View source for GO2-15-159, Final Safety Analysis Report, Amendment 63, Chapter 13 -Conduct of Operations

{{Adams
| number = ML15355A515
| issue date = 12/21/2015
| title = Final Safety Analysis Report, Amendment 63, Chapter 13 -Conduct of Operations
| author name = 
| author affiliation = Energy Northwest
| addressee name = 
| addressee affiliation = NRC/Document Control Desk, NRC/NRR
| docket = 05000397
| license number = 
| contact person = 
| case reference number = GO2-15-159
| package number = ML15356A148
| document type = Final Safety Analysis Report (FSAR)
| page count = 622
}}

=Text=
{{#Wiki_filter:COLUMBIA GENERATING STATION                                Amendment 63 FINAL SAFETY ANALYSIS REPORT                               December 2015 Chapter 13 CONDUCT OF OPERATIONS TABLE OF CONTENTS Section                                                                                           Page 13.1 ORGANIZATION STRUCTURE ..................................................... 13.1-1 13.1.1 MANAGEMENT AND TECHNICAL SUPPORT ORGANIZATION ...... 13.1-1 13.1.1.1 Technical Support for Operations ................................................. 13.1-1 13.1.1.2 Organizational Arrangement ....................................................... 13.1-2 13.1.1.3 Qualifications ......................................................................... 13.1-3 13.1.2 OPERATING ORGANIZATION.................................................... 13.1-3 13.1.2.1 Plant Organization ................................................................... 13.1-3 13.1.2.2 Plant Personnel Responsibilities and Authorities ............................... 13.1-3 13.1.2.2.1 Plant Management ................................................................. 13.1-3 13.1.2.2.2 Operations Supervision ........................................................... 13.1-4 13.1.2.2.3 Operating Shift Crew Supervision .............................................. 13.1-5 13.1.2.2.4 Shift Technical Advisor........................................................... 13.1-6 13.1.2.2.5 Licensed Operators ................................................................ 13.1-6 13.1.2.2.6 Nonlicensed Operators ............................................................ 13.1-6 13.1.2.2.7 Engineering Management ........................................................ 13.1-7 13.1.2.2.7.1 System Engineering Manager ................................................. 13.1-7 13.1.2.2.7.2 Design Engineering Manager ................................................. 13.1-8 13.1.2.2.7.3 Reactor/Fuels Manager ........................................................ 13.1-8 13.1.2.2.7.4 Technical Services Manager .................................................. 13.1-9 13.1.2.2.7.5 Plant Support Engineering Manager ......................................... 13.1-9 13.1.2.2.7.6 DELETED ....................................................................... 13.1-9 13.1.2.2.7.7 Equipment Reliability and Planning Supervisor ........................... 13.1-9 13.1.2.2.8 Nuclear Engineering Supervision ............................................... 13.1-9 13.1.2.2.9 Radiological Services Supervision .............................................. 13.1-9 13.1.2.2.10 Chemistry Supervision .......................................................... 13.1-10 13.1.2.2.11 Maintenance Supervision ....................................................... 13.1-10 13.1.2.2.12 Planning, Scheduling and Outage Supervision .............................. 13.1-10 13.1.2.2.13 Quality Supervision .............................................................. 13.1-10 13.1.2.3 Operating Shift Crews ............................................................... 13.1-11 13.1.2.3.1 Shift Crew Composition .......................................................... 13.1-11 13.1.2.3.2 Shift Responsibility for Radiation Protection ................................. 13.1-11 13.1.2.3.3 Shift Maintenance Support ....................................................... 13.1-11 13.1.2.3.4 Shift Fire Brigade .................................................................. 13.1-12 13.1.2.3.5 Shift Chemistry Support .......................................................... 13.1-12 LDCN-14-019, 14-037, 13-067                      13-i

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 Chapter 13 CONDUCT OF OPERATIONS TABLE OF CONTENTS (Continued)
Section                                                                                            Page 13.1.3 QUALIFICATIONS OF NUCLEAR PLANT PERSONNEL .................. 13.1-12 13.1.3.1 Plant Management ................................................................... 13.1-12 13.1.3.2 Operations Department .............................................................. 13.1-13 13.1.3.2.1 Operations Manager ............................................................... 13.1-13 13.1.3.2.2 Shift Manager ...................................................................... 13.1-13 13.1.3.2.3 Control Room Supervisor ........................................................ 13.1-13 13.1.3.2.4 Shift Technical Advisor........................................................... 13.1-14 13.1.3.2.5 Shift Support Supervisor ......................................................... 13.1-14 13.1.3.2.6 Reactor Operator ................................................................... 13.1-14 13.1.3.2.7 Equipment Operator ............................................................... 13.1-14 13.1.3.3 Engineering............................................................................ 13.1-14 13.1.3.3.1 Vice President Engineering, Assistant Vice President Engineering, System Engineering Manager, Design Engineering Manager, Reactor/Fuels Manager, Technical Services Manager, and Plant Support Engineering Manager 13.1-14 13.1.3.3.2 Engineering Supervisors .......................................................... 13.1-15 13.1.3.3.3 Fire Protection Engineer ......................................................... 13.1-15 13.1.3.4 Maintenance ........................................................................... 13.1-15 13.1.3.4.1 Maintenance Managers ........................................................... 13.1-15 13.1.3.4.2 Maintenance Supervisors ......................................................... 13.1-15 13.1.3.5 Chemsitry and Radiological Services ............................................. 13.1-16 13.1.3.5.1 Chemistry and Radiological Safety Manager ................................ 13.1-16 13.1.3.5.2 Radiological Services Manager ................................................. 13.1-16 13.1.3.5.3 Radiation Protection Manager ................................................... 13.1-16 13.1.3.5.4 Radiological Services Supervisors .............................................. 13.1-16 13.1.3.5.5 Chemistry Supervisors ............................................................ 13.1-17 13.1.3.6 DELETED ............................................................................ 13.1-17 13.1.3.7 Quality ................................................................................. 13.1-17 13.2 TRAINING ................................................................................. 13.2-1 13.2.1 PLANT STAFF TRAINING PROGRAM ......................................... 13.2-1 13.2.2 INITIAL AND CONTINUING TRAINING ...................................... 13.2-2 13.2.2.1 Licensed Operators .................................................................. 13.2-2 13.2.2.1.1 Initial Training ..................................................................... 13.2-2 LDCN-14-037, 13-067, 13-061, 15-008                 13-ii

COLUMBIA GENERATING STATION                                  Amendment 62 FINAL SAFETY ANALYSIS REPORT                                 December 2013 Chapter 13 CONDUCT OF OPERATIONS TABLE OF CONTENTS (Continued)
Section                                                                                           Page 13.2.2.1.2 Continuing Training ............................................................... 13.2-3 13.2.2.2 Nonlicensed Operator Training .................................................... 13.2-3 13.2.2.2.1 Initial Training ..................................................................... 13.2-3 13.2.2.2.2 Continuing Training Program ................................................... 13.2-4 13.2.2.3 Shift Technical Advisor Training .................................................. 13.2-4 13.2.2.3.1 Initial Training ..................................................................... 13.2-4 13.2.2.3.2 Continuing Training ............................................................... 13.2-4 13.2.2.4 Other Plant Personnel (Maintenance, Health Physics, Chemistry) .......... 13.2-5 13.2.2.4.1 Initial Training ..................................................................... 13.2-5 13.2.2.4.2 Continuing Training ............................................................... 13.2-5 13.2.2.5 Fire Brigade ........................................................................... 13.2-5 13.2.2.5.1 Initial and Continuing Training ................................................. 13.2-5 13.2.2.5.2 Offsite Fire Department .......................................................... 13.2-6 13.2.3 TRAINING PROGRAM EFFECTIVENESS...................................... 13.2-7 13.2.4 PLANT TRAINING RECORDS .................................................... 13.2-7 13.2.5 OTHER TRAINING DOCUMENTS ............................................... 13.2-7 13.3 EMERGENCY PLANNING ............................................................ 13.3-1 13.4 REVIEW AND AUDIT .................................................................. 13.4-1 13.4.1 ONSITE REVIEW ..................................................................... 13.4-1 13.4.2 INDEPENDENT REVIEW ........................................................... 13.4-1 13.4.3 AUDIT PROGRAM ................................................................... 13.4-2 13.5 PLANT PROCEDURES ................................................................. 13.5-1 13.5.1 ADMINISTRATIVE PROCEDURES .............................................. 13.5-1 13.5.1.1 Conformance With Regulatory Guide 1.33, Revision 2 ....................... 13.5-1 13.5.1.2 Preparation of Procedures .......................................................... 13.5-1 13.5.1.3 Procedures ............................................................................. 13.5-1 13.5.2 OPERATING AND MAINTENANCE PROCEDURES ........................ 13.5-2 13.5.2.1 Control Room Operating Procedures ............................................. 13.5-2 13.5.2.2 Other Procedures ..................................................................... 13.5-3 13.6 INDUSTRIAL SECURITY ............................................................. 13.6-1 13-iii

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 Chapter 13 CONDUCT OF OPERATIONS LIST OF TABLES Number                                 Title                                               Page 13.1-1      Minimum Shift Crew Composition ............................................... 13.1-19 LDCN-10-002                                13-iv

COLUMBIA GENERATING STATION  Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 13 CONDUCT OF OPERATIONS LIST OF FIGURES Number                                 Title 13.1-1      Energy Northwest Organization 13.1-2      Nuclear Generation Organization 13.1-3      Plant General Manager Organization 13.1-4      Operational Support Organization 13.1-5      (Deleted) 13.1-6      Vice President Engineering Organization 13.1-7      Quality Organization 13.1-8      (Deleted) 13.1-9      Operations Organization 13.1-10     Operations Crew 13.1-11     Radiological Services Organization 13.1-12     Chemistry Organization 13.1-13     Plant Maintenance Organization LDCN-14-019                                13-v

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 Chapter 13 CONDUCT OF OPERATIONS 13.1     ORGANIZATION STRUCTURE The organizational structure of Energy Northwest and the line of responsibility for the operation of Columbia Generating Station (CGS) is in accordance with established administrative and quality standards that apply to this operation. The applicable organization charts are shown in Figures 13.1-1 through 13.1-13.
13.1.1       MANAGEMENT AND TECHNICAL SUPPORT ORGANIZATION Energy Northwest is a municipal corporation and a joint operating agency of the State of Washington. The management and control of Energy Northwest is vested in the Executive Board.
The Executive Board consists of five members of the Energy Northwest Board of Directors and six outside directors. Three outside directors are selected by the Board of Directors, and three directors are appointed by the Governor of the State of Washington.
The full Board of Directors has members representing each of Energy Northwests member utilities, and has the authority to select the inside members of the Executive Board and to terminate existing projects or authorize new projects.
Certain responsibilities for day-to-day management of Energy Northwest have been delegated to the Chief Executive Officer (the chief administrative officer).
The staff of Energy Northwest includes senior management level positions, which are responsible to the Chief Executive Officer for performance of specialized work by their respective groups. See Figure 13.1-1 for an organization chart. However, as specified in Technical Specifications, Section 5.2.1, the Chief Executive Officer retains corporate responsibility for overall plant nuclear safety.
13.1.1.1        Technical Support for Operations Technical support for the nuclear organization is the responsibility of the Chief Nuclear Officer, Plant General Manager, Vice President, Engineering, and Vice President, Operations.
The Plant General Manager is responsible for the safe, reliable, and efficient operation and maintenance of CGS and for providing major services which support plant operation.
LDCN-14-046                                      13.1-1

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 Reporting to the Chief Nuclear Officer includes the Vice President, Operations, Vice President, Engineering, and the Quality Manager. The Plant General Manager reports to the Vice President, Operations.
Reporting to the Chief Nuclear Officer are departments that provide support to CGS in the areas of Operations, Engineering, and Quality (see Figure 13.1-2).
Reporting to the Vice President, Engineering are departments which provide technical support in the areas of reactor fuels and engineering.
Reporting to the Vice President, Operations, are the Plant General Manager, the Emergency Services Manager, and the Training Manager. Security reports to the Emergency Services Manager. (see Figure 13.1-4).
The Quality Managers responsibilities are described in the Energy Northwest Operational Quality Assurance Program Description (OQAPD), EN-QA-004. An organization chart is provided in Figure 13.1-7.
The Vice President, Engineering is responsible for design control of all authorized plant modifications, technical expertise in the fundamental engineering disciplines such as mechanical, electrical, civil, chemical, fuels, as well as specialty areas such as materials, welding, and inservice inspection engineering. In addition, the Vice President, Engineering is responsible for providing technical support in the area of system engineering. An organization chart for Engineering is shown in Figure 13.1-6.
13.1.1.2         Organizational Arrangement Figures 13.1-1 through 13.1-7 provide the current corporate structure as applicable to CGS support organizations. The number of personnel to be assigned to each of the working level organizations will be determined based on workload and need for pertinent expertise. If the need arises, qualified outside contractors will be used to support the Energy Northwest staff.
LDCN-14-019, 14-046, 15-008                   13.1-2

COLUMBIA GENERATING STATION                            Amendment 62 FINAL SAFETY ANALYSIS REPORT                           December 2013 13.1.1.3       Qualifications Qualification requirements for key technical support personnel who fulfill the responsibilities identified in Section 13.1.1.1 shall meet the criteria of Regulatory Guide 1.8, Revision 1, 1977 (see the OQAPD). The personnel qualification and training programs are under continuing review and modification to reflect the changes following the TMI accident. The Vice President Engineering meets the definition and qualifications of Engineer in Charge.
Any Vice President or Manager listed in Section 13.1.1.1 may authorize deviations from the qualification requirements for subordinate positions when, in their judgment, the combined education, experience, and managerial competency of a particular individual are sufficient to ensure adequate performance of assigned responsibilities. Such exceptions will be documented in writing and will not be used as a means to degrade the overall qualifications of the support staff. Deviations are not authorized for those positions whose qualifications are described in the Technical Specifications and the OQAPD.
13.1.2      OPERATING ORGANIZATION 13.1.2.1       Plant Organization This section describes the structure, functions, and responsibilities of the onsite organization established to operate and maintain CGS. Figures 13.1-9 through 13.1-13 show the plant organizations that directly operate and maintain CGS. The principal departments that function directly under the supervision of the Plant General Manager are: Operations, Maintenance, Radiological Services, and Chemistry (see Figure 13.1-3).
The Security Force Lieutenant is responsible to the Plant General Manager for day-to-day operation of the Plant Security Program and receives functional supervision from Operations Support management.
Position titles, NRC licenses required, and lines of functional reporting, as well as direct lines of communications, are indicated on the organization charts.
13.1.2.2       Plant Personnel Responsibilities and Authorities 13.1.2.2.1       Plant Management The Plant General Manager has direct responsibility and authority for all plant activities. The Plant General Manager reports directly to the Vice President, Operations.
The Plant General Manager has the responsibility for management of the following plant departments: Operations, Chemistry, Radiological Services, Planning, Scheduling and Outage, and Maintenance.
LDCN-12-004                                   13.1-3

COLUMBIA GENERATING STATION                            Amendment 62 FINAL SAFETY ANALYSIS REPORT                           December 2013 A Security Force Lieutenant exercises supervision and authority over the onsite security personnel. The Security Force Lieutenant reports to the Plant General Manager or the designated representative on day shifts and to the Shift Manager during other than normal working hours (i.e., backshifts, weekends, and holidays).
In the event of incapacitation of key plant personnel or unexpected contingencies of a temporary nature, the line of succession of authority and responsibility for all plant activities is as follows:
: a. Plant General Manager,
: b. Operations Manager,
: c. One of the Assistant Operations Managers (see below),
: d. Duty Shift Manager.
13.1.2.2.2      Operations Supervision Operations is under the direction of the Operations Manager. The Operations Manager is responsible for overall plant operation. The Operations Manager directs and manages the activities of operations to ensure safe plant operation and control of plant systems in compliance with licensing documents.
The Operations Manager is responsible for being cognizant of and complying with the OQAPD.
The Operations Manager is responsible for the day-to-day routine as well as the abnormal or emergency operating situations that may arise. The Operations Manager is responsible to see that all operations are carried out in a safe, efficient manner and that the plant is operated in strict conformance to the Operating License, Technical Specifications, and in accordance with approved written procedures. Additionally, the Operations Manager is responsible for operating personnel schedules, development, and periodic review of plant operating procedures and instructions, and the preparation of operating records and reports.
The Operations Crew, Operations Support, Operations Work Control and Operations Training Managers (hereinafter referred to collectively as Assistant Operations Managers (AOMS))
support and assist the Operations Manager in the performance of these duties. The Operations Crew Manager is responsible to the Operations Manager for the immediate supervision of the Operations staff that supports work team and outage activities, and as such, he receives direction from the Operations Manager for the day-to-day routine and supervises implementation. The Operations Support Manager is responsible to the Operations Manager for the immediate supervision of the Operations staff that supplies miscellaneous support to the Operations Department.
LDCN-13-040                                     13.1-4

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 The AOMs may be required to maintain a current Senior Reactor Operator (SRO) license.
During periods of transition such as promotion, the individual with a current SRO, either the Operations Manager or one of the AOM will have the responsibility for immediate supervision of the Operations staff. In either case, the individual with the SRO may only be relieved by another individual possessing a current SRO. The Operations Manager will designate one of the assistants to assume total responsibility for the Operations Managers duties (as described in this section) during periods when the Operations Manager is temporarily absent from the plant. See Figure 13.1-9 for an organization chart of the Operations Department.
The plant Fire Marshall assists the Operations Manager in the implementation of the Fire Protection Program. Responsibilities include ensuring that the fire protection systems and components are maintained and that the Fire Brigade is adequately trained and staffed. More detailed information is contained in Section 13.2.2.5.2.
13.1.2.2.3      Operating Shift Crew Supervision Within the Operations Department are a minimum of five shift crews during normal operations. In some situations, such as refueling outages, these may be reduced to four shift crews. Plant management and technical support will be present or on call at all times to provide advice to the shift personnel.
The Shift Manager holds an SRO license and is directly responsible to the Operations Manager (see Figure 13.1-10 for typical Operations Crew organization chart). The Shift Manager is in charge of all plant operations on shift and is directly in charge of and responsible for the shift crew assigned to his specific shift. The Shift Manager has the authority to institute immediate action in any given situation to shut the plant down, or eliminate difficulties to preclude violation of the Operating License or Technical Specifications, or to avert possible injury or undue radiation exposure of personnel. Additionally, the Shift Manager may at times direct the activities of other personnel during tasks such as backshift maintenance, radiation protection, chemistry control, and security implementation. The Shift Manager also keeps plant management appraised of situations that may affect plant safety and/or constitute a hazard to the general public. During other than normal working hours, the Shift Manager assumes responsibility for all plant operations in the absence of senior plant management personnel.
The Control Room Supervisor holds an SRO license and assists the Shift Manager in the performance of duties and assumes those duties during periods when the Shift Manager is unavailable. The Control Room Supervisor is responsible for supervising the activities of the Control Room Reactor Operators and other assigned personnel (i.e., equipment operators and maintenance support personnel) required to operate the plant safely and efficiently. The Control Room Supervisor is directly responsible to the Shift Manager.
LDCN-14-019                                    13.1-5

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 If stationed, the Shift Support Supervisor assists the Shift Manager in the performance of his duties. The Shift Support Supervisor is responsible for the supervision and direction of personnel assigned to perform balance-of-plant (BOP) operating functions such as operations of makeup water treatment system, radwaste processing systems, and other plant support systems.
The individual is responsible for performing administrative duties as assigned.
All core alterations are observed and directly supervised by either a licensed SRO, or licensed SRO limited to fuel handling, who has no concurrent responsibilities during the performance of the core alterations.
13.1.2.2.4     Shift Technical Advisor A Shift Technical Advisor (STA) qualified individual provides engineering expertise on shift pursuant to safe and efficient operation of the plant. The STA function may be staffed by a dedicated individual (licensed or non-licensed), or by an individual filling a dual role as the Control Room Supervisor, Shift Manager or Shift Support Supervisor. The STA qualified individual monitors reactor core operations, and core management and reactivity controls. The STA normally reports to the Shift Manager.
13.1.2.2.5      Licensed Operators In addition to the licensed supervisors listed above, there are a minimum of two reactor operators on each shift. The reactor operator (RO) holds a reactor operator or senior reactor operator license and is responsible to the Control Room Supervisor for the safe and efficient operation of the plant from the main control room. The RO follows approved procedures in performing work and is responsible for taking the immediate action required to maintain or bring the plant to a safe condition during abnormal and/or emergency conditions. However, if a particular situation is not covered by a procedure, the individual may seek advice from the Control Room Supervisor, or if the situation is critical, may use his or her own judgment to prevent damage to equipment, injury to personnel, or undue radiation exposure of plant personnel and the general public. The RO directs and supports the activities of other operators in the performance of their duties and works cooperatively with all plant service groups that interface with plant operation.
13.1.2.2.6      Nonlicensed Operators The equipment operators (EO) are responsible to the Control Room Supervisor or Shift Support Supervisor for assisting in the plant operation and performing work assignments from local control stations and all other defined areas outside of the central control room. The EO follows approved procedures in doing work and does not deviate from those procedures except as authorized. The EO performs assigned routine inspections and manipulates equipment without close supervision. The EO also performs special assignments as directed.
LDCN-10-002                                    13.1-6

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 13.1.2.2.7        Engineering Management Reporting to the Vice President, Engineering is the Assistant Vice President Engineering, the System Engineering Manager, the Technical Services Manager, the Design Engineering Manager, the Plant Support Engineering Manager, and the Reactor Fuels Manager.
They are responsible for developing and implementing plant programs and procedures which provide proper management control in the above areas and thus ensure compliance with the conditions of the operating license and proper plant safety. They interface with other support organizations to support plant operations.
The engineering organizations are responsible for being cognizant of and complying with the Operational Quality Assurance Program Description.
13.1.2.2.7.1 System Engineering Manager. The System Engineering Manager is responsible for long-term management of and the health and reliability of systems and components, overall direction of the system engineering program in support of plant operation, maintenance, and chemistry, and developing long range plans for system improvement and performance in the areas of NSSS systems, control/electrical systems, and BOP systems.
The System Engineering Manager is responsible for the development, implementation, and execution of programs to monitor system performance, to conduct inspections, and to perform specialized testing. The objective is to identify potential component degradation, minimize threats to successful operation of systems and the plant, and to identify opportunities for improvement.
The System Engineering Manager is the primary interface with the Design Engineering Manager, Plant Support Engineering Manager, and Technical Services Manager in support of maintaining plant compliance with design and licensing requirements.
The System Engineering Manager is responsible for implementing performance monitoring of plant systems and critical plant programmatic processes. This includes providing recommendations to plant management for implementation of new program requirements, performing periodic assessments of existing programs, and recommending component or system improvements. The System Engineering Manager is responsible for daily plant support, responding to emergent issues, operability assessments, and providing troubleshooting expertise to operations and maintenance.
Reporting to the System Engineering Manager are Equipment Reliability and Planning Supervisor, and the System Engineering Supervisors for nuclear steam supply systems (NSSS),
BOP systems, and instrument and control and electrical systems. System Engineering Supervisors direct the activities of the System Engineering staff in support of plant operation in LDCN-14-019, 14-037                           13.1-7

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 the functional areas of mechanical engineering, instrumentation and control engineering, and electrical engineering. Activities include initiating engineering design changes, making recommendations for improved operation, and providing operating and maintenance support for instrumentation and control systems, mechanical systems, electrical systems, plant water systems, and waste handling systems.
13.1.2.2.7.2 Design Engineering Manager. The Design Engineering Manager is responsible to assist System Engineering for daily plant support, responding to emerging issues, and operability assessments. The Design Engineering Manager is responsible for maintenance of the plant design basis, performance of plant design changes, and design and drafting. This includes non-modification design related activities.
Reporting to the Design Engineering Manager are the Mechanical Design Supervisor, the Civil/Stress Design Supervisor, the Electrical Design Supervisor, and the Instrumentation &
Control Design Supervisor.
13.1.2.2.7.3 Reactor Fuels Manager. The Reactor Fuels Manager is responsible for fuel design, overall management of the reactor core, and monitoring of core parameters.
The Reactor Fuels Manager is responsible for providing technical support to Operations in management of refueling floor activities, support to Maintenance in resolving refueling equipment problems, providing technical resources for resolution of vessel hardware problems and concerns with interfacing systems which influence or monitor core reactivity, for maintaining involvement in applicable industry initiatives affecting core reactivity issues and new developments in core operation, providing recommendations to plant management on operating strategies in support of normal and off-normal operating situations, and planned shutdown and startup activities.
The Reactor Fuels Manager ensures sound fuel design philosophy is followed, fuel designs provide no unreasonable challenges to safe plant operation, and probabilistic safety assessments (PSA) are performed for CGS.
Reporting to the Reactor Fuels Manager are the Fuel Design/Reactor Engineering Supervisor, and the Safety Analysis/PSA Supervisor.
The Fuel Design/Reactor Engineering Supervisor and staff are responsible for performing periodic core physics evaluations to monitor the operation, burnup, and thermal/hydraulic performance of the reactor core. They provide and maintain plant operating curves and reactivity data for use by shift operation personnel and are responsible for the onsite accountability of nuclear fuel and special nuclear materials. The Fuel Design/Reactor LDCN-14-019                                    13.1-8

COLUMBIA GENERATING STATION                          Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 Engineering Supervisor and staff are responsible for core design, fuel planning, licensing support (e.g., COLR, accident/transient analysis), and analytical work necessary to support cycle operation (e.g., control rod pattern recommendations).
The Safety Analysis/PSA Supervisor and staff provide probabilistic safety assessments for CGS. They provide analytical support for radiation dose analysis, shielding, equipment qualification, ODCM, emergency procedures and primary and secondary containment analyses.
13.1.2.2.7.4 Technical Services Manager is responsible for plant, code, component programs.
Reporting to the Technical Services Manager are Plant Programs Supervisor, Code Programs Supervisor, and Plant Components Supervisor. The Technical Services personnel are responsible for Equipment Qualification (EQ), Fire Protection (FP), In Service Test (IST),
Thermal Performance (TP), ASME Section XI, ISI, BWRVIP, welding, Appendix J Local Leak Rate Testing (LLRT), pump, valve (AOVs, MOVs, and reliefs), large motor, circuit breaker, relay, and Component Condition Monitoring programs, including vibration analysis, oil analysis, and thermography.
13.1.2.2.7.5 Plant Support Engineering Manager is responsible for supporting the System Engineering Manager and the plant in responding to emergent issues, operability assessments, providing troubleshooting expertise to operations and maintenance and performing engineering needed for special procurement. Reporting to the Plant Support Engineering Manager are the engineering fix-it-now (EFIN) Supervisor, the Minor Modifications Supervisor and the Procurement Engineering Supervisor.
13.1.2.2.7.6 DELETED.
13.1.2.2.7.7 Equipment Reliability and Planning Supervisor is responsible for interface with System and Design Engineering managers and the Asset Management department for Equipment Reliability Initiatives and planning to support the long range plan. The Equipment Reliability and Planning Supervisor is also responsible for Maintenance Rule (MRule) implementation.
13.1.2.2.8        Nuclear Engineering Supervision See Section 13.1.2.2.7.3.
13.1.2.2.9        Radiological Services Supervision See Section 12.5.1 for a description of duties, responsibilities, and reporting relationships. See Figure 13.1-11 for an organization chart.
LDCN-14-019, 14-037                            13.1-9

COLUMBIA GENERATING STATION                          Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 13.1.2.2.10       Chemistry Supervision Chemistry is under the direction of the Chemistry and Radiological Safety Manager, who reports to the Plant General Manager. The group provides plant oversight for system chemistry optimization and control, gaseous, and liquid effluent releases, radwaste processing and chemical control, the Offsite Dose Calculation Manual, the Radiological Environmental Monitoring Program (REMP), and Radiological Effluent Report. See Figure 13.1-12 for an organization chart.
13.1.2.2.11       Maintenance Supervision Maintenance is under the direction of the Maintenance Manager. The Maintenance Manager is responsible for the Maintenance Program and for the development and implementation of maintenance processes and procedures which will ensure the safe and reliable operation of plant equipment. The Maintenance Manager is responsible for primary component level troubleshooting. The Maintenance Manager reports to the Plant General Manager. The organization is shown in Figure 13.1-13.
The Maintenance Manager, with the assistance of direct managerial reports, manages the following activities: Reactor and Major Maintenance, Maintenance Services, FIN Component Group, Mechanical Component Group, I & C Component Group, Electrical Component Group, and other teams that are formed to address specific maintenance or business needs.
Shops and/or teams may be combined as long as supervisory qualifications are maintained as described in Section 13.1.3.4.
All plant modifications are accomplished through this department either directly or through the actions of the Site Support Services contractor. Engineering, Training, and Support Services, as discussed in Section 13.1.1.1, provide support for this department. Other support is provided when needed in the form of vendor representatives for technical guidance on maintenance of major components of the plant.
Maintenance Supervisors are responsible for the day-to-day implementation of the Maintenance Program. They are responsible for maintaining plant electrical, instrumentation, and mechanical systems through preventive and corrective maintenance and surveillance programs.
13.1.2.2.12       Planning, Scheduling and Outage Supervision This organization is responsible for managing the work process and ensuring work schedule consistency. It is also responsible for the development and oversight of outage preparation and implementation and coordination of outage work.
13.1.2.2.13       Quality Supervision A description of duties and responsibilities for the Quality organization is contained in the OQAPD.
LDCN-13-061, 15-008                           13.1-10

COLUMBIA GENERATING STATION                            Amendment 61 FINAL SAFETY ANALYSIS REPORT                           December 2011 13.1.2.3       Operating Shift Crews 13.1.2.3.1      Shift Crew Composition Shift coverage is provided by using a rotating shift schedule depending on operating needs.
The schedules are based on a nominal 40-hr work week and shifts are normally of 8 or 12 hr duration (excluding shift turnover time).
During normal operations, a minimum of five crews provide 24 hr/day, 7 day/week coverage.
Table 13.1-1, as well as the Technical Specifications and the Emergency Plan, identify the minimum number and type of licensed and unlicensed personnel required to be onsite.
For those operations that involve core alterations, direct supervision of all fuel movements is provided by an individual holding an SRO license. This person has no other concurrent responsibilities during this assignment.
It is CGSs policy to maintain an adequate number of personnel in the Shift Manager, Control Room Supervisor, Shift Support Supervisor, STA (if required), Control Room Reactor Operator, and Equipment Operator positions such that the use of overtime is not routinely required to compensate for inadequate staffing.
13.1.2.3.2      Shift Responsibility for Radiation Protection A minimum of one Health Physics Technician is assigned to each operating shift to provide radiological surveillance/control (see Table 13.1-1).
All shift personnel are instructed in the fundamentals of health physics such as implementing radiation protection procedures, radiation and contamination surveys, use of protective barriers and signs, use of protective clothing and breathing apparatus, radiation monitoring, and accumulated dose.
Shift personnel are responsible for immediately informing the on-duty Shift Manager if conditions develop that exceed or are likely to exceed preestablished radiation levels or exposure limits or if they believe that unsafe or hazardous conditions exist. The Shift Manager will evaluate the situation and if a radiological condition exists that warrants attention and investigation, the appropriate Health Physics personnel will be called for assistance.
13.1.2.3.3      Shift Maintenance Support Craftsmen and technicians, as required, are available to provide maintenance support and surveillance testing in the areas of instrumentation and controls and mechanical and electrical equipment.
LDCN-10-002                                    13.1-11

COLUMBIA GENERATING STATION                            Amendment 62 FINAL SAFETY ANALYSIS REPORT                           December 2013 13.1.2.3.4      Shift Fire Brigade A Shift Fire Brigade, consisting of a minimum of five members of the nominal shift complement, shall have advanced fire training and be equipped for fire fighting. This select group on each operating shift will have primary response capabilities and will respond to emergencies involving fire and/or emergencies where life threatening danger exists.
The brigade shall not include the minimum shift crew complement required to safely shut down the unit. At a minimum the brigade leader and two brigade members shall have sufficient knowledge of plant fire safe shutdown systems. The balance of the fire brigade shall be composed of Fire Brigade trained support personnel. See Section 13.2.2.5 for the qualification requirements for fire brigade members.
13.1.2.3.5      Shift Chemistry Support At least one qualified chemistry technician is assigned to each operating shift for the purpose of providing chemistry support in the area of chemical surveillances while the plant is in Modes 1, 2, or 3.
13.1.3      QUALIFICATIONS OF NUCLEAR PLANT PERSONNEL The minimum educational and experience qualifications for the onsite plant personnel are based on Regulatory Guide 1.8, Revision 1-R, 1977. If an individual who does not meet the minimum qualification criteria is placed in a discipline, it will be specifically pointed out and justification or explanation provided. See Section 13.1.1.3. Personnel qualification and training programs are under continual review and modification to reflect the changes following TMI. The minimum qualification requirements identified in Section 13.1.3.1 will be revised accordingly. The licensed ROs and SROs meet or exceed the minimum qualifications of the supplemental requirements specified in Sections A and C of Enclosure 1 of the March 28, 1980, NRC letter to all licensees, as modified by NUREG-0737, November 1980, Clarification of TMI Action Plan Requirements, Enclosure 1, Section 1.A.2.1, Immediate Upgrading of Reactor Operator and Senior Reactor Operator Training and Qualifications.
13.1.3.1       Plant Management The Plant General Manager shall have 10 years of responsible power plant experience of which a minimum of 3 years shall be nuclear power plant experience. A maximum of 4 years of the remaining 7 years of experience may be fulfilled by academic training on a one-for-one time basis. This academic training shall be in an engineering or scientific field generally associated with power production. The Plant General Manager shall have acquired the experience and training normally required for examination by the NRC for an SRO license, whether or not the LDCN-13-040                                  13.1-12

COLUMBIA GENERATING STATION                          Amendment 62 FINAL SAFETY ANALYSIS REPORT                        December 2013 examination is taken. The Plant General Manager should have a recognized baccalaureate or higher degree in an engineering or scientific field generally associated with power production.
13.1.3.2       Operations Department 13.1.3.2.1      Operations Manager The Operations Manager shall have a minimum of 8 years of responsible power plant experience of which a minimum of 3 years shall be nuclear power plant experience.
A maximum of 2 years of the remaining 5 years of power plant experience may be fulfilled by satisfactory completion of academic or related technical training on a one-for-one time basis.
The Operations Crew Manager shall have qualifications similar to those of the Operations Manager. The Operations Manager or Operations Crew Manager shall hold an SRO license.
13.1.3.2.2      Shift Manager The Shift Manager shall have a minimum of a high school diploma or equivalent and 4 years of responsible power plant experience of which a minimum of 1 year shall be nuclear power plant experience. At least 6 months of nuclear plant experience will be at CGS. A maximum of 2 years of power plant experience may be fulfilled by academic or related technical training on a one-for-one time basis. The Shift Manager shall hold an SRO license. For NRC license eligibility guidelines (experience, training, and education) for an SRO license, see NUREG-1021, section ES-202.
13.1.3.2.3      Control Room Supervisor The Control Room Supervisor shall have a minimum of a high school diploma or equivalent and 4 years of responsible power plant experience, of which a minimum of 1 year shall be nuclear power plant experience. At least 6 months of nuclear plant experience will be at CGS.
A maximum of 2 years of power plant experience may be fulfilled by academic or related technical training on a one-for-one time basis. The Control Room Supervisor shall hold an SRO license. For NRC license eligibility guidelines (experience, training, and education) for an SRO license, see NUREG-1021, section ES-202.
LDCN-13-040                                    13.1-13

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 13.1.3.2.4        Shift Technical Advisor The STA possesses a bachelors degree in engineering or science with sufficient courses to provide a sound background for understanding the design and operation of a BWR power plant. The STA shall have a minimum of 2 years of power plant experience with at least 6 months of nuclear plant experience at CGS.
13.1.3.2.5        Shift Support Supervisor The Shift Support Supervisor shall have a high school diploma or equivalent. The individual shall have 4 years of power plant experience of which 1 year shall be nuclear power plant experience. This position does not require an RO license.
13.1.3.2.6        Reactor Operator The RO shall have a minimum of a high school diploma or equivalent and two years of power plant experience of which a minimum of 1 year shall be nuclear power plant experience. At least 6 months of the nuclear experience shall be at CGS unless the incumbent has an equal amount of nuclear experience acquired on a similar unit. The individual shall hold an RO license. For NRC license eligibility guidelines (experience, training, and education) for an RO license, see NUREG-1021, section ES-202.
13.1.3.2.7        Equipment Operator Before assuming the full responsibilities of the position in the plant, the Equipment Operator shall have a minimum of a high school diploma or equivalent and shall have completed the Energy Northwest training program for Equipment Operators. This position does not require an RO license.
13.1.3.3         Engineering 13.1.3.3.1        Vice President Engineering, Assistant Vice President Engineering, System Engineering Manager, Design Engineering Manager, Reactor Fuels Manager, Technical Services Manager, and Plant Support Engineering Manager Vice President Engineering, Assistant Vice President Engineering, System Engineering Manager, Design Engineering Manager, Reactor Fuels Manager, Technical Services Manager, and Plant Support Engineering Manager shall have a minimum of 8 years of related technical experience of which 1 year should be nuclear power plant experience. A maximum of 4 years of the remaining 7 years may be fulfilled by satisfactory completion of academic training.
LDCN-14-037, 15-008                           13.1-14

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 A bachelor of science degree in engineering or physical sciences suitable to the nuclear power field is required. The Reactor Fuels Manager shall have a minimum of 2 years of experience in areas such as reactor/core physics, measurements, heat transfer, and physics testing. The Engineer in Charge described in Section 13.1.1.3 shall have (in addition to any applicable requirements listed above) a minimum of a Bachelors Degree in Engineering or the Physical Sciences and have a minimum of three years of professional level experience in nuclear services, nuclear plant operation, or nuclear engineering, and the necessary overall nuclear background to determine when to call consultants and contractors for dealing with complex problems beyond the scope of owner-organization expertise.
13.1.3.3.2      Engineering Supervisors The Engineering Supervisors in System Engineering, Design Engineering, Plant Support Engineering, and Technical Services shall have a minimum of 5 years of related technical experience of which 1 year shall be nuclear power plant experience. A maximum of 4 years of the required 5 years may be fulfilled by satisfactory completion of academic training. The Reactor Engineering/Fuel Design Supervisor(s) shall have a minimum of 2 years experience in areas such as reactor/core physics, measurements, heat transfer, and physics testing. A Bachelor of Science degree in engineering or physical sciences or the equivalent is required.
13.1.3.3.3      Fire Protection Engineer The qualified Fire Protection Engineer meets the qualifications of member grade in the Society of Fire Protection Engineers or is a registered Fire Protection Engineer.
13.1.3.4       Maintenance 13.1.3.4.1      Maintenance Managers The Maintenance Manager shall have a minimum of 7 years of responsible power plant experience or applicable industrial experience, a minimum of 1 year of which shall be nuclear power plant experience. A maximum of 2 years of the remaining 6 years of power plant or industrial experience may be fulfilled by satisfactory completion of academic or related technical training on a one-for-one time basis. He further should have nondestructive testing familiarity, craft knowledge, and an understanding of electrical, pressure vessel, and piping codes.
13.1.3.4.2      Maintenance Supervisors Maintenance Supervisors shall each have a high school diploma or equivalent and should have a minimum of 4 years experience in the craft or discipline that they supervise in accordance with ANSI 18.1, 1971. In cases where a supervisor does not have a minimum of 4 years of 13.1-15

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 experience in the discipline of the craft being supervised, technical direction for the craft will be given by a qualified supervisor.
13.1.3.5       Chemistry and Radiological Services 13.1.3.5.1      Chemistry and Radiological Safety Manager The Chemistry and Radiological Safety Manager shall, in accordance with ANSI N18.1-1971, have a minimum of 8 years in responsible positions, of which 1 year shall be nuclear power plant experience. A maximum of 4 years of the remaining seven years of experience should be fulfilled by satisfactory completion of academic training.
13.1.3.5.2      Radiological Services Manager The Radiological Services Manager shall meet the qualification requirements of ANSI N18.1-1971, section 4.2.4. This includes a minimum of 8 years of responsible positions, of which a minimum of 1 year shall be nuclear power plant experience.
A maximum of 4 years of the remaining 7 years of experience should be fulfilled by satisfactory completion of academic training.
13.1.3.5.3      Radiation Protection Manager The Radiological Services Manager functions as the Radiation Protection Manager and shall, at a minimum, meet the qualifications defined in Regulatory Guide 1.8, Revision 1-R, May 1977.
This individual shall have a bachelors degree or the equivalent in a science or engineering subject including some formal training in radiation protection. The Radiation Protection Manager shall have at least 5 years of professional experience in applied radiation protection.
A masters degree may be considered equivalent to 1 year of professional experience and a doctors degree may be considered equivalent to 2 years of professional experience where course work related to radiation protection is involved. At least 3 years of this professional experience shall be in applied radiation protection work in a nuclear facility dealing with radiological problems similar to those encountered in nuclear power stations, preferably in an actual nuclear power station. The Radiation Protection Manager is an assigned duty and not a defined position in the organization (see Section 12.5.1).
13.1.3.5.4      Radiological Services Supervisors Radiological Services Supervisors shall, in accordance with ANSI 18.1-1971, have a high school diploma or equivalent and a minimum of 4 years of related experience.
LDCN-13-061                                   13.1-16

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 13.1.3.5.5     Chemistry Supervisors Chemistry Supervisors who are responsible for directing the actions of technicians shall, in accordance with ANSI N18.1-1971, have a high school diploma or equivalent and a minimum of 4 years related experience.
1.3.1.3.6      Deleted 13.1.3.7      Quality See the OQAPD for a description of qualification requirements.
LDCN-13-061                                13.1-17

COLUMBIA GENERATING STATION                            Amendment 61 FINAL SAFETY ANALYSIS REPORT                           December 2011 Table 13.1-1 Minimum Shift Crew Composition Minimum Number of Personnel per Position per Shift Position Titleb     Type of License          Modes 1, 2, and 3c          Modes 4 and 5c SM                 SRO                             1                      1 CRS                SRO                             1                      None RO                 RO                              2                      1 EO                 None                            2                      1 STA                None                          1d,e                     Notef HP                 None                            1                      1 a
This table represents the minimum number of personnel required to fill any particular position. It does not provide a total staffing level for an operating shift. Additional staff for safe shutdown and fire brigade must also be satisfied.
Technical Specifications paragraph 5.3.2 was added in LAR 182 to clarify compliance with 10 CFR 55.53 requirements. Energy Northwest may take credit for more than the minimum number of watchstanders required by 10 CFR 50.54(m). However, fulfillment of 10 CFR 55.53(e) and (f) requirements of active performance of operator or senior operator functions requires that Energy Northwest implement administrative controls to assure functions and duties are divided and rotated in a manner which provides each watchstander meaningful and significant opportunity to maintain proficiency in the performance of the functions of an RO and/or SRO.
b Position title abbreviations are as follows:
SM      Shift Manager with SRO on Columbia Generating Station CRS     Control Room Supervisor with SRO on Columbia Generating Station RO      Reactor Operator with RO or SRO on Columbia Generating Station EO      Equipment Operator STA     Shift Technical Advisor HP      Health Physics Technician 13.1-19

COLUMBIA GENERATING STATION                         Amendment 61 FINAL SAFETY ANALYSIS REPORT                       December 2011 Table 13.1-1 Minimum Shift Crew Composition (Continued) c Modes
: 1.      Power operation
: 2.      Startup
: 3.      Hot shutdown
: 4.      Cold shutdown
: 5.      Refueling d
An STA qualified individual shall be on-shift in Modes 1, 2 and 3. The STA qualified individual may be a dedicated individual (licensed or non-licensed) or an individual filling a dual role position as the Control Room Supervisor, Shift Manager or Shift Support Supervisor.
e When the STA qualified individual is filling a dual role as the Control Room Supervisor or Shift Manager, another SRO is required to be on-shift to provide independent oversight and emergency response support to the Shift Manager.
f Refer to the Emergency Plan for emergency response staffing requirements in Modes 4, 5.
The shift crew composition may be one less than the minimum requirements for a period not to exceed 2 hr to accommodate unexpected absence of on-duty shift crew members provided immediate action is taken to restore the shift crew composition to within the minimum requirements. This provision does not permit any shift crew position to be unmanned on shift change due to an oncoming shift crewman being late or absent.
During any absence of the Shift Manager from the control room while the unit is in Operational Condition 1, 2, or 3, an Operations Department individual with a valid SRO license shall be designated to assume the control room command function. During any absence of the Shift Manager from the control room while the unit is in Operational Condition 4 or 5, an individual with a valid SRO license or RO license shall be designated to assume the control room command function.
13.1-20

Amendment 63 December 2015 Chief Executive Officer Chief Nuclear Officer Quality Manager Legend:
Administrative and Functional Reporting Communications Lines Energy Northwest Organization Columbia Generating Station Final Safety Analysis Report Draw. No. 970187.02     Rev. Figure 13.1-1 Form No. 960690FH LDCN-14-011, 14-019, 14-046

Amendment 63 December 2015 Chief Nuclear Officer Quality              Vice President                    Vice President Manager                Operations                         Engineering Nuclear Generation Organization Columbia Generating Station Final Safety Analysis Report Draw. No. 970187.03    Rev.        Figure 13.1-2 Form No. 960690FH LDCN-14-019, 14-046

Amendment 63 December 2015 Plant General Manager Chemistry and                                                            Planning Operations              Maintenance Radiological              Manager                  Manager            Scheduling, Safety                                                            and Outage Manager**                                                             Manager Radiological Services Manager*
Security Force Lieutenant
* Also fulfills Radiation Protection Manager function
                  ** Also fulfills the Chemistry Manager function Plant General Manager Organization Columbia Generating Station Final Safety Analysis Report Draw. No. 970187.41      Rev. 2      Figure 13.1-3 Form No. 960690FH LDCN-13-061

Amendment 63 December 2015 Vice President Operations Emergency Services           Plant                      Training Manager                General                     Manager Manager Operational Support Organization Columbia Generating Station Final Safety Analysis Report Draw. No. 970187.05      Rev. 4    Figure 13.1-4 Form No. 960690FH LDCN-14-019,15-008

Amendment 63 December 2015 DELETED Training Organization Columbia Generating Station Final Safety Analysis Report Draw. No. 970187.06       Rev. 1   Figure 13.1-5 Form No. 960690FH LDCN-14-019

Amendment 63 December 2015 Vice President Engineering Assistant Vice President Engineering Design                      Reactor                      Plant Support Engineering                     Fuels                        Engineering Manager                     Manager                           Manager Technical                      System Services                     Engineering Manager                       Manager Columbia Generating Station                     Vice President Engineering Organization Final Safety Analysis Report Draw. No. 970187.07      Rev.       Figure 13.1-6 Form No. 960690FH LDCN-14-019

Amendment 61 December 2011 Quality Manager Quality Services        Supplier Quality                Quality Services Supervisor             Supervisor                    Supervisor/Plant Maintenance/Engineering/                                         Support Quality Control (Audits)                               (Continuous Monitoring)
Quality Organization Columbia Generating Station Final Safety Analysis Report Draw. No. 970187.08       Rev. 1      Figure 13.1-7 Form No. 960690FH LDCN-10-002

Amendment 62 December 2013 DELETED Columbia Generating Station Final Safety Analysis Report Draw. No. 970187.04 Rev. 1 Figure 13.1-8 Form No. 960690FH LDCN-12-004

Amendment 62 December 2013 Operations Manager Operations           Operations Support       Assistant Operations        Assistant Operations Crew Manager                Manager               Manager - Training              Manager -
Work Control Operations Organization Columbia Generating Station Final Safety Analysis Report Draw. No. 970187.09       Rev. 2       Figure 13.1-9 Form No. 960690FH LDCN-13-040

Amendment 62 December 2013 Operations Manager Operations Crew Manager Shift Managers (SRO)
                                 *Shift Technical                                         Incident Advisor                                              Advisor Control Room                                         If Required Supervisor                                         Shift Support (SRO)                                                      Supervisor Control Room Equipment Reactor Operators Operators (RO)(SRO)
Equipment                                         HP***/Chemistry Operators                                          Technicians Maintenance Legend:                                                                                 Support**
Functional StructureRather than Organizational Structure NRC License             Position Required (SRO)
* An assigned duty, not an organizational title
              ** To be provided from Maintenance Department as required
             *** To be provided from HP/Chemistry Department as required Operations Crew Columbia Generating Station Final Safety Analysis Report Draw. No. 970187.10         Rev. 1     Figure 13.1-10 Form No. 960690FH LDCN-12-020

Amendment 63 December 2015 Chemistry and Radiological Safety Manager Radiological Services Manager*
Radiological                  Radiological Operations                     Support Supervisor                  Supervisor Rad-Material HP Craft Control / Rad-Waste            Supervisors Supervisor
            *Also fulfills Radiation Protection Manager function Columbia Generating Station                                  Radiological Services Organization Final Safety Analysis Report Draw. No. 970187.11         Rev. 3 Figure 13.1-11 Form No. 960690FH LDCN-13-061

Amendment 63 December 2015 Chemistry and Radiological Safety Manager**
Chemistry                               Chemistry                          Environmental/
Technical                              Operations                       Analytical Support Supervisor                             Supervisors                           Supervisor*
* Dashed line indicates a functional rather than an organizational structure.
                     ** Also fulfills the Chemistry Manager function Columbia Generating Station                                      Chemistry Organization Final Safety Analysis Report Draw. No. 970187.12     Rev. 1      Figure 13.1-12 Form No. 960690FH LDCN-13-061

Amendment 63 December 2015 Maintenance Manager FIN Component             Maintenance                Reactor and Group                  Services              Major Maintenance Manager                Manager                     Manager Mechanical                   I&C                      Electrical Component                Component                   Component Group Manager            Group Manager               Group Manager Columbia Generating Station                          Plant Maintenance Organization Final Safety Analysis Report Draw. No. 970187.13       Rev. 3       Figure 13.1-13 Form No. 960690FH LDCN-13-040, 15-008

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 13.2     TRAINING 13.2.1       PLANT STAFF TRAINING PROGRAM In accordance with applicable federal guidelines, the Columbia Generating Station (CGS) training program has been designed to provide plant personnel with sufficient knowledge, training, and experience to enable them to safely and efficiently operate and maintain the plant and to protect the health and safety of the public.
The overall training program has been developed and coordinated by Energy Northwest, utilizing courses and programs produced by the nuclear steam supply system (NSSS) supplier, training consultant organizations, the training staff, and other employees of Energy Northwest possessing expertise in related disciplines.
The training program will provide sufficient qualified reactor operators, senior reactor operators, equipment operators, shift technical advisors, maintenance, health physics, chemistry, and engineering support personnel to fully staff CGS.
Initial training programs provide qualified replacement personnel and continuing training programs provide ongoing training for all plant staff commensurate with their area of responsibility and knowledge level.
The Chief Nuclear Officer is responsible for overall conduct and administration of the CGS training program. The development and implementation of that program may be delegated to the Training Organization or other members of the plant staff.
: a.      General Employee Training - Program Description All personnel granted unescorted access to the station will be trained in the following areas:
: 1. Appropriate plant security and emergency procedures,
: 2. General radiological protection,
: 3. Industrial safety,
: 4. Fire protection, and
: 5. Quality assurance program.
Written or oral exams will be required for selected classes to determine successful completion.
LDCN-14-046                                   13.2-1

COLUMBIA GENERATING STATION                            Amendment 58 FINAL SAFETY ANALYSIS REPORT                           December 2005
: b. General Employee Training - Fire Protection Program
: 1.       Plant employees Employees receiving an unescorted security clearance will be provided training to include orientation to the fire protection plans, evacuation signals and procedures, and the procedure for reporting a fire.
: 2.       Contractor personnel Training will be provided to contractors as part of their access status--
escorted or unescorted.
: c. Security Personnel Training - Fire Protection Program Training will be provided to plant security personnel that addresses
: 1.       Entry procedures for offsite fire department,
: 2.       Personnel control during emergency evacuation, and
: 3.       Basic fire hazard recognition.
13.2.2      INITIAL AND CONTINUING TRAINING 13.2.2.1       Licensed Operators 13.2.2.1.1      Initial Training Under the normal progression of an individual through the various levels of operator qualification, much of the material and experience will have been previously obtained, and hence, the licensed operator replacement training program will emphasize topics pertinent to the control room operator job function and requirements necessary for fulfilling the NRC operator licensing qualifications. Replacement for licensed operators normally come from the ranks of qualified nonlicensed operators; however, personnel from other departments or from outside the utility may be trained as control room operators if they meet all requirements for the position.
The CGS Operations Training Manager shall have the responsibility for establishing, supervising, and scheduling the initial licensed operator training program.
In accordance with 10 CFR 55.31(a)(4) the CGS licensed operator initial training program has been reviewed and approved by the Commission and was developed using a systems approach to training.
LDCN-03-077                                      13.2-2

COLUMBIA GENERATING STATION                          Amendment 58 FINAL SAFETY ANALYSIS REPORT                         December 2005 The licensed operator initial training program has been accredited by the National Academy for Nuclear Training. The accreditation is renewed every 4 years. Accreditation is maintained in accordance with Institute of Nuclear Power Operation (INPO) Guidelines 02-001, The Objectives and Criteria for Accreditation of Training in the Nuclear Power Industry, and 02-002, The Process for Accreditation of Training in the Nuclear Power Industry.
13.2.2.1.2      Continuing Training A requalification training program implementing the requirements of 10 CFR 55.59, will be conducted to maintain the knowledge level and operating proficiency of licensed personnel.
The retraining program will be based on a 2-year cycle.
The CGS Operations Training Manager shall have the responsibility for establishing, supervising, and scheduling the retraining program.
In accordance with 10 CFR 55.59(c) the CGS licensed operator requalification training program has been reviewed and approved by the NRC and was developed using a systems approach to training.
The requalification program has been accredited by the National Academy for Nuclear Training. The accreditation is maintained in accordance with INPO Guidelines 02-001, The Objectives and Criteria for Accreditation of Training in the Nuclear Power Industry, and 02-002, The Process for Accreditation of Training in the Nuclear Power Industry.
The retraining and replacement program for the unit staff meets the requirements of Section 5.5 of ANSI/ANS N18.1-1971, Appendix A of 10 CFR Part 55, and the supplemental requirements specified in Sections A and C of Enclosure 1 of the March 28, 1980, NRC letter to all licensees, and includes familiarization with relevant industry operational experience.
13.2.2.2       Nonlicensed Operator Training 13.2.2.2.1      Initial Training Normally replacements will be required to complete the following training prior to being placed into the equipment operator qualification sequence:
: a. Basic fundamentals,
: b. Basic boiling water reactor (BWR) systems,
: c. Reactor plant equipment and component theory, and
: d. Administrative procedures.
The training will emphasize topics pertinent to the equipment operator job function and requirements necessary for qualification.
LDCN-03-077                                    13.2-3

COLUMBIA GENERATING STATION                          Amendment 58 FINAL SAFETY ANALYSIS REPORT                         December 2005 13.2.2.2.2      Continuing Training Program Continuing training of nonlicensed operators may be conducted in conjunction with the licensed operator requalification program. Nonlicensed operators shall be required to attend specific lecture topics that pertain to their job level requirements. At a minimum, nonlicensed operators shall participate in periodic reviews of systems and operating procedures for which continuous familiarization is important for safe and efficient operation of the plant.
Specifically, the equipment operator retraining program consists of
: a.      Preplanned lecture series,
: b.      Update lecture series,
: c.      Normal/abnormal procedure review, and
: d.      Examinations/evaluations.
The CGS Operations Training Manager has the responsibility for establishing, supervising, and scheduling the equipment operator training program.
The equipment operator training program has been accredited by the National Academy for Nuclear Training. The accreditation is renewed every 4 years. Accreditation is maintained in accordance with INPO Guidelines 02-001, The Objectives and Criteria for Accreditation of Training in the Nuclear Power Industry, and 02-002, The Process of Accreditation of Training in the Nuclear Power Industry.
13.2.2.3       Shift Technical Advisor Training 13.2.2.3.1      Initial Training The initial shift technical advisor (STA) training program content will normally include training and qualification in the following subject areas:
: a.      Completion of the SRO replacement operator training program or equivalent
: b.      Plant transient/accident analysis, and
: c.      STA job specific training.
13.2.2.3.2      Continuing Training Continuing training of the STAs is normally conducted in conjunction with the licensed operator requalification training program. The STAs shall be required to attend specific lecture topics that pertain to their job level requirements. At a minimum, STAs shall participate in periodic reviews of systems and operating procedures for which continuous LDCN-03-077                                     13.2-4

COLUMBIA GENERATING STATION                        Amendment 58 FINAL SAFETY ANALYSIS REPORT                       December 2005 familiarization is important for safe and efficient operation of the plant. Specifically, the STA retraining program consists of
: a.        Preplanned lecture series,
: b.        Update lecture series,
: c.        Normal/abnormal procedure review, and
: d.        Examinations/evaluations.
The CGS Operations Training Manager has the responsibility for establishing, supervising, and scheduling the STA training program.
The STA training program has been accredited by the National Academy for Nuclear Training.
The accreditation is renewed every 4 years. Accreditation is maintained in accordance with INPO Guidelines 02-001, The Objectives and Criteria for Accreditation of Training in the Nuclear Power Industry, and 02-002, The Process for Accreditation of Training in the Nuclear Power Industry.
13.2.2.4         Other Plant Personnel (Maintenance, Health Physics, Chemistry) 13.2.2.4.1        Initial Training Replacement personnel, when hired, will be given training commensurate with their job responsibilities as determined necessary by the respective Department Manager and the appropriate Training Supervisor after a review of past experience and training.
13.2.2.4.2        Continuing Training Continuing training is conducted on a regular basis and consists of pertinent operating experience and designated requalification topics. The continuing training will be commensurate with their assigned job responsibilities as determined necessary by their respective Department Manager and Training Coordinator.
13.2.2.5         Fire Brigade 13.2.2.5.1        Initial and Continuing Training Each assigned member of the Fire Brigade will complete initial and continuing Fire Brigade training courses to provide the knowledge and skills necessary to accomplish the expected fire fighting activities. The scope of this training will be described and implemented by plant procedures.
LDCN-03-059, 03-077                             13.2-5

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 One assigned member will be designated as the Fire Brigade leader to direct the actual fire fighting forces. This individual will receive the training necessary to effectively carry out this function.
The Fire Brigade leader and two additional members will be knowledgeable of plant fire safe shutdown equipment.
: a.      Planned meetings Regular planned meetings for each Fire Brigade member will be held each quarter to review changes in the program and other subjects, as necessary.
During these planned meetings, the initial training program content will be reviewed for all Fire Brigade members over a 2-year period.
: b.      Practice sessions Practice sessions will be held for each Fire Brigade member annually on the proper methods of fighting the various types of fires that could occur in a nuclear power plant.
: c.      Drills Planned drills will be conducted for practice in responding as a team to areas of the plant site where the Fire Brigade may be required to respond. Each Fire Brigade member will be required to participate in at least two drills per year.
Each shift Fire Brigade will be required to participate in quarterly fire drills.
One drill for each shift Fire Brigade per year will be unannounced and one drill for each shift Fire Brigade per year will be on a back shift. The back shift and unannounced drill requirements can be satisfied concurrently for each shift.
13.2.2.5.2      Offsite Fire Department The offsite fire department that supplements the Fire Brigade will attend familiarization training associated with the CGS plant layout, operational precautions, radiation protection, and special hazards associated with fires at a nuclear power plant. This offsite fire department will participate in at least one fire drill each year.
LDCN-01-075                                      13.2-6

COLUMBIA GENERATING STATION                          Amendment 56 FINAL SAFETY ANALYSIS REPORT                        December 2001 13.2.3      TRAINING PROGRAM EFFECTIVENESS The effectiveness of the Training Program will be evaluated by the following methods:
: a.      Satisfactory job performance as determined by periodic line management evaluations and observations,
: b.      Satisfactory performance of plant personnel on various oral and or written examinations administered by Energy Northwest or NRC, and
: c.      Periodic reviews of instructors, programs, and training material as conducted by the Training Department.
13.2.4      PLANT TRAINING RECORDS The Training Manager maintains complete qualification records on each member of the plant staff.
All records necessary to support requests for NRC reactor operator and senior reactor operator licenses are included in these files. Records to be maintained are as follows:
: a.      Lecture series attendance,
: b.      Lecture examinations and answers by the licensees,
: c.      Annual examinations and answers by the licensees,
: d.      Simulator performance evaluation results,
: e.      Control Manipulations Tracking System Form, and
: f.      Additional training for deficiencies.
13.2.5      OTHER TRAINING DOCUMENTS For compliance with other applicable documents see Sections 1.8 and 12.5.3.8.
LDCN-01-047                                    13.2-7

COLUMBIA GENERATING STATION                      Amendment 53 FINAL SAFETY ANALYSIS REPORT                     November 1998 13.3    EMERGENCY PLANNING The detailed emergency plan is included as a separate volume in the Columbia Generating Station Emergency Plan.
13.3-1

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 13.4    REVIEW AND AUDIT The following sections describe the conduct of reviews and audits of operating activities that are important to safety. The review and audit program is consistent with the requirements of ANSI N18.7-1976, Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants.
Periodic reviews of plant operations are performed by the plant operating staff. In addition, Energy Northwest uses a formal onsite committee (see Section 13.4.1) and an independent group (see Section 13.4.2) for review.
The Quality staff has formulated and executed an audit program for the plant activities as defined in the Operational Quality Assurance Program Description (OQAPD).
The organization for review and audit and its relationship to other organizations is shown in Figures 13.1-1, 13.1-2, and 13.1-7.
13.4.1      ONSITE REVIEW Onsite reviews are consistent with Regulatory Guide 1.33 (see Section 1.8). The plant operating staff provides, as part of the normal duties of plant supervisory personnel, timely and continuing monitoring of operating activities to assist the Plant General Manager in keeping abreast of general plant conditions and to verify that the day-to-day operating activities are conducted safely and in accordance with applicable administrative controls. These continuing monitoring activities are an integral part of the routine supervisory function and are important to the safety of plant operation.
13.4.2      INDEPENDENT REVIEW In accordance with the OQAPD, the Plant Operations Committee (POC) serves as a review and advisory organization to the Plant General Manager on all matters related to nuclear safety. The Senior Site ALARA Committee (SSAC) serves as a review and advisory organization to the Plant General Manager on radiological safety matters. A specific function of the POC is to implement an independent review program as it relates to all proposed Technical Specification changes, License Amendment Requests, and Emergency Plan changes.
Written administrative procedures describe the responsibility and authority of the POC and SSAC. The POC activities and review are described in the OQAPD. The results of POC and SSAC review activities are documented.
LDCN-15-028                                   13.4-1

COLUMBIA GENERATING STATION                          Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 Additionally, in accordance with the OQAPD, the Corporate Nuclear Safety Review Board (CNSRB) is responsible for oversight of the POC and SSAC, which entails evaluating the effectiveness of POC and SSAC reviews, collectively, with regard to nuclear and radiological safety. The CNSRB reports to and advises the Chief Executive Officer on the adequacy and implementation of Energy Northwest nuclear and radiological safety policies and programs.
Documentation defining CNSRB membership, responsibilities, authority, and method of operation is contained in a Site Wide Procedure. Significant organizational features and review responsibilities are also described in the OQAPD. Conclusions of the independent reviews are transmitted to the appropriate members of management.
Independent technical reviews are performed by Quality in accordance with the OQAPD.
The objectivity of Quality is maintained based on a charter and reporting relationship independent of plant line management, without precluding participation in plant activities and tasks.
13.4.3      AUDIT PROGRAM A comprehensive program of audits is carried out to verify compliance to the OQAPD. These audits are performed by or under the direct cognizance of the Quality staff. Written reports of such audits are reviewed by the CNSRB, Plant General Manager, and other management as appropriate. Timely resolution of any deficiencies noted during audits is required by those organizations having responsibility for the area audited. Details of those areas to be audited are described in the OQAPD.
LDCN-15-028                                   13.4-2

COLUMBIA GENERATING STATION                           Amendment 62 FINAL SAFETY ANALYSIS REPORT                          December 2013 13.5    PLANT PROCEDURES The administrative controls and quality assurance program for plant operation are carried out in accordance with approved written procedures. All activities affecting nuclear safety are conducted by written and approved procedures of a type appropriate to the circumstances, and these activities are accomplished in accordance with these procedures.
13.5.1      ADMINISTRATIVE PROCEDURES 13.5.1.1       Conformance With Regulatory Guide 1.33, Revision 2 ANSI N18.7-1976 and Regulatory Guide 1.33 including Appendix A are followed in accordance with the Energy Northwest position discussed in the Operational Quality Assurance Program Description (OQAPD).
13.5.1.2       Preparation of Procedures The Procedure Program provides the administrative controls necessary to prepare, review, and approve the procedures required for plant operating activities.
The Chief Nuclear Officer has the overall responsibility for the Procedure Program and its implementing procedures. The Plant General Manager is responsible for the procedures that are required by ANSI N18.7-1976 and Regulatory Guide 1.33 and Appendix A. The preparation and review of the procedures are the responsibility of various plant staff personnel.
All procedures are approved according to the Procedure Program and the OQAPD.
13.5.1.3       Procedures The Procedure Program for Administrative Procedures defines the responsibility, methods used, and procedural action required to help ensure that the plant will be managed in a safe and dependable manner.
Administrative Procedures establish rules and instructions pertaining to activities such as procedure preparation, records management, plant reporting requirements, plant personnel responsibilities and authorities, plant modification, corrective and preventive maintenance, clearance orders, temporary changes to approved procedures, reviews of plant documents, surveillance testing and inservice inspection, equipment control, and material control.
Administrative Procedures governing standing orders to shift operations include the reactor operators authority and responsibilities; the senior reactor operators authority and responsibilities; the logbook use and control; issuance and updating of special orders; and the plans for meeting the requirements of 10 CFR 50.54(i), (j), (k), (1), and (m). This includes a diagram of the control room that illustrates the area designated as at the controls.
LDCN-12-022                                    13.5-1

COLUMBIA GENERATING STATION                            Amendment 55 FINAL SAFETY ANALYSIS REPORT                          May 2001 13.5.2       OPERATING AND MAINTENANCE PROCEDURES 13.5.2.1       Control Room Operating Procedures Detailed procedures used by the control room operators ensure plant safety and reliability.
These procedures are categorized and described as follows:
System Operating Procedures The System Operating Procedures provide instructions pertinent to the various normal operating modes of startup, operation, and shutdown of each system or subsystem. Checkoff lists are included, where appropriate, with each procedure to delineate the proper equipment lineup that is required.
General Operating Procedures General Operating Procedures provide the instructions for the integrated operation of plant systems during startup, shutdown, power operations, and power changes. Checkoff lists, as appropriate, are included to ensure that necessary prerequisites to integrated operation have been completed. Checklists may also be used to confirm completion of major steps in the proper sequence.
Abnormal Condition Procedures Abnormal Condition Procedures specify operator actions for restoring selected equipment or systems to their normal controlled status on a failure or to restore normal operating conditions following a perturbation. These procedures are not emergency procedures but are written to aid the operator in determining if a true emergency exists.
Abnormal Condition Procedures also contain response instructions for annunciator alarms and for abnormal conditions within the major systems covered in System Operating Procedures.
Each safety-related annunciator is addressed in a written procedure which contains (1) meaning of annunciator, (2) the source of the signal, (3) the immediate action that is to occur automatically, (4) immediate operator actions, and (5) subsequent operator actions. Those procedures that require the Immediate Operator Action steps to be memorized are given adequate identification.
Emergency Operating Procedures/Severe Accident Guidelines Emergency Operating Procedures/Severe Accident Guidelines are provided to guide operations during potential emergencies. These procedures specify actions, including manipulation of 13.5-2

COLUMBIA GENERATING STATION                          Amendment 62 FINAL SAFETY ANALYSIS REPORT                         December 2013 controls, to avoid further degradation of abnormal conditions or to reduce the consequences of an accident or hazardous condition that has already occurred.
13.5.2.2       Other Procedures Other safety-related activities conducted in accordance with approved procedures are categorized and described as follows (radioactive waste system operating procedures are covered by System Operating Procedures and the other aspects of radioactive waste management are covered by Health Physics and Chemistry Procedures).
Fuel Handling and Refueling Activities Procedures Fuel Handling and Refueling Activities Procedures provide instructions for fuel and core component accountability, new fuel handling, refueling operations, defective fuel handling, reactor core component handling, and irradiated fuel shipment.
Surveillance Procedures (both Operational Surveillance and Instrument and Electrical Surveillance)
Surveillance Procedures provide instructions for performing periodic tests to verify and document that safety-related structures, systems, and components continue to function properly to remain in a state of readiness to perform their intended safety functions. Surveillance Procedures cover systems operability tests, logic system functional tests, and instrument and/or electrical functional tests and calibrations for the various surveillance requirements listed in the Technical Specifications.
Operating and Test Procedures Operating and Test Procedures provide instructions for performing special tests on both safety and non-safety-related systems and components. These procedures contain tests such as power ascension, turbine efficiency, system hydrostatic tests, and reactor steam quality.
Nuclear Performance Evaluation Procedures The Nuclear Performance Evaluation Procedures provide instructions for Engineering and Operations in the performance of the following types of evaluations: core thermal power evaluations, core thermal-hydraulic evaluations, intermediate range monitor, local power range monitor, and average power range monitor calibration and criticality predictions.
LDCN-12-004                                     13.5-3

COLUMBIA GENERATING STATION                         Amendment 55 FINAL SAFETY ANALYSIS REPORT                        May 2001 Maintenance Programs and Procedures Maintenance Procedures provide instructions for performance of maintenance on safety-related equipment or systems and selected non-safety-related equipment and systems. Maintenance procedures cover mechanical, electrical, instrument and control, coatings, and refueling activities.
Health Physics Procedures Health Physics Procedures establish the administrative and technical controls for the Radiation Protection Program and the implementing procedures for accomplishing the program.
Descriptions of the activities covered by these procedures are included in Chapter 12.
Chemistry Procedures Chemistry Procedures establish the administrative and technical controls for water quality analysis. Chemical and radiochemical determination procedures and associated instrument operation and calibration procedures are provided.
Emergency Plan Implementing Procedures Detailed procedures prescribe the appropriate course of action necessary to limit or mitigate the consequences for each classification of incidents described in the Emergency Plan. An index of the Emergency Plan Implementing Procedures is included in Appendix II to the Emergency Plan.
Security Programs Implementing Procedures Detailed security procedures prescribe the course of action necessary for compliance with the policies of the Security Plan. The Security Plan and associated implementing procedures that contain safeguards information are withheld from public disclosure (see Section 13.6).
Fire Protection Procedures Fire Protection Procedures provide instructions for performing tests, inspections, and scheduled maintenance on fire protection equipment and systems and actions required for degraded systems.
ODCM Implementing Procedures The ODCM Implementing Procedures prescribe the action necessary to implement the requirements of the Offsite Dose Calculation Manual (ODCM), including effluent monitoring, instrument calibration, and reporting requirements.
13.5-4

COLUMBIA GENERATING STATION                       Amendment 55 FINAL SAFETY ANALYSIS REPORT                      May 2001 Environmental Compliance Procedures Environmental Compliance Procedures establish the administrative and technical controls for environmental compliance. These procedures provide instructions for the management of solid wastes, pollution prevention and waste minimization, chemical storage and use, and hazardous substance spills and cleanup.
13.5-5

COLUMBIA GENERATING STATION                        Amendment 53 FINAL SAFETY ANALYSIS REPORT                       November 1998 13.6    INDUSTRIAL SECURITY The Columbia Generating Station Physical Security Plan contains a description of the physical protection program for the facility as required by 10 CFR 50.54(p) and 10 CFR 73.55. The contents of this plan are safeguards information and are withheld from public disclosure pursuant to Section 2.790(a)(3) of 10 CFR Part 2.
13.6-1

COLUMBIA GENERATING STATION                                      Amendment 54 FINAL SAFETY ANALYSIS REPORT                                     April 2000 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS Section                                                                                             Page 14.1 SPECIFIC INFORMATION INCLUDED IN PRELIMINARY SAFETY ANALYSIS REPORTS..................................................... 14.1-1 14.2 SYSTEM LINEUP, PREOPERATIONAL, AND INITIAL STARTUP TEST PROGRAM ....................................................................... 14.2-1 14.2.1 

==SUMMARY==
OF TEST PROGRAM AND OBJECTIVES ......................... 14.2-1 14.2.1.1 Initial Test Program Objectives .................................................. 14.2-1 14.2.1.2 Initial Test Program Summaries.................................................. 14.2-1 14.2.1.3 Description of System Lineup Tests .............................................. 14.2-2 14.2.1.4 Description of Preoperational Tests ............................................. 14.2-3 14.2.1.5 Description of Startup Tests....................................................... 14.2-3 14.2.2 ORGANIZATION AND STAFFING................................................. 14.2-4 14.2.2.1 General ............................................................................... 14.2-4 14.2.2.2 Definitions............................................................................ 14.2-5 14.2.2.3 Test and Startup Program Organization and the System Lineup and Preoperational Test Program...................................................... 14.2-6 14.2.2.3.1 General............................................................................. 14.2-6 14.2.2.3.2 Responsibilities of CGS Test and Startup Division ......................... 14.2-6 14.2.2.3.3 CGS Test and Startup Department Position Responsibilities ............. 14.2-6 14.2.2.3.3.1 CGS Test and Startup Manager ............................................. 14.2-6 14.2.2.3.3.2 CGS Test Group Manager.................................................... 14.2-7 14.2.2.3.3.3 CGS Test Group Supervisor.................................................. 14.2-7 14.2.2.3.3.4 CGS Test Engineers ........................................................... 14.2-8 14.2.2.4 Plant Operations Organization and the Power Ascension Test Program ............................................................................... 14.2-8 14.2.2.5 Test Working Group ................................................................ 14.2-9 14.2.2.5.1 System Lineup and Preoperational Test Program .......................... 14.2-9 14.2.2.5.2 Membership and Responsibility of the Test Working Group .............. 14.2-9 14.2.2.6 Plant Organization Functions and Responsibilities During All Testing and Plant Operations...................................................... 14.2-10 14.2.2.7 Energy Northwest Support of the Test and Startup Program ................ 14.2-10 14.2.2.7.1 Plant Organization ............................................................... 14.2-10 14.2.2.7.1.1 Support During Test and Startup Program Development ............... 14.2-10 14.2.2.7.1.2 Support During Testing ....................................................... 14.2-11 14.2.2.7.2 CGS Program ..................................................................... 14.2-11 LDCN-99-000                                          14-i

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                            Page 14.2.2.7.3 Plant Quality Assurance......................................................... 14.2-11 14.2.2.8 Architect-Engineer Support of the Test and Startup Program............... 14.2-11 14.2.2.9 General Electric Support of the Test and Startup Program.................. 14.2-12 14.2.2.9.1 Staff Responsibilities ............................................................. 14.2-12 14.2.2.9.1.1 General Electric Operations Manager ..................................... 14.2-12 14.2.2.9.1.2 General Electric Operations Superintendent .............................. 14.2-12 14.2.2.9.1.3 General Electric Shift Superintendents ..................................... 14.2-12 14.2.2.9.1.4 General Electric Lead Engineer - Startup Test, Design, and Analysis .......................................................................... 14.2-13 14.2.2.10 Qualifications of Personnel Supporting the Test and Startup Program ............................................................................. 14.2-13 14.2.2.10.1 Test and Startup Program Department Personnel Qualifications ...... 14.2-13 14.2.2.10.2 Plant Organization Personnel Qualifications .............................. 14.2-14 14.2.3 TEST PROCEDURES................................................................. 14.2-14 14.2.3.1 Development of Test Procedures ................................................. 14.2-14 14.2.3.1.1 Incorporation of Plant Procedures ............................................ 14.2-15 14.2.3.1.2 Format of Test Procedures...................................................... 14.2-15 14.2.3.1.2.1 Preoperational Test Phase ................................................... 14.2-15 14.2.3.1.2.2 Power Ascension Test Phase ................................................. 14.2-17 14.2.3.2 Review of Test Procedures ........................................................ 14.2-17 14.2.3.3 Approval of Test Procedures ...................................................... 14.2-18 14.2.4 CONDUCT OF TEST PROGRAM.................................................. 14.2-18 14.2.4.1 Administrative Procedures for Preoperational Testing ....................... 14.2-18 14.2.4.1.1 Test Performance Authorization ............................................... 14.2-18 14.2.4.1.2 Preoperational Test Prerequisites ............................................. 14.2-19 14.2.4.1.3 Conduct of Preoperational Testing ............................................ 14.2-19 14.2.4.1.4 Deficiency Reporting............................................................. 14.2-20 14.2.4.1.5 Equipment Maintenance and Modifications During Preoperational Testing.............................................................................. 14.2-20 14.2.4.1.6 Preoperational Test Summary .................................................. 14.2-21 14.2.4.1.7 Evaluation of Preoperational Test Data ...................................... 14.2-21 14.2.4.1.8 Preoperational Test Records ................................................... 14.2-21 14.2.4.2 Administrative Procedures for Power Ascension Testing .................... 14.2-21 14.2.4.2.1 Plant Operation During Power Ascension Testing ......................... 14.2-21 14.2.4.2.2 Power Ascension Test Scheduling and Sequencing ......................... 14.2-22 LDCN-02-000                                        14-ii

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                            Page 14.2.4.2.3 Power Ascension Test Performance ........................................... 14.2-22 14.2.4.3 Control of Test Prerequisites...................................................... 14.2-23 14.2.4.4 Modification of Test Procedures During Testing .............................. 14.2-23 14.2.4.4.1 System Lineup and Preoperational Test Phase .............................. 14.2-23 14.2.4.4.2 Power Ascension Test Phase ................................................... 14.2-24 14.2.5 REVIEW, EVALUATION, AND APPROVAL OF TEST RESULTS ........... 14.2-24 14.2.5.1 Control of Test Results Review ................................................... 14.2-24 14.2.5.2 Design Organization Participation in Problem Resolution .................. 14.2-24 14.2.5.3 Results Analysis Prerequisites to Continuation of Startup Testing ......... 14.2-25 14.2.6 TEST RECORDS....................................................................... 14.2-25 14.2.6.1 System Lineup and Preoperational Test Phase ................................ 14.2-25 14.2.6.1.1 General............................................................................. 14.2-25 14.2.6.1.2 Test Record Responsibilities .................................................... 14.2-26 14.2.6.1.3 Types of Documents and Records Requiring Test Record File Retention ........................................................................... 14.2-26 14.2.6.2 Power Ascension Test Phase ...................................................... 14.2-26 14.2.7 CONFORMANCE OF TEST PROGRAMS WITH REGULATORY GUIDES ................................................................................. 14.2-26 14.2.7.1 Conformance with Regulatory Guide 1.68...................................... 14.2-26 14.2.7.2 Exceptions to Regulatory Guide 1.68............................................ 14.2-27 14.2.7.3 Conformance With or Exceptions to Regulatory Guides Other Than 1.68 ............................................................................ 14.2-27 14.2.8 UTILIZATION OF REACTOR OPERATING AND TESTING EXPERIENCES IN THE DEVELOPMENT OF THE TEST PROGRAM...... 14.2-27 14.2.9 TRIAL USE OF PLANT OPERATING AND EMERGENCY PROCEDURES ......................................................................... 14.2-28 14.2.10 INITIAL FUEL LOADING AND INITIAL CRITICALITY ..................... 14.2-28 14.2.10.1 Fuel Loading and Shutdown Power Level Tests.............................. 14.2-28 14.2.10.1.1 Loss of Power Demonstration - Standby Core Cooling Required ...... 14.2-28 14.2.10.1.2 Cold Functional Testing ....................................................... 14.2-28 14.2.10.1.3 Routine Surveillance Testing .................................................. 14.2-29 14.2.10.1.4 Master Startup Checklist....................................................... 14.2-29 14.2.10.1.5 Initial Fuel Loading ............................................................ 14.2-29 14.2.10.1.6 Zero Power Level Tests ........................................................ 14.2-30 14.2.10.2 Initial Heatup to Rated Temperature and Pressure.......................... 14.2-30 LDCN-02-000                                        14-iii

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                           Page 14.2.10.3 Power Testing From 25% to 100% of Rated Output ........................ 14.2-30 14.2.11 TEST PROGRAM SCHEDULE .................................................... 14.2-32 14.2.12 INDIVIDUAL TEST DESCRIPTIONS ............................................ 14.2-32 14.2.12.1 Preoperational Test Procedures ................................................ 14.2-32 14.2.12.1.1 Reactor Feedwater System Preoperational Test ........................... 14.2-33 14.2.12.1.2 Condensate System Preoperational Test .................................... 14.2-33 14.2.12.1.3 Fire Protection System Preoperational Test ................................ 14.2-34 14.2.12.1.4 Reactor Water Cleanup System Preoperational Test...................... 14.2-35 14.2.12.1.5 Standby Liquid Control System Preoperational Test...................... 14.2-35 14.2.12.1.6 Nuclear Boiler System Preoperational Test ................................ 14.2-36 14.2.12.1.7 Residual Heat Removal System Preoperational Test...................... 14.2-37 14.2.12.1.8 Reactor Core Isolation Cooling System Preoperational Test ............ 14.2-37 14.2.12.1.9 Reactor Recirculation System and Control Preoperational Test ........ 14.2-38 14.2.12.1.10 Reactor Manual Control System Preoperational Test ................... 14.2-39 14.2.12.1.11 Control Rod Drive Hydraulic System Preoperational Test ............. 14.2-39 14.2.12.1.12 Fuel Handling and Vessel Servicing Equipment Preoperational Test ............................................................................... 14.2-40 14.2.12.1.13 Low-Pressure Core Spray System Preoperational Test ................. 14.2-41 14.2.12.1.14 High-Pressure Core Spray System Preoperational Test ................ 14.2-42 14.2.12.1.15 Fuel Pool Cooling and Cleanup System Preoperational Test .......... 14.2-43 14.2.12.1.16 Leak Detection System Preoperational Test............................... 14.2-43 14.2.12.1.17 Liquid and Solid Radwaste System Preoperational Test ................ 14.2-44 14.2.12.1.18 Reactor Protection System Preoperational Test .......................... 14.2-45 14.2.12.1.19 Neutron Monitoring System Preoperational Test......................... 14.2-46 14.2.12.1.20 Traversing In-Core Probe System Preoperational Test ................. 14.2-47 14.2.12.1.21 Rod Worth Minimizer System Preoperational Test ...................... 14.2-47 14.2.12.1.22 Process Radiation Monitoring System Preoperational Test ............ 14.2-48 14.2.12.1.23 Area Radiation Monitoring System Preoperational Test................ 14.2-49 14.2.12.1.24 Process Computer Interface System Preoperational Test............... 14.2-50 14.2.12.1.25 Rod Sequence Control System Preoperational Test...................... 14.2-50 14.2.12.1.26 Remote Shutdown Preoperational Test .................................... 14.2-51 14.2.12.1.27 Offgas System Preoperational Test ......................................... 14.2-52 14.2.12.1.28 Environs Radiation Monitoring Preoperational Test .................... 14.2-53 14.2.12.1.29 Main Steam System Preoperational Test .................................. 14.2-53 LDCN-02-000                                       14-iv

COLUMBIA GENERATING STATION                                      Amendment 61 FINAL SAFETY ANALYSIS REPORT                                     December 2011 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                           Page 14.2.12.1.30 Radwaste Building Heating, Ventilating, and Air Conditioning System Preoperational Test................................................... 14.2-54 14.2.12.1.31 Closed Cooling Water System Preoperational Test ...................... 14.2-55 14.2.12.1.32 Primary Containment Atmospheric Control System Preoperational Test (SYSTEM DEACTIVATED) ......................... 14.2-55 14.2.12.1.33 Primary Containment Cooling System Preoperational Test ............ 14.2-56 14.2.12.1.34 Primary Containment Instrument Air Preoperational Test ............. 14.2-57 14.2.12.1.35 Primary Containment Atmospheric Monitoring System Preoperational Test ............................................................ 14.2-57 14.2.12.1.36 Standby Gas Treatment System Preoperational Test .................... 14.2-58 14.2.12.1.37 Loss of Power and Safety Testing Preoperational Test ................. 14.2-59 14.2.12.1.38 Instrument Power Preoperational Test .................................... 14.2-61 14.2.12.1.39 Emergency Lighting System Preoperational Test ........................ 14.2-61 14.2.12.1.40 Standby Alternating Current Power System Preoperational Test ..... 14.2-62 14.2.12.1.41 250-V Direct Current Power System Preoperational Test .............. 14.2-63 14.2.12.1.42 125-V Direct Current Power System Preoperational Test .............. 14.2-64 14.2.12.1.43 24-V Direct Current Power System Preoperational Test ............... 14.2-64 14.2.12.1.44 Plant Service Water System Preoperational Test ........................ 14.2-65 14.2.12.1.45 Standby Service Water System Preoperational Test ..................... 14.2-66 14.2.12.1.46 Plant Communications System Preoperational Test ..................... 14.2-67 14.2.12.1.47 Reactor Building Emergency Cooling System Preoperational Test ............................................................................... 14.2-67 14.2.12.1.48 Control, Cable, and Critical Switchgear Rooms Heating, Ventilating and Air Conditioning System Preoperational Test ......... 14.2-68 14.2.12.1.49 Standby Service Water Pump House Heating and Ventilating System Preoperational Test................................................... 14.2-68 14.2.12.1.50 Reactor Building Crane Preoperational Test ............................. 14.2-69 14.2.12.1.51 Primary Containment Integrated Leak Rate Preoperational Test ..... 14.2-70 14.2.12.1.52 Secondary Containment Integrated Leak Rate Preoperational Test ............................................................................... 14.2-71 14.2.12.1.53 Diesel Generator Building Heating and Ventilating System Preoperational Test ............................................................ 14.2-71 14.2.12.1.54 Seismic Monitoring System Preoperational Test ......................... 14.2-72 14.2.12.2 General Discussion of Startup Tests ........................................... 14.2-72 LDCN-11-000                                        14-v

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                          Page 14.2.12.3 Startup Test Procedures .......................................................... 14.2-73 14.2.12.3.1 Test Number 1 - Chemical and Radiochemical ............................ 14.2-73 14.2.12.3.1.1 Purpose ........................................................................ 14.2-73 14.2.12.3.1.2 Prerequisites .................................................................. 14.2-73 14.2.12.3.1.3 Description .................................................................... 14.2-73 14.2.12.3.1.4 Criteria ......................................................................... 14.2-74 14.2.12.3.2 Test Number 2 - Radiation Measurements .................................. 14.2-74 14.2.12.3.2.1 Purpose ........................................................................ 14.2-74 14.2.12.3.2.2 Prerequisites .................................................................. 14.2-74 14.2.12.3.2.3 Description .................................................................... 14.2-74 14.2.12.3.2.4 Criteria ......................................................................... 14.2-75 14.2.12.3.3 Test Number 3 - Fuel Loading ................................................ 14.2-75 14.2.12.3.3.1 Purpose ........................................................................ 14.2-75 14.2.12.3.3.2 Prerequisites .................................................................. 14.2-75 14.2.12.3.3.3 Description .................................................................... 14.2-76 14.2.12.3.3.4 Criteria ......................................................................... 14.2-76 14.2.12.3.4 Test Number 4 - Full Core Shutdown Margin.............................. 14.2-76 14.2.12.3.4.1 Purpose ........................................................................ 14.2-76 14.2.12.3.4.2 Prerequisites .................................................................. 14.2-76 14.2.12.3.4.3 Description .................................................................... 14.2-77 14.2.12.3.4.4 Criteria ......................................................................... 14.2-77 14.2.12.3.5 Test Number 5 - Control Rod Drive System ................................ 14.2-77 14.2.12.3.5.1 Purpose ........................................................................ 14.2-77 14.2.12.3.5.2 Prerequisites .................................................................. 14.2-77 14.2.12.3.5.3 Description .................................................................... 14.2-78 14.2.12.3.5.4 Criteria ......................................................................... 14.2-79 14.2.12.3.6 Test Number 6 - Source Range Monitor Performance and Control Rod Sequence .......................................................... 14.2-80 14.2.12.3.6.1 Purpose ........................................................................ 14.2-80 14.2.12.3.6.2 Prerequisites .................................................................. 14.2-80 14.2.12.3.6.3 Description .................................................................... 14.2-80 14.2.12.3.6.4 Criteria ......................................................................... 14.2-80 14.2.12.3.7 Test Number 7 ................................................................... 14.2-81 14.2.12.3.8 Test Number 8 ................................................................... 14.2-81 14.2.12.3.9 Test Number 9 ................................................................... 14.2-81 LDCN-02-000                                      14-vi

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                         Page 14.2.12.3.10 Test Number 10 - Intermediate Range Monitor System Performance.................................................................... 14.2-81 14.2.12.3.10.1 Purpose ....................................................................... 14.2-81 14.2.12.3.10.2 Prerequisites ................................................................. 14.2-81 14.2.12.3.10.3 Description................................................................... 14.2-81 14.2.12.3.10.4 Criteria ....................................................................... 14.2-81 14.2.12.3.11 Test Number 11 - Local Power Range Monitor Calibration ........... 14.2-82 14.2.12.3.11.1 Purpose ....................................................................... 14.2-82 14.2.12.3.11.2 Prerequisites ................................................................. 14.2-82 14.2.12.3.11.3 Description................................................................... 14.2-82 14.2.12.3.11.4 Criteria ....................................................................... 14.2-82 14.2.12.3.12 Test Number 12 - Average Power Range Monitor Calibration ........ 14.2-82 14.2.12.3.12.1 Purpose ....................................................................... 14.2-82 14.2.12.3.12.2 Prerequisites ................................................................. 14.2-82 14.2.12.3.12.3 Description................................................................... 14.2-82 14.2.12.3.12.4 Criteria ....................................................................... 14.2-83 14.2.12.3.13 Test Number 13 - Process Computer....................................... 14.2-83 14.2.12.3.13.1 Purpose ....................................................................... 14.2-83 14.2.12.3.13.2 Prerequisites ................................................................. 14.2-83 14.2.12.3.13.3 Description................................................................... 14.2-83 14.2.12.3.13.4 Criteria ....................................................................... 14.2-84 14.2.12.3.14 Test Number 14 - Reactor Core Isolation Cooling System ............. 14.2-85 14.2.12.3.14.1 Purpose ....................................................................... 14.2-85 14.2.12.3.14.2 Prerequisites ................................................................. 14.2-85 14.2.12.3.14.3 Description................................................................... 14.2-85 14.2.12.3.14.4 Criteria ....................................................................... 14.2-86 14.2.12.3.15 Test Number 15 ................................................................ 14.2-86 14.2.12.3.16 Test Numbers 16A and 16B.................................................. 14.2-86 14.2.12.3.16.1 Test Number 16A - Selected Process Temperatures................... 14.2-86 14.2.12.3.16.1.1 Purpose .................................................................... 14.2-86 14.2.12.3.16.1.2 Prerequisites .............................................................. 14.2-87 14.2.12.3.16.1.3 Description ................................................................ 14.2-87 14.2.12.3.16.1.4 Criteria..................................................................... 14.2-87 LDCN-02-000                                     14-vii

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                         Page 14.2.12.3.16.2 Test Number 16B - Water Level Reference Leg Temperature Measurement ................................................................. 14.2-88 14.2.12.3.16.2.1 Purpose .................................................................... 14.2-88 14.2.12.3.16.2.2 Prerequisites .............................................................. 14.2-88 14.2.12.3.16.2.3 Description ................................................................ 14.2-88 14.2.12.3.16.2.4 Criteria..................................................................... 14.2-89 14.2.12.3.17 Test Number 17 - System Expansion ....................................... 14.2-89 14.2.12.3.17.1 Purpose ....................................................................... 14.2-89 14.2.12.3.17.2 Prerequisites ................................................................. 14.2-89 14.2.12.3.17.3 Description................................................................... 14.2-89 14.2.12.3.17.4 Criteria ....................................................................... 14.2-92 14.2.12.3.18 Test Number 18 - Core Power Distribution............................... 14.2-92 14.2.12.3.18.1 Purpose ....................................................................... 14.2-92 14.2.12.3.18.2 Prerequisites ................................................................. 14.2-92 14.2.12.3.18.3 Description................................................................... 14.2-92 14.2.12.3.18.4 Criteria ....................................................................... 14.2-93 14.2.12.3.19 Test Number 19 - Core Performance....................................... 14.2-93 14.2.12.3.19.1 Purpose ....................................................................... 14.2-93 14.2.12.3.19.2 Prerequisites ................................................................. 14.2-93 14.2.12.3.19.3 Description................................................................... 14.2-94 14.2.12.3.19.4 Criteria ....................................................................... 14.2-94 14.2.12.3.20 Test Number 20 - Steam Production ....................................... 14.2-94 14.2.12.3.20.1 Purpose ....................................................................... 14.2-94 14.2.12.3.20.2 Prerequisites ................................................................. 14.2-95 14.2.12.3.20.3 Description................................................................... 14.2-95 14.2.12.3.20.4 Criteria ....................................................................... 14.2-95 14.2.12.3.21 Test Number 21 - Core Power-Void Mode ................................ 14.2-96 14.2.12.3.21.1 Purpose ....................................................................... 14.2-96 14.2.12.3.21.2 Prerequisites ................................................................. 14.2-96 14.2.12.3.21.3 Description................................................................... 14.2-96 14.2.12.3.21.4 Criteria ....................................................................... 14.2-96 14.2.12.3.22 Test Number 22 - Pressure Regulator ..................................... 14.2-96 14.2.12.3.22.1 Purpose ....................................................................... 14.2-96 14.2.12.3.22.2 Prerequisites ................................................................. 14.2-96 14.2.12.3.22.3 Description................................................................... 14.2-97 LDCN-02-000                                    14-viii

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                         Page 14.2.12.3.22.4 Criteria ....................................................................... 14.2-97 14.2.12.3.23 Test Number 23 - Feedwater System ....................................... 14.2-98 14.2.12.3.23.1 23A - Water Level Setpoint and Manual Flow Changes.............. 14.2-98 14.2.12.3.23.1.1 Purpose .................................................................... 14.2-98 14.2.12.3.23.1.2 Prerequisites .............................................................. 14.2-98 14.2.12.3.23.1.3 Description ................................................................ 14.2-98 14.2.12.3.23.1.4 Criteria..................................................................... 14.2-98 14.2.12.3.23.2 23B - Loss of Feedwater Heating ........................................ 14.2-100 14.2.12.3.23.2.1 Purpose .................................................................... 14.2-100 14.2.12.3.23.2.2 Prerequisites .............................................................. 14.2-100 14.2.12.3.23.2.3 Description ................................................................ 14.2-100 14.2.12.3.23.2.4 Criteria..................................................................... 14.2-100 14.2.12.3.23.3 22C - Feedwater Pump Trip .............................................. 14.2-101 14.2.12.3.23.3.1 Purpose .................................................................... 14.2-101 14.2.12.3.23.3.2 Prerequisites .............................................................. 14.2-101 14.2.12.3.23.3.3 Description ................................................................ 14.2-101 14.2.12.3.23.3.4 Criteria..................................................................... 14.2-101 14.2.12.3.23.4 23D - Maximum Feedwater Runout Capability ....................... 14.2-101 14.2.12.3.23.4.1 Purpose .................................................................... 14.2-101 14.2.12.3.23.4.2 Prerequisites .............................................................. 14.2-101 14.2.12.3.23.4.3 Description ................................................................ 14.2-101 14.2.12.3.23.4.4 Criteria..................................................................... 14.2-102 14.2.12.3.24 Test Number 24 - Turbine Valve Surveillance ............................ 14.2-103 14.2.12.3.24.1 Purpose ....................................................................... 14.2-103 14.2.12.3.24.2 Prerequisites ................................................................. 14.2-103 14.2.12.3.24.3 Description................................................................... 14.2-103 14.2.12.3.24.4 Criteria ....................................................................... 14.2-103 14.2.12.3.25 Test Number 25 - Main Steam Isolation Valves .......................... 14.2-104 14.2.12.3.25.1 25A - Main Steam Isolation Valve Function Tests..................... 14.2-104 14.2.12.3.25.1.1 Purpose .................................................................... 14.2-104 14.2.12.3.25.1.2 Prerequisites .............................................................. 14.2-104 14.2.12.3.25.1.3 Description ................................................................ 14.2-104 14.2.12.3.25.1.4 Criteria..................................................................... 14.2-104 14.2.12.3.25.2 25B - Full Reactor Isolation .............................................. 14.2-105 14.2.12.3.25.2.1 Purpose .................................................................... 14.2-105 14-ix

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                         Page 14.2.12.3.25.2.2 Prerequisites .............................................................. 14.2-105 14.2.12.3.25.2.3 Description ................................................................ 14.2-105 14.2.12.3.25.2.4 Criteria..................................................................... 14.2-105 14.2.12.3.26 Test Number 26 - Relief Valves ............................................. 14.2-106 14.2.12.3.26.1 Purpose ....................................................................... 14.2-106 14.2.12.3.26.2 Prerequisites ................................................................. 14.2-106 14.2.12.3.26.3 Description................................................................... 14.2-106 14.2.12.3.26.4 Criteria ....................................................................... 14.2-106 14.2.12.3.27 Test Number 27 - Turbine Trip and Generator Load Rejection ....... 14.2-107 14.2.12.3.27.1 Purpose ....................................................................... 14.2-107 14.2.12.3.27.2 Prerequisites ................................................................. 14.2-107 14.2.12.3.27.3 Description................................................................... 14.2-107 14.2.12.3.27.4 Criteria ....................................................................... 14.2-108 14.2.12.3.28 Test Number 28 - Shutdown From Outside the Main Control Room ............................................................................ 14.2-109 14.2.12.3.28.1 Purpose ....................................................................... 14.2-109 14.2.12.3.28.2 Prerequisites ................................................................. 14.2-110 14.2.12.3.28.3 Description................................................................... 14.2-110 14.2.12.3.28.4 Criteria ....................................................................... 14.2-110 14.2.12.3.29 Test Number 29 - Recirculation Flow Control ........................... 14.2-110 14.2.12.3.29.1 29A - Valve Position Control ............................................. 14.2-110 14.2.12.3.29.1.1 Purpose .................................................................... 14.2-110 14.2.12.3.29.1.2 Prerequisites .............................................................. 14.2-110 14.2.12.3.29.1.3 Description ................................................................ 14.2-110 14.2.12.3.29.1.4 Criteria..................................................................... 14.2-111 14.2.12.3.29.2 29B - Recirculation Flow Loop Control................................. 14.2-112 14.2.12.3.29.2.1 Purpose .................................................................... 14.2-112 14.2.12.3.29.2.2 Prerequisites .............................................................. 14.2-112 14.2.12.3.29.2.3 Description ................................................................ 14.2-112 14.2.12.3.29.2.4 Criteria..................................................................... 14.2-113 14.2.12.3.30 Test Number 30 - Recirculation System ................................... 14.2-115 14.2.12.3.30.1 30A - One Pump Trip ...................................................... 14.2-115 14.2.12.3.30.1.1 Purpose .................................................................... 14.2-115 14.2.12.3.30.1.2 Prerequisites .............................................................. 14.2-115 14.2.12.3.30.1.3 Description ................................................................ 14.2-115 14-x

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                         Page 14.2.12.3.30.1.4 Criteria..................................................................... 14.2-115 14.2.12.3.30.2 30B - Recirculation Trip of Two Pumps ................................ 14.2-116 14.2.12.3.30.2.1 Purpose .................................................................... 14.2-116 14.2.12.3.30.2.2 Prerequisites .............................................................. 14.2-116 14.2.12.3.30.2.3 Description ................................................................ 14.2-116 14.2.12.3.30.2.4 Criteria..................................................................... 14.2-116 14.2.12.3.30.3 30C - System Performance ................................................ 14.2-117 14.2.12.3.30.3.1 Purpose .................................................................... 14.2-117 14.2.12.3.30.3.2 Prerequisites .............................................................. 14.2-117 14.2.12.3.30.3.3 Description ................................................................ 14.2-117 14.2.12.3.30.3.4 Criteria..................................................................... 14.2-117 14.2.12.3.30.4 30D - Recirculation Pump Runback ..................................... 14.2-118 14.2.12.3.30.4.1 Purpose .................................................................... 14.2-118 14.2.12.3.30.4.2 Prerequisites .............................................................. 14.2-118 14.2.12.3.30.4.3 Description ................................................................ 14.2-118 14.2.12.3.30.4.4 Criteria..................................................................... 14.2-118 14.2.12.3.30.5 30E - Recirculation System Cavitation .................................. 14.2-118 14.2.12.3.30.5.1 Purpose .................................................................... 14.2-118 14.2.12.3.30.5.2 Prerequisites .............................................................. 14.2-118 14.2.12.3.30.5.3 Description ................................................................ 14.2-118 14.2.12.3.30.5.4 Criteria..................................................................... 14.2-119 14.2.12.3.31 Test Number 31 - Loss of Turbine-Generator and Offsite Power ..... 14.2-119 14.2.12.3.31.1 Purpose ....................................................................... 14.2-119 14.2.12.3.31.2 Prerequisites ................................................................. 14.2-119 14.2.12.3.31.3 Description................................................................... 14.2-119 14.2.12.3.31.4 Criteria ....................................................................... 14.2-119 14.2.12.3.32 Not Applicable ................................................................. 14.2-120 14.2.12.3.33 Test Number 33 - Piping Vibration......................................... 14.2-120 14.2.12.3.33.1 Purpose ....................................................................... 14.2-120 14.2.12.3.33.2 Prerequisites ................................................................. 14.2-120 14.2.12.3.33.3 Description................................................................... 14.2-120 14.2.12.3.33.4 Criteria ....................................................................... 14.2-120 14.2.12.3.34 Test Number 34 - Reactor Pressure Vessel Internals Vibration ....... 14.2-121 14.2.12.3.34.1 Purpose ....................................................................... 14.2-121 14.2.12.3.34.2 Prerequisites ................................................................. 14.2-121 14-xi

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                         Page 14.2.12.3.34.3 Description................................................................... 14.2-121 14.2.12.3.34.4 Criteria ....................................................................... 14.2-122 14.2.12.3.35 Test Number 35 - Recirculation System Flow Calibration.............. 14.2-122 14.2.12.3.35.1 Purpose ....................................................................... 14.2-122 14.2.12.3.35.2 Prerequisites ................................................................. 14.2-122 14.2.12.3.35.3 Description................................................................... 14.2-122 14.2.12.3.35.4 Criteria ....................................................................... 14.2-123 14.2.12.3.36 Test Number 70 - Reactor Water Cleanup System ....................... 14.2-123 14.2.12.3.36.1 Purpose ....................................................................... 14.2-123 14.2.12.3.36.2 Prerequisites ................................................................. 14.2-123 14.2.12.3.36.3 Description................................................................... 14.2-123 14.2.12.3.36.4 Criteria ....................................................................... 14.2-123 14.2.12.3.37 Test Number 71 - Residual Heat Removal System ....................... 14.2-124 14.2.12.3.37.1 Purpose ....................................................................... 14.2-124 14.2.12.3.37.2 Prerequisites ................................................................. 14.2-124 14.2.12.3.37.3 Description................................................................... 14.2-124 14.2.12.3.37.4 Criteria ....................................................................... 14.2-124 14.2.12.3.38 Test Number 72 - Drywell Atmosphere Cooling System ................ 14.2-125 14.2.12.3.38.1 Purpose ....................................................................... 14.2-125 14.2.12.3.38.2 Prerequisites ................................................................. 14.2-125 14.2.12.3.38.3 Description................................................................... 14.2-125 14.2.12.3.38.4 Criteria ....................................................................... 14.2-125 14.2.12.3.39 Test Number 73 - Cooling Water Systems................................. 14.2-125 14.2.12.3.39.1 Purpose ....................................................................... 14.2-125 14.2.12.3.39.2 Prerequisites ................................................................. 14.2-125 14.2.12.3.39.3 Description................................................................... 14.2-125 14.2.12.3.39.4 Criteria ....................................................................... 14.2-126 14.2.12.3.40 Test Number 74 - Offgas System ............................................ 14.2-126 14.2.12.3.40.1 Purpose ....................................................................... 14.2-126 14.2.12.3.40.2 Prerequisites ................................................................. 14.2-126 14.2.12.3.40.3 Description................................................................... 14.2-126 14.2.12.3.40.4 Criteria ....................................................................... 14.2-127 14-xii

COLUMBIA GENERATING STATION                                      Amendment 53 FINAL SAFETY ANALYSIS REPORT                                     November 1998 Chapter 14 INITIAL TEST PROGRAM LIST OF TABLES Number                                  Title                                               Page 14.2-1 Preoperational Tests............................................................ 14.2-129 14.2-2 Major Plant Transients......................................................... 14.2-132 14.2-3 Stability Tests .................................................................... 14.2-133 14.2-4 Power Ascension Test Program............................................... 14.2-134 14-xiii

COLUMBIA GENERATING STATION                      Amendment 54 FINAL SAFETY ANALYSIS REPORT                     April 2000 Chapter 14 INITIAL TEST PROGRAM LIST OF FIGURES Number                                 Title 14.2-1      Test Condition Region Definition 14.2-2      Test and Startup Relation to Other Energy Northwest Departments 14.2-3      CGS Startup Organization 14.2-4      Preoperational Test Schedule 14.2-5      RCIC Acceptance Criteria Curves for Capacity and Actuation Time 14.2-6      Maximum Acceptable Drive Flow Response LDCN-99-000                               14-xiv

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998 Chapter 14 INITIAL TEST PROGRAM 14.1     SPECIFIC INFORMATION INCLUDED IN PRELIMINARY SAFETY ANALYSIS REPORTS The initial test program overall test objectives and general prerequisites were previously provided in the Preliminary Safety Analysis Report (PSAR). The technical aspects of the initial test program are described in Section 14.2 in sufficient detail to show that the test program adequately verifies the functional requirements of plant structures, systems, and components such that the safety of the plant will not be dependent on untested structures, systems, or components.
14.1-1

COLUMBIA GENERATING STATION                            Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998 14.2    SYSTEM LINEUP, PREOPERATIONAL, AND INITIAL STARTUP TEST PROGRAM The italicized information is historical and was provided to support the application for an operating license.
The initial test program consisted of a series of tests categorized as system lineup testing, preoperational, and initial startup tests. The system lineup testing determines correct installation and functional operability of equipment. Preoperational tests are those tests normally conducted prior to fuel loading to demonstrate the capability of plant systems to meet performance requirements. Initial startup tests began with fuel loading and demonstrated the capability of the integrated plant to meet performance requirements.
14.2.1      

==SUMMARY==
OF TEST PROGRAM AND OBJECTIVES 14.2.1.1       Initial Test Program Objectives The objectives of the initial test program are to
: a.       Ensure that the construction is complete and acceptable,
: b.       Demonstrate the capability of structures, components, and systems to meet performance requirements,
: c.       Effect fuel loading in a safe manner,
: d.       Demonstrate, where practical, that the plant is capable of withstanding anticipated transients and postulated accidents,
: e.       Evaluate and demonstrate, to the extent possible, plant operating procedures to provide assurance that the operating group is knowledgeable about the plant and procedures and fully prepared to operate the facility in a safe manner, and
: f.       Bring the plant to rated capacity and sustained power operation.
14.2.1.2       Initial Test Program Summaries The three categories of tests in the initial test program are summarized below:
: a.       System lineup tests such as pump and valve tests, mechanical actuation to verify proper installation, and electrical continuity verifications, are those tests which demonstrate that components are correctly installed and operational.
14.2-1

COLUMBIA GENERATING STATION                            Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998
: b. Preoperational tests conducted prior to fuel loading to demonstrate that the plant systems have been properly designed and that they meet performance requirements.
: c. Startup tests consist of fuel loading, precritical tests, low power tests, and power ascension tests that ensure fuel loading in a safe manner, confirm the design bases, demonstrate where practical that the plant is capable of withstanding the anticipated transients and postulated accidents, and ensure that the plant is safely brought to rated capacity and sustained power operation.
14.2.1.3      Description of System Lineup Tests Typical system lineup tests generally include but are not limited to the following:
: a.      Chemical cleaning and flushing of systems, tanks, and vessels,
: b. Electrical equipment to test and/or energize, e.g., grounding, relays, circuit breaker operation and controls, continuity, megger, phasing, high potential measurements, and buses,
: c. Initial adjustment, bumping, and running of rotating equipment,
: d.      Checking control and interlock functions of instruments, relays, and control devices,
: e. Calibrating instruments and checking or setting initial trip setpoints,
: f. Pneumatic testing of instruments and service air system and cleanout of lines,
: g.      Checking and adjusting relief and safety valves,
: h. Complete tests of safety-related motor-operated valves including adjusting torque switches and limit switches, checking all interlocks and controls, measuring motor current and operating speed, and checking leaktightness of stem packing and valve seat during hydrotests; and complete tests of the nuclear steam supply system (NSSS) control systems including checking all interlocks and controls, adjusting limit switches, measuring operating speed, checking leaktightness of pneumatic operators, and checking for proper operation of controllers, pilot solenoids, etc., and
: i. Other tests and verifications such as structural, leaktightness, and vibration.
14.2-2

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998 14.2.1.4       Description of Preoperational Tests A listing of the preoperational tests is provided in Table 14.2-1. The general objectives of the preoperational test phase are as follows:
: a.      Ensure that test acceptance criteria are met,
: b.      Provide documentation of the performance and safety of equipment and systems,
: c.      Provide baseline test and operating data on equipment and systems for future reference,
: d.      Run-in of a system for a sufficient period so that any design, manufacturing, or installation defects can be detected and corrected,
: e.      Ensure that plant systems operate together on an integrated basis to the extent possible,
: f.      Give maximum opportunity to the permanent plant operating staff to obtain practical experience in the operation and maintenance of equipment and systems,
: g.      Establish safe and efficient normal, abnormal, and emergency operating procedures, to the extent possible,
: h.      Establish and evaluate surveillance testing procedures, and
: i.      Demonstrate that systems and safety equipment are operational and that it is possible to proceed to fuel loading and to the Startup Phase.
14.2.1.5       Description of Startup Tests The Power Ascension Test Phase (PATP) begins after the Preoperational Test Phase has been completed. The Power Ascension Test Phase begins with fuel loading and extends to commercial operation. This phase is subdivided into the following four parts:
: a.      Open vessel testing (fuel loading and shutdown power level tests),
: b.      Initial heatup,
: c.      Power testing, and
: d.      Warranty demonstration.
The tests conducted during the Power Ascension Test Phase consist of major plant transients (Table 14.2-2), stability tests (Table 14.2-3), and a remainder of tests which are directed 14.2-3

COLUMBIA GENERATING STATION                          Amendment 54 FINAL SAFETY ANALYSIS REPORT                         April 2000 towards demonstrating correct performance of the nuclear boiler and numerous auxiliary plant systems while at power. Certain tests may be identified with more than one class of test.
Table 14.2-4 shows the complete Power Ascension Test Program. Figure 14.2-1 provides test conditions region definition.
The general objectives of the Power Ascension Test Phase are as follows:
: a.      Achieve an orderly and safe initial core loading,
: b.      Accomplish all testing and measurements necessary to determine that the approach to initial criticality and subsequent power ascension is safe and orderly,
: c.      Conduct low power physics tests sufficient to ensure that test acceptance criteria have been met,
: d.      Conduct initial heatup and hot functional testing so that hot integrated operation of all systems is shown to meet test acceptance criteria,
: e.      Conduct an orderly and safe power ascension program, with requisite physics and systems testing, to ensure that the plant operating at power meets test acceptance criteria, and
: f.      Conduct a successful warranty demonstration program.
14.2.2      ORGANIZATION AND STAFFING 14.2.2.1       General The Energy Northwest Test and Startup Program is administered by two entities with distinct levels of responsibility and two distinct organizations.
For the system lineup test phase and the preoperational test phase, the Test Working Group (TWG) provides review, approval, and planning of general Test and Startup Program activities and the results of those activities. The Test and Startup organization and qualified members of other organizations represented on the TWG provide the necessary development, implementation, and analysis of Test and Startup Program activities at the working level.
For the Power Ascension Test Phase, the Plant Operations Committee (POC) provides review and planning of the test program and evaluates the test results. The Plant Manager approves the procedures and final test reports. The implementation of the PATP is achieved with the normal plant operations crew operating the plant and test engineers under the direction of the Reactor Engineering Supervisor coordinating the test activities.
LDCN-99-000                                     14.2-4

COLUMBIA GENERATING STATION                           Amendment 54 FINAL SAFETY ANALYSIS REPORT                          April 2000 14.2.2.2      Definitions The definitions of phrases used in this section and throughout this chapter are as follows:
: a. Test Working Group (TWG) - a project onsite administrative body whose membership consists of personnel representing organizations directly responsible for preparation and performance of testing and startup during the system lineup and preoperational test phases. This group provides review and approval of test preparation and performance activities.
: b. Power Generation - an Energy Northwest organization within the Operations Directorate with responsibility for development and implementation of the Test and Startup Program.
: c. Columbia Generating Station (CGS) Test and Startup - a Power Generation division with responsibility for development and implementation of the CGS Test and Startup Program.
: d. CGS Plant Organization - a Power Generation division with responsibility to startup, operate, and maintain CGS in compliance with Federal, State, local, and owner requirements.
: e. CGS Plant Operations Committee (POC) - refer to definition in Section 13.4.1.
The POC reviews the activities of the Power Ascension Test Phase.
: f. Test and Startup Manager - the Power Generation Division Manager with responsibility for implementation of the CGS Test and Startup Program.
: g. Test and Startup Program - the program that encompasses the transition from construction to commercial operation and consists of system lineup testing, preoperational testing, and power ascension testing.
: h. Test and Startup Program Manual - the manual that defines generic administrative policy and procedures for the initial testing and startup of Energy Northwest nuclear facilities.
: i. Test and Startup Instructions - the specific instructions required to implement the Test and Startup Program for an individual project.
: j. Plant Procedure Manual (PPM) - the Plant Manager approved procedures for operating the plant. The PPMs include the test procedures for the PATP.
LDCN-99-000                                    14.2-5

COLUMBIA GENERATING STATION                          Amendment 54 FINAL SAFETY ANALYSIS REPORT                         April 2000 14.2.2.3       Test and Startup Program Organization and the System Lineup and Preoperational Test Program 14.2.2.3.1          General Power Generation is an organization within the Energy Northwest Operations Directorate.
Relative to the Program, Power Generation is responsible for development and administration of plans, policies, and administrative procedures; procurement of test equipment and other test-related resources, and assignment of the CGS Test and Startup Manager. The Power Generation organization and its relationship to other Energy Northwest organizations is shown in Figure 14.2-2.
14.2.2.3.2          Responsibilities of CGS Test and Startup Division CGS Test and Startup is a Division of the Power Generation organization. The CGS Test and Startup Manager manages an organization comprised of Energy Northwest test engineers and test technicians augmented by test personnel from the architect-engineer, the NSSS supplier, and others as contractually established. The CGS Test and Startup Manager is responsible for the development and implementation of the CGS Test and Startup program and those responsibilities are described in Section 14.2.2.3.3. The CGS Test and Startup staff organization is shown in Figure 14.2-3.
14.2.2.3.3          CGS Test and Startup Department Position Responsibilities 14.2.2.3.3.1 CGS Test and Startup Manager.
: a.      Chairman, TWG;
: b.      Develop plans, schedules, methods, procedures, and data systems for the testing and evaluation of all plant equipment and systems to permit acceptance and licensing;
: c.      Administer and coordinate the testing activities with other organizations involved in the Test and Startup Program;
: d.      Manage and direct assigned test personnel in activities relating to the attainment of Test and Startup Program objectives;
: e.      Manage and direct assigned test personnel to establish qualitative and quantitative acceptance criteria and develop test procedures to direct and guide performance of testing, and LDCN-99-000                                   14.2-6

COLUMBIA GENERATING STATION                         Amendment 54 FINAL SAFETY ANALYSIS REPORT                        April 2000
: f.      Provide recommendations and effect actions to eliminate equipment or system deficiencies as determined by Test and Startup Program criteria which could adversely affect performance of safety-related functions.
14.2.2.3.3.2 CGS Test Group Manager.
: a.      Represent Test and Startup on the TWG;
: b.      Coordinate the activities of Test Group Supervisors and test engineers during the Test and Startup Program;
: c.      Develop, monitor, and coordinate the preparation and implementation of plans, schedules, methods, and procedures for testing and evaluation of plant systems and components for verification of performance and acceptance;
: d.      Maintain surveillance over testing performed by Energy Northwest and others, including system and equipment tests, and calibration of instrumentation;
: e.      Identify problem areas and recommend actions where deficiencies could adversely affect the performance, safety-related functions, or operating efficiency;
: f.      Assist in preparation of program status and other Test and Startup Program related reports, and
: g.      Assume the responsibilities of the Test and Startup Manager as described in the Test and Startup Program Manual (TSPM) during his absence and all other responsibilities specifically delegated.
14.2.2.3.3.3 CGS Test Group Supervisor. Test Group Supervisors are assigned lead technical responsibility for testing. General Test Group Supervisors duties are as follows:
: a.      Supervise the activities of assigned test engineers;
: b.      Review and, where appropriate, approve test procedures, field changes to procedures and test results, and make recommendations to the Test Group Managers or Startup Manager, as appropriate;
: c.      Set schedules and priorities for assigned Test Engineers and assist them with problem resolution; LDCN-99-000                                     14.2-7

COLUMBIA GENERATING STATION                          Amendment 54 FINAL SAFETY ANALYSIS REPORT                         April 2000
: d. With other Test Group Supervisors and the Test Group Manager or Startup Manager, as appropriate, plan and coordinate startup activities and provide assistance;
: e. Advise the Test Group Manager or Test and Startup, as appropriate, on all matters concerning testing within their group and if required, attend TWG meetings for this purpose;
: f. Act for the Test Group Manager or Test and Startup Manager, as appropriate, when so delegated;
: g. Prepare for and perform testing as required to support the Test and Startup Program;
: h. Coordinate the identification and documentation of design problems and their resolution, and
: i. Advise the Test Group Manager or Test and Startup Manager, as appropriate, regarding current and future manpower requirements impacting the testing effort.
14.2.2.3.3.4 CGS Test Engineers. Test engineers provide for the routine development and implementation of testing. General test engineer duties are as follows:
: a. Prepare assigned test procedures,
: b. Review tests and inspections prepared by others for application to assigned testing responsibilities,
: c. Provide direction during performance of system and component testing, and
: d. Identify problem areas and recommend actions where deficiencies could adversely affect performance of safety-related functions or operating efficiency.
14.2.2.4      Plant Operations Organization and the Power Ascension Test Program The PATP will be carried out by the plant operations organization using test procedures developed and approved according to the requirements of the PPM. The PATP procedures were prepared by members of the plant technical department under the supervision of the Reactor Engineering Supervisor. Technical expertise from other Energy Northwest organizations and from the General Electric Company (GE), the NSSS vendor, was used whenever necessary. Review of these procedures and scheduling of the test activities will be carried out by the POC and approved by the Plant Manager. The Reactor Engineering LDCN-99-000                                  14.2-8

COLUMBIA GENERATING STATION                       Amendment 53 FINAL SAFETY ANALYSIS REPORT                      November 1998 Supervisor will direct the PATP test engineers in the completion of testing according to the POC schedule.
14.2.2.5        Test Working Group 14.2.2.5.1       System Lineup and Preoperational Test Program The purpose of the TWG, a composite of representatives from organizations directly responsible for preparation, performance, and review of Test and Startup Program activities, is to provide a means for a coordinated review of all testing concerns and ensuring all obligations to the Test and Startup Program are met by the organizations represented.
The TWG provides review and approval of all activities proposed and the results thereof as appropriate. All decisions and approvals or recommendations of the group are included in the minutes of the meetings. Matters requiring approval by the TWG includes, but are not limited to
: a.      System lineup procedures,
: b.      Preoperational test procedures,
: c.      Changes to test procedures, and
: d.      Results of testing.
14.2.2.5.2           Membership and Responsibility of the Test Working Group The TWG membership consist of organizations that have a direct support function for conduct or development of testing.
The CGS Test and Startup Manager is Chairman of the TWG and is responsible for convening and conducting TWG meetings on the administrative and technical content of program activities.
The Test Group Manager is responsible for providing a technical review of the proposed activities, technical documents, and their results. The Test Group Manager serves as Chairman during the absence of the Test and Startup Manager.
The CGS Plant Manager is responsible for providing an operational review of test documents and for submitting safety-related documents to the POC for review and for communicating the committees decisions to the TWG. The Plant Manager provides detailed plant operating procedures and surveillance procedures to be used for plant operation and testing during the Test and Startup Program system lineup and preoperational test phase.
14.2-9

COLUMBIA GENERATING STATION                           Amendment 54 FINAL SAFETY ANALYSIS REPORT                          April 2000 The plant quality assurance representative to the TWG shall be responsible for review of proposed activities, test procedures, and test results as required by the Operational Quality Assurance Program Description (OQAPD).
The project engineering representative is responsible for obtaining a technical review of proposed activities and test documents by assigned project engineers and for providing a working relationship with Energy Northwest and architect-engineering organizations to aid resolution of testing concerns.
Conditional Members are representative of any organization having responsibility and/or expertise in the area of the TWG meeting agenda. In this situation the representative will be requested to attend the meeting by the TWG chairman.
14.2.2.6       Plant Organization Functions and Responsibilities During All Testing and Plant Operations The plant organization has overall responsibility for the safe and efficient operation of plant systems and equipment, from provisional acceptance through commercial operation including responsibility for maintenance and operational control. Plant organization responsibilities in supporting the Test and Startup Program are discussed in Section 14.2.2.7.1.
The responsibility of the plant organization representative to the TWG is defined in Section 14.2.2.5.2.
14.2.2.7       Energy Northwest Support of the Test and Startup Program 14.2.2.7.1          Plant Organization In addition to the responsibilities described in Section 14.2.2.6, the plant operating, technical, and maintenance sections provide manpower for development, implementation, and review of testing.
14.2.2.7.1.1 Support During Test and Startup Program Development. Assistance during the development of the Test and Startup Program is provided formally through the plant organizations TWG representative and through the POC. Input to test procedures and other testing documentation by the plant staff ensures that
: a. The operational requirements of the test procedures are based on the knowledge and experience of the operating staff,
: b. The technical considerations receive the review of the Plant Technical Staff, and LDCN-99-000                                   14.2-10

COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                           December 2003
: c.      Important nuclear and operational safety considerations receive attention by the plant organization.
14.2.2.7.1.2 Support During Testing. Detailed review and analysis of system lineup and preoperational test results will be performed by the plant technical section and/or plant operations section where their particular expertise is deemed necessary by the plant representative to the TWG to support approvals of completed system lineup and preoperational tests.
Detailed review and analysis of PATP test results will be carried out by the test engineers of the plant operations technical department and will receive final review through the POC and final approval by the Plant Manager.
14.2.2.7.2          CGS Program The CGS Program Director is responsible for the performance of the organizations involved in the design, procurement, and construction of generating projects. The Program Director supports the Test and Startup Program by providing and implementing project control systems, project engineering services, and engineering support services.
The CGS Program Director supports the Test and Startup Program by maintaining a high level of current status information available to the startup program organizations to ensure that all startup program scheduling and preparation is based on an accurate assessment of the condition of systems and equipment being readied for testing. The Program Director provides liaison with Construction Management for the provision of construction craft support for the implementation of various system lineup and preoperational tests.
14.2.2.7.3          Plant Quality Assurance The functions of the plant Quality Assurance organization during the Test and Startup Program will be to survey ongoing efforts to determine that the controls required by various regulations, guides, and standards are effectively implemented. The activities of the TWG will be monitored to ensure that the proper degrees of control for safety-related activities are being maintained and that required activities are completed when they are prerequisite to another testing activity.
14.2.2.8       Architect-Engineer Support of the Test and Startup Program Burns and Roe, Inc., is responsible for providing engineering services required to ensure timely completion of construction testing and equipment turnover for provisional acceptance and system turnover. Burns and Roe also provides system-oriented engineers to assist the CGS Test and Startup Divisions, as requested by Energy Northwest technical direction and/or advice and consultation during system and component testing through preoperational testing.
LDCN-02-000                                  14.2-11

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 14.2.2.9       General Electric Support of the Test and Startup Program General Electric is the supplier of the boiling water reactor (BWR) NSSS for the CGS plant.
General Electric is responsible for generic and specific CGS designs and for the supply of the NSSS. During the construction phase of the plant cycle, the GE Resident Site Manager is responsible for all NSSS equipment disposition. When the startup testing phase of the project begins after fuel load, the responsibility of GE-NSSS activities are assigned to the Preoperational and Startup group. The GE Preoperational and Startup staff responsibilities are outlined below.
14.2.2.9.1          Staff Responsibilities 14.2.2.9.1.1 General Electric Operations Manager. The GE Operations Manager is the senior NSSS vendor representative onsite at or near official fuel loading, and is the official site spokesman for GE for preoperational and startup testing concerns and requirements. The Operations Manager coordinates with the Startup Superintendent for the performance of his duties, which are as follows:
: a.      Reviewing all NSSS test procedures, including changes to test procedures, and test results as a conditional member of TWG and POC,
: b.      Providing technical direction to the station staff,
: c.      Managing the activities of the GE site personnel in providing technical direction to CGS personnel in the testing and operation of GE-supplied systems,
: d.      Providing liaison between the site and the GE San Jose home office to provide rapid and effective solution to problems that cannot be solved onsite,
: e.      Participating as a conditional member of the TWG when required, and
: f.      Reviewing test procedures for the POC.
14.2.2.9.1.2 General Electric Operations Superintendent. The GE Operations Superintendent is responsible to the GE Operations Manager for supervising the activities of GE Shift Superintendents. He works directly with the CGS Operations Manager in providing GE technical direction to the operating organization.
14.2.2.9.1.3 General Electric Shift Superintendents. The GE shift superintendents provide technical direction to CGS shift personnel in the testing and operation of GE-supplied systems.
They provide 24-hr per day shift coverage as required beginning with fuel loading. They report to the GE Operations Superintendent.
14.2-12

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 14.2.2.9.1.4 General Electric Lead Engineer - Startup Test, Design, and Analysis. The GE lead engineer - Startup Test, Design, and Analysis, is responsible to the GE Operations Manager for supervising the GE shift engineers and for verifying core physics parameters and characteristics and documenting that performance of the NSSS and components conform to test acceptance criteria.
The lead engineer works with the CGS technical department to coordinate and effect implementation of the PATP instrumentation including special test equipment required to confirm these acceptance criteria.
14.2.2.10      Qualifications of Personnel Supporting the Test and Startup Program The qualifications described in this section are for those persons having authority to direct testing, review and approve test documentation and results, or otherwise have direct influence on the conduct of testing and quality of acquired data. Although other personnel, specifically GE, Burns and Roe, and Energy Northwest technical specialists, are also involved in these processes, they are under the direction of individuals whose qualifications are described herein and who review and approve all Test and Startup Program activities.
14.2.2.10.1         Test and Startup Program Department Personnel Qualifications
: a.      At the time of appointment to the active position, the CGS Test and Startup Manager shall have 10 years of responsible thermal power plant experience such as, but not limited to, managerial, technical, or administrative positions, of which a minimum of 3 years shall be nuclear power plant experience.
A maximum of 4 years of the remaining 7 years of experience may be fulfilled by academic training on a one-to-one basis. This academic training shall be in engineering or the individual shall have acquired the experience and training normally required for examination by the NRC for a senior operator license whether or not the examination is taken.
: b.      Minimum qualifications for Test Group Manager are a B.S. degree in engineering or related field and 6 years of applicable experience, at least 3 of which are in testing or operation of nuclear power generation, propulsion, or similar scale test or production facilities. Related experience may be substituted for academic requirements when the candidates professional background and level of achievement clearly demonstrate capabilities to fill the position.
Previous preoperational testing experience is required. A good understanding of quality assurance and regulatory requirements and an ability to effectively communicate with others are necessities. A demonstrated technical leadership in his discipline and necessary work experience at the Test Group Supervisor or equivalent level is evidence of required proficiency.
14.2-13

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003
: c.      Minimum qualifications for Test Group Supervisor are a B.S. degree in engineering or related field and 5 years of applicable experience, at least 2 of which are in testing or operation of nuclear power generation, propulsion, or similar scale test or production facilities. Related experience may be substituted for academic requirements when the candidates professional background and level of achievement clearly demonstrate capabilities to fill the position.
Previous preoperational testing experience is required. A good understanding of quality assurance and regulatory requirements and an ability to effectively communicate with others are necessities. A demonstrated technical leadership in his discipline and necessary work experience at the Senior Test Engineer or equivalent level is evidence of required proficiency.
: d.      Minimum qualifications for a Test Engineer directing preoperational tests are a B.S. degree in engineering or related field or a graduate of a technical or vocational school in an engineering or related field and 2 years of related experience. Related experience above the required minimum may be substituted for academic requirements when the candidates record for performance clearly indicates the ability to fill the position without question. A good understanding of engineering principles and the ability to understand new concepts and to effectively communicate with others is a necessity.
Minimum requirements for a Test Engineer directing startup tests are a B.S.
degree in engineering or related field and 2 years of related experience or a graduate of a technical or vocational school in an engineering or related field, and 3 years of related experience. Related experience above the required minimum may be substituted for academic requirements when the candidates record for performance clearly indicates the ability to fill the position without question. A good understanding of engineering principles and the ability to understand new concepts and to effectively communicate with others is a necessity.
14.2.2.10.2        Plant Organization Personnel Qualifications Qualifications of some plant personnel are discussed in Section 13.1.3.
14.2.3     TEST PROCEDURES 14.2.3.1      Development of Test Procedures Test Procedures are developed by the CGS Test and Startup or Plant Operations Department to provide a detailed method to demonstrate the capability of the system to perform its design function under anticipated operating and accident condition.
14.2-14

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 General Electric Company as supplier of the NSSS provides test program specifications and instructions from which Energy Northwest prepares the preoperational and initial startup test procedures for systems supplied by GE.
Architect-Engineer and Vendors Technical assistance is provided by Burns and Roe and vendor technical representatives as deemed necessary.
14.2.3.1.1          Incorporation of Plant Procedures The following program will be implemented at CGS to utilize and qualify plant operating procedures during testing.
: a.      Plant procedures required to support testing will have been prepared and approved before preoperational testing begins on the system using the best information available from the principal designer and responsible equipment suppliers.
: b.      Preoperational test procedures will use plant operating and emergency procedures as nearly as possible.
: c.      Using the results of preoperational testing, including the use-testing of plant procedures where practical, the plant procedures required to support startup testing will be updated and revised before startup testing of applicable systems.
Exceptions to this program will be those approved plant procedures required to be verified during the startup phase.
: d.      Startup test procedures will be developed using the results of preoperational testing and updated plant procedures.
14.2.3.1.2          Format of Test Procedures 14.2.3.1.2.1 Preoperational Test Phase. The minimum content requirements for CGS Preoperational test procedures are specified in the Energy Northwest TSPM. The format for CGS test procedures is specified in the CGS TSPM. The resulting format and content is the following:
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COLUMBIA GENERATING STATION                              Amendment 57 FINAL SAFETY ANALYSIS REPORT                            December 2003
: a. Preoperational Test Procedure Format
: 1. Purpose A concise description of the objectives of the test, including such test requirements as component functions to be checked and testing under normal or simulated conditions to verify readiness for system startup and operation, and system tests to confirm that the performance of the system is in compliance with all applicable design requirements.
: 2. Prerequisites Provisions necessary for performance of the test. Conditions that should exist prior to start of the test. Instructions given to identify required operational status of the plant and interfacing systems, environmental conditions, and individual component status requirements, including verification of the following:
(a)      Components and systems being tested have been turned over and open deficiencies will not affect the performance of the test, (b)      System lineup testing on components, included in the test, is complete, (c)      Necessary support systems are available, and (d)      For control system testing, the other principal control systems are in appropriate operating modes for the given test conditions.
: 3. Limits and Precautions Special precautions required for safety of personnel and equipment or needed to ensure a meaningful test and satisfactory performance of testing.
: 4. Special Equipment A list of special material and equipment for the performance of the test.
: 5. Procedure A step by step procedure for performing the test. Plant operating procedures will be utilized whenever practicable for the operation of 14.2-16

COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                           December 2003 systems and equipment during testing and for returning the system to normal after completion of testing. Abnormal procedures will be utilized as required to supplement normal plant operating procedures. Data collection will be part of the procedure steps.
: 6. Restoration Includes those steps necessary to return the system to a normal operating or tagged status. This may include removal of special test instruments, temporary equipment, electrical jumpers, valve lineups, etc.
: 7. Acceptance Criteria The criteria against which the success or failure of the test will be judged must be identified. In some instances, these will be qualitative criteria, e.g., given event does or does not occur. In other cases, quantitative values can be designated as acceptance criteria.
(a)     All quantitative acceptance criteria shall include suitable tolerances, and (b)     A readily apparent correlation should exist to cross-reference among procedure steps, data, and acceptance criteria.
: 8. References A listing of all material required for the preparation and performance of the test. This should include piping and instrumentation drawings, electrical elementary drawings, vendor instruction manuals, applicable FSAR sections, contract specifications, and applicable codes, standards or guides, and applicable plant procedures.
14.2.3.1.2.2 Power Ascension Test Phase. All PATP procedures will be formatted according to the PPM.
14.2.3.2     Review of Test Procedures Each member of the TWG ensures test procedures will provide for review with respect to that members organizational area of responsibility. Power ascension test procedures will be reviewed by the POC.
Comments submitted by TWG members will be evaluated by the TWG and the test procedure revised accordingly. After discussion of the resulting version, the decision to reject, accept, or 14.2-17

COLUMBIA GENERATING STATION                        Amendment 57 FINAL SAFETY ANALYSIS REPORT                       December 2003 accept with modification, will be obtained by consensus of the membership of the TWG. In the event the TWG cannot reach a consensus, the Chairman shall provide resolution or a method for resolving the issue to the appropriate division management for review and concurrence.
The results of the POC review of PATP will be approved by the Plant Manager.
The qualifications of the individuals or organization representatives reviewing test procedures are described in Section 14.2.2.10.
The administrative procedures governing the test procedure review process are contained in the CGS TSPM. These procedures cover the mechanism for review and comment resolution, documentation of this review, and method of indication for the review status of a test procedure.
14.2.3.3       Approval of Test Procedures Test procedures will be approved by the TWG Chairman by means of consensus of the TWG membership after review of the test procedure as described in Section 14.2.3.2. Power ascension test procedures will be reviewed by the POC in a similar manner.
Individual test procedures will be approved by the chairman of the TWG or POC/Plant Manager, as appropriate. The consensus of the two committees were contained in the meeting minutes.
The administrative procedures governing the exercise of approval of test procedures are contained in the CGS TSPM or the PPM.
14.2.4      CONDUCT OF TEST PROGRAM 14.2.4.1       Administrative Procedures for Preoperational Testing 14.2.4.1.1           Test Performance Authorization A significant period of time may have elapsed between the time a preoperational test procedure was approved and the time a test is performed. The test procedure is therefore reviewed just prior to initiating the test. Any changes in the system since original approval of the test procedure will be thoroughly researched and the test procedure revised and approved in accordance with Sections 14.2.3.2 and 14.2.3.3. The CGS Test and Startup Manager will then approve the test procedure for performance of the test.
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COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                           December 2003 14.2.4.1.2          Preoperational Test Prerequisites Approval by the Test and Startup Manager to perform a preoperational test also requires consideration of the prerequisite testing required to qualify components and systems for operation. In general, completion of the system lineup testing (see Section 14.2.1.3) will qualify the system for preoperational testing. System lineup testing, as a prerequisite to preoperational testing, includes the following:
: a.      Instrumentation and protective relay checks, including calibration, setpoint adjustments, logic verification, and line checks;
: b.      Component operability checks, including valve stroking, motor rotation, ventilation system balancing, rotating equipment run-in and pipe support inspection and adjustment;
: c.      Flushing, including proof flushes, flow instrumentation response, and pump performance and capacity checks;
: d.      Electric component and system checks, including breaker trip setpoints; and
: e.      Hydrostatic or pneumatic pressure tests and systems where dynamic testing, such as pump runs, are required to allow performance of pressure tests.
Pressure integrity tests are otherwise performed during construction testing.
Verification that required system lineup tests have been or can be successfully completed prior to preoperational testing is performed by the respective test group manager prior to recommending turnover of a system or component from a contractor to Energy Northwest.
Verification that the system is actually ready for preoperational testing will be performed as described in Section 14.2.4.3.
14.2.4.1.3          Conduct of Preoperational Testing
: a.      Implementation responsibilities for scheduling all tests are assigned to the CGS Test and Startup Manager. The TWG will be kept informed of the scheduled activities.
: b.      The satisfaction of prerequisites to commencement of the test, as indicated in the test procedure, will be verified by the test engineer prior to performance of the test.
: c.      The assigned test engineer is responsible for directing the performance of each test. Testing is performed in direct coordination between the test engineer and shift supervision.
14.2-19

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003
: d. All testing will be conducted in accordance with approved test procedures. If, during the performance of a test the procedure is unacceptable, the test engineer can propose changes by use of a Test Change Notice (see Section 14.2.4.4).
This provided both documentation of the change and confirmation by the TWG.
: e. All test data will be entered on or attached to the record copy of the test procedure.
14.2.4.1.4          Deficiency Reporting Deficiencies or discrepancies identified during testing will be reported individually as described in Section 14.2.5.2.
Corrective action or satisfactory disposition shall be taken on all deficiencies and discrepancies in equipment and procedures prior to final approval of the preoperational test results. All deficiencies or discrepancies identified during the test, or which have not been resolved on completion of the test, will be recorded in the record copy of the preoperational test.
14.2.4.1.5          Equipment Maintenance and Modifications During Preoperational Testing Modifications or repair to safety-related systems will be implemented as a result of a formal system of problem and deviation reporting. Disposition of problems requiring mechanical or electrical changes or repairs by contractors will be implemented by work requests.
: a. Startup Problem Reports (SPR), Startup Deficiency Reports (SDR), and Startup Work Requests (SWR) are administered through closed-loop procedural controls to ensure resolutions. A completed SPR, SDR, and SWR is approved for closure by the respective Test Group Manager.
: b. Startup Problem Reports are used to report design deficiencies and are coordinated by the Energy Northwest project engineering organization for resolution by the responsible design organization or qualified alternate. The SPRs are reviewed by engineering and a Project Engineering Directive (PED) is issued to define plant modifications or changes that are required. An SWR is then issued to perform the plant modification by contractor personnel or an SDR is issued to defer the work or have it performed by startup personnel.
: c. Startup Deficiency Reports (SDR) are used to report and track non-design-related deficiencies. If required, an SWR will be issued to perform the repair work to resolve the non-design-related deficiency by contractor personnel. Work accomplished by startup personnel can be accomplished by the SDR without issuing an SWR.
14.2-20

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003
: d.      Retest requirements will be identified on the SWR or SDR and attached to, or referenced by the work request number in test files.
: e.      Startup Problem Reports, SDR, SWR, design change documentation, retest results, and procurement records for safety-related systems will be filed in assembled packages or with appropriate cross-referencing for retrievability.
14.2.4.1.6          Preoperational Test Summary During the preoperational test, the test engineer will prepare a test report which includes a summary of the conduct of the test, evaluation of the test results with reference to the acceptance criteria, and a description of problems encountered and corrective actions taken or proposed. This report will be attached to the record copy of the test.
14.2.4.1.7          Evaluation of Preoperational Test Data On completion of the test, a copy of the official test procedure, data, the test summary, and other applicable attachments will be transmitted to each member of the TWG responsible for review.
14.2.4.1.8          Preoperational Test Records The Test and Startup Manager will maintain all official test records (the copy of the test procedure containing the original test data and signatures and all attachments) until completion of the test program. See Section 14.2.6 for details of the test records handling and retention program.
14.2.4.2       Administrative Procedures for Power Ascension Testing 14.2.4.2.1          Plant Operation During Power Ascension Testing During initial startup tests and operations, the plant procedures are followed except as specifically modified by approved test procedures. In addition, special safety precautions and limitations are included in the test procedures. Approved test procedures will be used to control test conditions outside of the Technical Specifications limits where allowed for test purposes.
Certain individual tests or power escalations may require authorization by both the POC and the Plant Manager immediately prior to implementation and will be so identified in the applicable test procedure.
14.2-21

COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                           December 2003 The final authority to start or continue a test is the responsibility of the Shift Manager after all previous approvals have been exercised. Testing is performed in direct coordination between the test engineer and Shift Manager.
14.2.4.2.2           Power Ascension Test Scheduling and Sequencing Scheduling and sequencing of testing during startup is performed under the direction of the Plant Manager by POC.
The startup or power ascension test sequence is described in terms of individual test evolutions and specific power plateaus due to interfaces with other simultaneous tests, requirements for continuous data review, and plant administrative requirements for authorization to proceed or continue. The test sequence identifies hold points for data review and authorization to proceed and establishes the general plant conditions for each group of tests.
14.2.4.2.3           Power Ascension Test Performance Before starting each test, the assigned shift test engineer will review the test procedure to ensure that prerequisite activities of conditions have been satisfied as described in Section 14.2.4.3.
The test will be stopped or curtailed if it cannot be performed safely or in accordance with the approved test procedure. Required test procedure deviations or changes may be effected in accordance with PPM 1.2.3, Use of Plant Procedures, as described in Section 14.2.4.4.2.
Should apparent deviations of test results from performance requirements or acceptance criteria be revealed, or should other apparent anomalies develop, the plant will be placed in a safe condition and relevant test data will be reviewed by the test engineer and Shift Manager.
If the apparent discrepancy or anomaly is substantiated, the situation will be reviewed by the POC to ascertain if a plant safety question is involved. Control of any identified nonconformance or noncompliance will be in accordance with the plant administrative procedures.
Evaluation of the effect of the discrepancy or anomaly on plant safety will be performed at the appropriate level of review, and appropriate corrective actions will be taken before resumption of the test or test conditions at which the problem was revealed.
At the completion of an entire test procedure, the test engineer will assemble all of the data and supporting information, nonconformance documentation, and test results evaluations for review by the POC. Any data reduction or analysis required will be done as soon after the data is available as is practical so that the results of the analysis may be included in the complete test package.
14.2-22

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 Test records will be maintained as described in Section 14.2.6.
14.2.4.3       Control of Test Prerequisites Conditions and activities prerequisite to a given test will be identified in the applicable test procedure. Prior to commencement of the particular test, the test engineer will verify that the identified prerequisites have been satisfied. The verifications will be recorded and retained as part of the test record.
The test engineer will verify that
: a.      The test procedure has been approved by the appropriate committee and Plant Manager, Test and Startup Manager, or Startup Superintendent as required.
The test procedure is compatible with the latest versions of material referenced in the test procedure;
: b.      The record copy of the test procedure is identical to that contained in the master file or PPM, including the latest TWG/POC approved revisions or test procedure field changes (see Section 14.2.4.4);
: c.      Prerequisite tests have been completed. If TWG and/or Plant Manager approval of a completed test is also a prerequisite, that approval will have been obtained;
: d.      The test procedure has been made available for shift operator review and familiarization. Operator support has been scheduled, as necessary;
: e.      Test equipment is available or in place as required. Calibration or other readiness requirements have been completed. System instrumentation to be used in the test has been calibrated within the required time period established for surveillance testing and/or preventative maintenance; and
: f.      Test and operating personnel involved in the performance of the test have been briefed immediately prior to starting the test.
14.2.4.4       Modification of Test Procedures During Testing 14.2.4.4.1           System Lineup and Preoperational Test Phase The TSPM provides a means of controlling modifications to TWG-approved test procedures during testing. This administrative procedure, contained in the CGS TSPM, applies to changes made to an approved test procedure during preoperational and startup testing. The procedure does not apply to revisions made during the preparation of test procedures.
14.2-23

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 The procedure provides control of revisions which change the intent or the acceptance criteria of the test procedure.
The required changes, when identified by the responsible test engineer, are described on a special form (Test Change Notice/Procedure Deviation Form) which identifies the affected test procedure or plant procedure, justifies the change, and contains spaces for the appropriate approvals. The Test Change Notice forms became a permanent part of the test record.
A Test Change Notice for a preoperational test is reviewed by the TWG and approved by the Test and Startup Manger, TWG Chairman.
14.2.4.4.2          Power Ascension Test Phase All test procedure details or changes must be made in accordance with PPM 1.2.3, Use of Plant Procedures. This process requires documentation on the required forms, signatures of authorized individuals, and subsequent full POC review. The PPM 1.2.3 forms became a permanent part of the test record.
14.2.5      REVIEW, EVALUATION, AND APPROVAL OF TEST RESULTS 14.2.5.1       Control of Test Results Review The individuals responsible for reviewing the results of particular tests will be designated by the POC or the Test and Startup Manager. These reviews will be obtained through TWG or POC members in accordance with their represented areas of responsibility. TWG members will provide names of individuals in their represented organizations who meet the requirements of Regulatory Guide 1.58, Revision 0, for evaluation of inspection and test results.
Based on the recommendations of the qualified reviewers, the completed preoperational test will be approved by the TWG. Plant Operating Committee review and Plant Manager approval of power ascension test results is required.
14.2.5.2       Design Organization Participation in Problem Resolution Failures of tests to meet acceptance criteria and other problems discovered in the course of testing will be documented as deficiencies in accordance with the requirements of the TSPM for System Lineup and Preoperational Tests and in accordance with PPM 1.3.12, Plant Nonconformances, for the power ascension tests. Reports of such deficiencies will indicate the parties or organizations deemed responsible for providing an acceptable resolution of the deficiency. The responsible organization will be requested to provide a resolution of the defined problem.
14.2-24

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 Documentation of the final resolution will include the recommendation of the responsible organization and a description of the measures implemented in accordance with that recommendation. Design problems will require resolution by the appropriate Energy Northwest Technical Division Department, Project Engineering, Plant Technical Staff, or original design organization, depending on the technical nature of the problem.
14.2.5.3       Results Analysis Prerequisites to Continuation of Startup Testing The POC will establish prerequisites for various tests, test conditions, and test phases in consideration of system or component qualification for subsequent testing. The control or prerequisites to an individual test will be as described in Section 14.2.4.3.
The POC will also require an evaluation of the data acquired during a particular test phase or plateau. The items considered in this evaluation will include, but are not limited to the following:
: a.      The need for additional testing or retesting to improve assurance that a particular system or component will perform as required in subsequent testing, especially under more demanding conditions such as higher power levels,
: b.      The need for analysis of certain data to qualify measured variables or parameters for use in subsequent measurements,
: c.      The completeness of testing up to the point in question as evidenced by the documentation of the completed tests, and
: d.      The need for specific reviews and approvals of particular sets of data to satisfy the above.
14.2.6      TEST RECORDS 14.2.6.1       System Lineup and Preoperational Test Phase 14.2.6.1.1          General The TSPM contains a generic procedure regarding filing and recordkeeping to be applied to testing documentation. This procedure is intended to ensure compliance of Energy Northwest project startup programs with the applicable provisions of ANS N45.2.9-1974, Requirements for Collection, Storage, and Maintenance of Nuclear Power Plant Quality Assurance Records, as required by Regulatory Guide 1.88, Revision 1, December 1975.
The following sections describe the provisions of the aforementioned procedure, which will be contained in specific detail in the CGS Test and Startup Instructions.
14.2-25

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 14.2.6.1.2          Test Record Responsibilities The Test and Startup Manager is responsible for identifying the responsibilities, controls, and requirements for establishing and implementing a Test and Startup Program filing and recordkeeping system, in accordance with 10 CFR 50 Appendix B, ANSI N45.2.9, and the Energy Northwest Quality Assurance Program Manual. The Test and Startup Manager will ensure that adequate procedures are prepared and maintained within the Test and Startup Instructions. The Test and Startup Manager will ensure that trained and qualified personnel maintain the Test and Startup Program files.
14.2.6.1.3          Types of Documents and Records Requiring Test Record File Retention Documentation and records that will be maintained within Test and Startup Program files are:
: a. Test and Startup program records as specified by ANSI N45.2.9, and
: b. All records and documents as specified by the Test and Startup Program and instruction manuals.
Other records, documents, correspondence, etc., may be maintained at the discretion and approval of the Startup Program Manager, provided their access requirements do not compromise the security of the mandatory files.
14.2.6.2       Power Ascension Test Phase All test records and data shall be kept and filed in accordance with the PPM 1.6 series of procedures which detail the requirements for all plant recordkeeping.
14.2.7      CONFORMANCE OF TEST PROGRAMS WITH REGULATORY GUIDES 14.2.7.1       Conformance with Regulatory Guide 1.68 The CGS Test and Startup Program conforms to the requirements of Regulatory Guide 1.68, Revision 0, Preoperational and Initial Startup Test Programs for Water-Cooled Power Reactors, except where specifically noted otherwise. The Regulatory Guide has been reviewed by Energy Northwest for applicability of individual items in the guide to CGS and its systems. The applicability to this plant has determined the nature and scope of testing to be performed. Actual exceptions to the testing required by this guide have been specifically addressed and are discussed in Section 14.2.7.2. Areas where the guide does not apply are not considered to be exceptions.
14.2-26

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 14.2.7.2        Exceptions to Regulatory Guide 1.68 The exceptions to Regulatory Guide 1.68 are listed below with an explanation of the justification for the exception.
: a.      Exception to Format of Test Procedures The format of the test procedures is different from that found in Appendix C of Regulatory Guide 1.68, but the format difference is not considered an exception to the regulatory guide since the guide specifies required elements of a test procedure while merely implying but not requiring a format.
: b.      See Section 1.8.2 for a delineation of specific exceptions to the requirements of Regulatory Guide 1.68.
14.2.7.3        Conformance With or Exceptions to Regulatory Guides Other Than 1.68
: a.      Regulatory Guide 1.70, Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants will be complied with for the section that pertains to the Test and Startup Program,
: b.      Regulatory Guide 1.33, Quality Assurance Program Requirements will be complied with in Quality Assurance During the Operations Phase, Section 17.2, of the FSAR for the Test and Startup Program,
: c.      All other regulatory guides pertaining to individual testing will be complied with unless noted otherwise in Section 14.2.12, and
: d.      Regulatory Guide 1.58 Qualifications of Nuclear Power Plant Inspection, Examination, and Testing Personnel. Energy Northwest Test and Startup personnel involved in testing meet the requirements of Regulatory Guide 1.58.
14.2.8      UTILIZATION OF REACTOR OPERATING AND TESTING EXPERIENCES IN THE DEVELOPMENT OF THE TEST PROGRAM As a matter of Energy Northwest policy, a continuous program of review of reactor operating experience is coordinated by the Operations Division of Energy Northwest. The sources of information reviewed in compliance with this policy are NRC Information Notices and Bulletins, operating experience reports, preoperational test summaries and startup reports from other plants, administrative and test procedures from other plants startup programs, personal contacts with other nuclear plant licensees or applicants, and additional information supplied by Energy Northwest Technical and Operations Division members. All available sources are 14.2-27

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 utilized; relevance to particular Energy Northwest nuclear projects is determined in the review process.
The information is reviewed by CGS Startup Program personnel for applicability to the CGS Test and Startup Program, for incorporation into test procedures, or for consideration in the administrative control of testing.
14.2.9      TRIAL USE OF PLANT OPERATING AND EMERGENCY PROCEDURES To the extent practical throughout the preoperational and initial PATP, test procedures utilize operating, emergency, and abnormal procedures where applicable in the performance of tests.
The use of these procedures is intended to do the following:
: a.      Prove the specific procedure or illustrate changes which may be required,
: b.      Provide training of plant personnel in the use of these procedures, and
: c.      Increase the level of knowledge of plant personnel on the systems being tested.
Test procedures may use operating, emergency, and abnormal procedures in several ways: the test procedure may reference the procedure directly; the test procedure may extract a series of steps from the procedure; the test procedure may use a combination of the first two methods; or the test procedure may require system and plant conditions that will be obtained by the use of plant operating or emergency procedures.
14.2.10     INITIAL FUEL LOADING AND INITIAL CRITICALITY 14.2.10.1      Fuel Loading and Shutdown Power Level Tests Fuel loading and initial criticality is conducted in accordance with written procedures after all prerequisite tests are satisfactorily completed and an operating license has been issued. Prior to approving fuel loading, the plant must be verified as ready to load fuel. This verification is accomplished by the following steps, which are performed at the completion of a majority of the preoperational testing.
14.2.10.1.1         Loss of Power Demonstration-Standby Core Cooling Required This test demonstrates the capability of each emergency diesel generator to start automatically and assumes all of its emergency core cooling loads in a loss of normal auxiliary power.
14.2.10.1.2         Cold Functional Testing The cold functional testing defined here is an integrated system operation of various plant systems that can be operated as systems prior to fuel loading. The intent is to observe any unexpected operational problems from either an equipment or a procedural source and to 14.2-28

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 provide an opportunity for operator familiarizations with the system-operating procedures under operating conditions.
Some of the cold functional testing will be accomplished during the preoperational test program. For example, integrated and simultaneous operation of the following systems may take place during the flush of the total system: condensate system, condensate demineralizer system, low-pressure coolant injection (LPCI) system, core spray system, reactor water cleanup (RWCU) system, service water system, closed cooling water (RCC) system, and others.
As required, additional integrated systems performance will be demonstrated prior to fuel loading.
14.2.10.1.3          Routine Surveillance Testing Because of the interval between completion of a preoperational test on a system and the requirement for that system to be operated may be of considerable length, a number of routine surveillance tests must be performed prior to fuel loading and must be repeated on a routine basis. The Technical Specifications described the test frequency. In general, this Surveillance Test Program (specified in the Technical Specifications) is instituted prior to fuel loading by the plant operating staff.
14.2.10.1.4          Master Startup Checklist A detailed list of items that must be complete, including the preoperational tests, work requests, design changes, and proper dispositioning of all exceptions noted during preoperational testing listed in Table 14.2-1 is rechecked to verify completion just prior to the final approvals for fuel loading and at each significant new step such as heat up, opening main steam isolation valves (MSIVs), and power operation.
14.2.10.1.5          Initial Fuel Loading Fuel loading requires the movement of the full core complement of assemblies from the fuel pool to the core, with each assembly identified by number before being placed in the correct coordinate position. The procedure controlling this movement is arranged so that shutdown margin and subcritical checks are made at predetermined intervals throughout the loading, thus ensuring safe loading increments. Specially sensitive invessel neutron monitors that are maintained at the loading face as loading progresses serve to provide indication for the shutdown margin measurements, and also to allow the recording of the core flux level as each assembly is added. A complete check is made of the fully loaded core to ascertain that all assemblies are properly installed, correctly oriented, and are occupying their designated positions.
14.2-29

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 14.2.10.1.6          Zero Power Level Tests At this point in the program, a number of tests are conducted which are best described as initial zero power level tests. Chemical and radiochemical tests are made to check the quality of the reactor water before fuel is loaded, and to establish base and background levels required to facilitate later analysis and instrument calibrations. Plant and site radiation surveys are made at specific locations for later comparison with the values obtained at the subsequent operating power levels. Shutdown margin checks are repeated for the fully loaded core, and criticality is achieved with each of the two prescribed rod sequences in turn, the data being recorded for each rod withdrawn. Each rod drive is subjected to scram and performance testing. The initial setting of the intermediate range monitors (IRMs) is at maximum gain.
14.2.10.2       Initial Heatup to Rated Temperature and Pressure Heatup follows the satisfactory completion of the fuel loading and zero power level tests (Sections 14.2.10.1.5 and 14.2.10.1.6) and further checks are made of coolant chemistry together with radiation surveys at the selected plant locations. All control rod drives (CRDs) are scram-timed at rated temperature and pressure, with selected drives timed at two intermediate reactor pressures and for different accumulator pressures. The process computer checkout continues as more process variables become available for input. The reactor core isolation cooling (RCIC) system will complete controlled starts at low reactor pressure and at rated conditions, with testing in the quick-start mode at 150 psig and 1000 psig. Correlations are obtained between reactor vessel temperatures at several locations and the values of other process variables as heatup continues. The movements of NSSS piping in the drywell mainly as a function of expansion are recorded for comparison with design data.
14.2.10.3       Power Testing From 25% to 100% of Rated Output The power test phase comprises the following tests, many of which are repeated several times at the different test levels; consequently, see Table 14.2-4 for the series. While a certain basic order of testing is maintained relative to power ascension, there is, nevertheless, considerable flexibility in the test sequence at a particular power level which may be used whenever it becomes operationally expedient. In no instance, however, is nuclear safety compromised.
: a.      Coolant chemistry tests and radiation surveys are made at each principal test level to preserve a safe and efficient power increase,
: b.      Selected CRDs are scram-timed at various power levels to provide a correlation with the initial data,
: c.      The effect of control rod movement on other parameters (e.g., electrical output, steam flow, and neutron flux level) is examined for different power conditions, 14.2-30

COLUMBIA GENERATING STATION                            Amendment 59 FINAL SAFETY ANALYSIS REPORT                           December 2007
: d. Following the first reasonable, accurate heat balance (25% power) the average power range monitors (APRMs) are calibrated and IRMs are reset if necessary,
: e. At each major power level (25%, 60%, and 100%), the local power range monitors (LPRMs) are calibrated,
: f. The APRMs are calibrated initially at each new power level and following LPRM calibration,
: g. Completion of the process computer checkout is made for all variables, and the various options are compared with hand calculations as soon as significant power levels are available,
: h. Further tests of the RCIC are made with and without injection into the reactor pressure vessel (RPV),
: i. Collection of data from the system expansion tests is completed for those piping systems which had not previously reached full operating temperatures,
: j. The axial and radial power profiles are explored fully by means of the traversing in-core probe (TIP) system at representative power levels during the power ascension, and
: k. Core performance evaluations are made at all test points above the 10% power level and for selected flow transient conditions; the work involves the determination of core thermal power, maximum fuel rod surface heat flux, and minimum critical power ratio (MCPR), and other thermal parameters.
: l. Overall plant stability in relation to minor perturbations is shown by the following group of tests which are made at selected test points:
: 1.      Core power-void mode response,
: 2.      Pressure regulator setpoint change,
: 3.      Water level setpoint change,
: 4.      Turbine valve surveillance, and
: 5.      Recirculation flow setpoint change.
For the first of these tests, a centrally located control rod is moved and the flux response is noted on a selected LPRM chamber. The next two tests require that the changes made should approximate as closely as possible a step change in demand, while for the next test the turbine stop, control, and bypass valves are opened to verify stability and power level for surveillance testing. The remaining test is performed to properly adjust the control loop of the LDCN-06-000                                 14.2-31

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 recirculation system. For all of these tests the plant performance is monitored by recording the transient behavior of numerous process variables, the one of principal interest being neutron flux. Other imposed transients are produced by step changes in demand core flow, partial loss of feedwater heating, and simulating failure of the operating pressure regulator to permit takeover by the backup regulator. Table 14.2-3 shows the power and flow levels at which all these stability tests are performed.
: m. The category of major plant transients includes full closure of all the MSIVs, fast closure of turbine generator control valves, fast closure of turbine generator stop valves, loss of the main generator and offsite power, tripping a feedwater pump, and several trips of the recirculation pumps. The plant transient behavior is recorded for each test and the results may be compared with the acceptance criteria and the predicted design performance. Table 14.2-2 shows the operating test condition for all the proposed major transients;
: n. A test is made of the relief valves in which leaktightness and general operability are demonstrated;
: o. At some major power levels the jet pump flow instrumentation is calibrated;
: p. The as-built characteristics of the recirculation system are investigated as soon as operating conditions permit full core flow; and
: q. The local control loop performance, based on the drive pump, jet pumps, and control equipment is checked.
14.2.11    TEST PROGRAM SCHEDULE The test program schedule for preoperational and startup tests are indicated in Table 14.2-4 and Figure 14.2-4. These schedules are preliminary and will be adjusted to consider actual construction and testing progress; they are included to provide general information but are not considered to be identical to the schedules in use during the startup program. The test procedures will be made available for review at least 30 days prior to the test date or fuel load.
14.2.12    INDIVIDUAL TEST DESCRIPTIONS 14.2.12.1     Preoperational Test Procedures The following general descriptions are the specific objectives of each preoperational test.
During the final construction phase, it may be necessary to modify the preoperational test methods as operating and preoperational test procedures are developed. Consequently, methods described in the following descriptions are general, not specific.
14.2-32

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 Specific acceptance criteria for each preoperational test are in accordance with the detailed system and equipment specifications for equipment in those systems. The tests demonstrate that the installed equipment and systems perform within the limits of these specifications.
In addition to the prerequisites listed on each on the following preoperational tests, there will be electrical power available to each of the systems.
Table 14.2-1 lists the preoperational tests anticipated for this facility.
14.2.12.1.1          Reactor Feedwater System Preoperational Test
: a.      Purpose To verify the operation of the reactor feedwater system, including pumps, valves, turbines, turbine auxiliaries, and turbine control systems.
: b.      Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The condensate system, control air system, and service water system must have a readiness verification.
: c.      General Test Methods and Acceptance Criteria The performance of the reactor feedwater system is verified within the limitations of the auxiliary steam supply by the demonstration of the proper operation of the following:
: 1.       Valves and related controls, interlocks, and position indicators,
: 2.       Reactor feedwater pumps, turbines, and auxiliaries,
: 3.       Control logic, and
: 4.       Annuciators and protective devices.
14.2.12.1.2          Condensate System Preoperational Test
: a.      Purpose To verify the operation of the condensate system, including pumps, valves, and control systems.
14.2-33

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The condenser, condensate filter demineralizers, feedwater, and control air systems are capable of supporting this test as necessary.
: c. General Test Methods and Acceptance Criteria The performance of the condensate system is verified by the demonstration of the proper operation of the following:
: 1.       Valves and related controls, interlocks, and positions indicators,
: 2.       Condensate pumps, condensate booster pumps and auxiliaries,
: 3.       Control logic, and
: 4.       Annuciators and protective devices.
14.2.12.1.3      Fire Protection System Preoperational Test
: a. Purpose To verify the operation of the fire protection system including the diesel engine, pumps, valves, detection and alarm circuits, and control and instrumentation circuits. To verify the location and status of all portable equipment.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The circulating water system, control and service air system, and electrical distribution system are available to support operation.
: c. General Test Methods and Acceptance Criteria Verification of the fire protection system capability is demonstrated by the proper integrated operation of the following:
: 1.       Diesel engine and pump operation and related control and logic,
: 2.       Fire alarm and detection circuits,
: 3.       Fire control panel in the main control room,
: 4.       Deluge, wet pipe and preaction sprinkler systems, and
: 5.       Carbon dioxide and Halon systems.
14.2-34

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 In addition, portable equipment and hose station capability will be verified.
14.2.12.1.4      Reactor Water Cleanup System Preoperational Test
: a. Purpose To verify the operation of the RWCU system, including pumps, valves, and filter/demineralizer equipment.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Filter aid, and anion and cation resin should be available.
The RCC system and instrument air system must have readiness verification.
: c. General Test Methods and Acceptance Criteria Verification of the RWCU system capability is demonstrated by the proper integrated operation of the following:
: 1.       Drain flow regulator flow interlocks,
: 2.       System isolation and logic,
: 3.       Valve-operating sequence,
: 4.       Pump operation and related control and logic,
: 5.       Annuciators, and
: 6.       Filter/demineralizer system operation.
14.2.12.1.5      Standby Liquid Control System Preoperational Test
: a. Purpose To verify the operation of the standby liquid control (SLC) system including pumps, tanks, control, logic, and instrumentation.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Valves should be previously bench tested and other precautions relative to positive displacement pumps taken. The reactor vessel should be available for injecting demineralized water.
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COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003
: c. General Test Methods and Acceptance Criteria Verification of the SLC system capability is demonstrated by the proper integrated operations of the following:
: 1.       SLC system tank level instrumentation,
: 2.       Heaters,
: 3.       Alarms and logic,
: 4.       Relief valves,
: 5.       Pumps and related controls and logic, and
: 6.       Flow testing with different flow paths.
14.2.12.1.6      Nuclear Boiler System Preoperational Test
: a. Purpose To verify proper operation of the nuclear boiler system including safety/relief valves (SRVs) and related controls and logic.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Verify that all SRVs have been previously bench tested.
: c. General Test Methods and Acceptance Criteria Functional and capacity tests of SRVs are not performed; verification of the NSSS capability is demonstrated by the proper integrated operation of the following:
: 1.       System valves and related sensors and logic,
: 2.       Vacuum breaker in relief valve discharge lines,
: 3.       Automatic isolation function of reactor water sample isolation valves,
: 4.       Isolation and leak detection systems,
: 5.       Automatic depressurization system logic,
: 6.       Reactor vessel actuators accumulator capacity test,
: 7.       Safety/relief valves air piston operation,
: 8.       Reactor head seal leak detection, and
: 9.       Alarms and annunciators.
14.2-36

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 14.2.12.1.7      Residual Heat Removal System Preoperational Test
: a. Purpose To verify the operation of the residual heat removal (RHR) system under its various modes of operation: LPCI, shutdown cooling and vessel head spray, containment spray, and suppression pool water cooling.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The RHR service water system must have readiness verification. The reactor vessel and recirculation loops shall be intact and capable of receiving water.
: c. General Test Methods and Acceptance Criteria Verification of the RHR system capability is demonstrated by the proper integrated operation of the following:
: 1.       System isolation valve control and logic tests,
: 2.       RHR and RHR service water pump and motor operation, controls, and related logic features,
: 3.       Automatic LPCI initiation logic,
: 4.       Verification of all flow paths. The time from initiation signal to full flow should be verified, and
: 5.       Alarms and annunciators.
14.2.12.1.8      Reactor Core Isolation Cooling System Preoperational Test
: a. Purpose To verify the operation of the RCIC system including turbine, pump, valves, instrumentation, and control.
14.2-37

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The turbine, disconnected from the pump, shall be tested.
The turbine instruction manual shall be reviewed in detail in order that precautions relative to turbine operation are followed. Then the system shall be tested within the capability of a temporary steam supply with the pump coupled to the turbine.
: c. General Test Methods and Acceptance Criteria
: 1.       All valves and related controls, interlocks, and indicators,
: 2.       Manual and automatic initiation,
: 3.       Automatic isolation, including leak detection system logic,
: 4.       Turbine speed control, trip, mode selection, and test mode,
: 5.       Barometric condenser condensate pump, and vacuum pump controls,
: 6.       Flow path verification, and
: 7.       Annunciators.
14.2.12.1.9      Reactor Recirculation System and Control Preoperational Test
: a. Purpose To verify the operation of the reactor recirculation system including pumps and their associated motors, valves, instrumentation, and controls. The rated conditions tests will be conducted during the startup testing program.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The RCC system must receive readiness verification. All required testing of equipment up to the operation of the recirculation pump has been completed, including recirculation pump motor (uncoupled) and all control loops.
: c. General Test Methods and Acceptance Criteria After prerequisite testing, verification of system capability is demonstrated by the proper integrated operation of the following:
: 1.       System valves, 14.2-38

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003
: 2.       Logic and interlocks,
: 3.       Recirculation pumps, valves, and related controls and interlocks,
: 4.       Annunciators, and
: 5.       Low frequency motor generator (LFMG) set.
14.2.12.1.10      Reactor Manual Control System Preoperational Test
: a. Purpose To verify the operation of the reactor manual control (RMC) system, including relays, control circuitry, switches and indicating lights, and control valves.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The CRD pump will not be operational during this test.
: c. General Test Methods and Acceptance Criteria Verification of RMC system capability is demonstrated by the proper integrated operation of the following:
: 1.       Rod blocks, alarms, and interlocks for all modes of the reactor mode switch,
: 2.       Rod position information system,
: 3.       Rod drift alarm circuit, and
: 4.       Rod directional control valve time sequence for insert and withdraw commands.
14.2.12.1.11      Control Rod Drive Hydraulic System Preoperational Test
: a. Purpose To verify the operation of the CRD hydraulic system including CRD mechanisms, hydraulic control units, hydraulic power supply, instrumentation, and controls.
14.2-39

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The CRD manual control system preoperational test must be completed on associated CRDs. The RCC system and instrument air system must receive readiness verification.
: c. General Test Methods and Acceptance Criteria Verification of CRD system capability is demonstrated by the proper integrated operation of the following:
: 1.       Logic and interlocks,
: 2.       CRD pumps and related controls and interlocks,
: 3.       Flow controller, pressure control valves, and stabilizer valves,
: 4.       Scram discharge level switches and CRD position indication, alarms, and interlocks,
: 5.       CRDs functional testing including latching and position indication,
: 6.       Scram testing of control rods at atmospheric pressure, and
: 7.       Annunciators.
14.2.12.1.12      Fuel Handling and Vessel Servicing Equipment Preoperational Test
: a. Purpose To verify the operation of the fuel handling and vessel servicing equipment including tools used in the servicing of control rods, fuel assemblies, LPRMs and dry tubes, and vacuum cleaning equipment.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Additionally, the refueling platform, fuel preparation machine, and fuel racks must be installed and operational; all slings and lifting devices must be certified at their design load, at least by the vendor.
14.2-40

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003
: c. General Test Methods and Acceptance Criteria Verification of the fuel handling and vessel servicing equipment is demonstrated by dry operation of the following equipment:
: 1.       Cell disassembly tools,
: 2.       Channel replacement tools,
: 3.       Instrument handling tools,
: 4.       Vacuum cleaning equipment,
: 5.       Interlocks and logic associated with the refueling and service platform are verified, and
: 6.       Proper operation of refueling and service platforms are verified.
14.2.12.1.13      Low-Pressure Core Spray System Preoperational Test
: a. Purpose To verify the operation of the low-pressure core spray system (LPCS), including spray pumps, sparger ring, spray nozzles, controls, valves, and instrumentation.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The reactor vessel must be available and ready to receive water.
: c. General Test Methods and Acceptance Criteria Verification of the LPCS system capability is demonstrated by the proper integrated operation of the following:
: 1.       Logic and interlocks,
: 2.       Low-pressure core spray system pumps, including auto initiation, 14.2-41

COLUMBIA GENERATING STATION                             Amendment 57 FINAL SAFETY ANALYSIS REPORT                            December 2003
: 3.       Flow path verification, including determination of system hydraulic performance to verify proper sizing of restricting orifice in LPCS discharge line to vessel (see Section 6.3.2.2.3),
: 4.       Annunciators,
: 5.       The time for initiation signal to full flow should be verified, and
: 6.       Photographs to prove acceptability of core spray patterns.
14.2.12.1.14      High-Pressure Core Spray System Preoperational Test
: a. Purpose To verify the operation of the high-pressure core spray (HPCS) system, including diesel generator and related auxiliary equipment, pumps, valves, instrumentation, and control.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The HPCS diesel generator must be installed and be operational.
: c. General Test Methods and Acceptance Criteria Verification of HPCS system capability is demonstrated by the proper integrated operation of the following:
: 1.       Valve controls and interlocks,
: 2.       HPCS electrical system tests, including dc and ac,
: 3.       HPCS diesel generator functional tests including starting, rated load, load rejection,
: 4.       Pump and motor tests with normal power supply and with diesel generator,
: 5.       HPCS flow path and flow rate verification,
: 6.       Annunciators, 14.2-42

COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                           December 2003
: 7.       The time from initiation signal to full flow should be verified, and
: 8.       Photographs to prove acceptability of HPCS spray pattern.
14.2.12.1.15      Fuel Pool Cooling and Cleanup System Preoperational Test
: a. Purpose To verify the operation of the fuel pool cooling and cleanup system including the pumps, heat exchangers, controls, valves, and instrumentation.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The instrument air, service air, fuel pool emergency makeup, service water, and RHR systems must be available.
: c. General Test Methods and Acceptance Criteria Verification of the fuel pool system capability is demonstrated by the integrated operation of the following:
: 1.       Logic and interlocks,
: 2.       Interconnection to RHR system,
: 3.       Pump operation and related controls,
: 4.       Cleanup subsystem operation, and
: 5.       Annunciators.
14.2.12.1.16      Leak Detection System Preoperational Test
: a. Purpose To summarize the test requirements and verify the leak detection test data for each of the nuclear systems.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The prerequisites are included in the preoperational test specifications for each of the nuclear systems listed below.
14.2-43

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003
: c. General Test Methods and Acceptance Criteria As an integral part of each of the following system preoperational tests, the nuclear systems leak detection is verified by the proper operation of the leak detection features of the following nuclear systems:
: 1.       Feedwater control system,
: 2.       RWCU system,
: 3.       NSSS,
: 4.       RHR system,
: 5.       RCIC system,
: 6.       Recirculation system, and
: 7.       Radwaste system.
14.2.12.1.17      Liquid and Solid Radwaste System Preoperational Test
: a. Purpose To verify that the radioactive waste system will perform its design functions of processing liquid and solid radioactive wastes.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing.
: c. General Test Methods and Acceptance Criteria Testing will demonstrate that the pumps, tanks, controls, and valves including automatic isolation, diversion and protection features, and instrumentation and alarms will operate and function in accordance with design requirements.
Testing will also verify that the CGS Process Control Program results in an acceptable waste form as required by 10 CFR 61. Simulated waste will be verified to form a free-standing monolithic solid with no free liquid prior to implementation of the solidification process on radioactive waste. Liners containing solidified waste will be inspected prior to shipment to the disposal site to verify compliance with 10 CFR 61 requirements.
14.2-44

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 14.2.12.1.18      Reactor Protection System Preoperational Test
: a. Purpose To verify the proper operation of the reactor protection system (RPS), including sensor logic and their respective scram relays, scram reset time delay, the annunciators, and motor generator set power supply.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing.
: c. General Test Methods and Acceptance Criteria Verification of the RPS capability is demonstrated by the proper integrated operation of the following:
: 1.       Motor generator set performance,
: 2.       Sensor logic and scram relay logic,
: 3.       Scram reset time delay,
: 4.       Sensors input-to-scram trip actuator response time on all channels of each function for which response times are required by the Technical Specifications,
: 5.       Annunciators,
: 6.       Mode switch tests, and
: 7.       Auxiliary sensor operation.
The ability of the system to scram the reactor within a specified time must be demonstrated in the CRD hydraulic system preoperational test (see Section 14.2.12.1.11).
14.2-45

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 14.2.12.1.19      Neutron Monitoring System Preoperational Test
: a. Purpose To verify the operation of the neutron monitoring system (NMS) including startup, intermediate, and power range detectors, and their related equipment.
: b. Prerequisites The system lineup tests have been complete, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Additionally, all source range monitors (SRMs) and pulse preamplifiers, IRMs and voltage preamplifiers, and APRMs will have been calibrated according to the vendors instructions.
: c. General Test Methods and Acceptance Criteria Verification of the NMS capability is demonstrated by the proper integrated operation of the following:
: 1.       All SRM detectors, and their respective insert and retract mechanisms, and cables;
: 2.       SRM channel including pulse preamp, remote meter and record, trip logic, logic bypass and related lamps and annunciators, control system interlocks, refueling instrument trips, and power supply;
: 3.       All IRM detectors and their respective insert and retract mechanisms and cables;
: 4.       IRM channels including voltage preamps, remote recorders, RMC system interlocks, RPS trips, annunciators and lamps, and power supplies;
: 5.       All LPRM detectors and their respective cables, and power supplies;
: 6.       All APRM channels including trips, trip bypasses, annunciators and lamps, remote recorders, RMC system interlocks, RPS trips, and power supplies;
: 7.       Recirculation flow bias signal including flow unit, flow transmitters, and related annunciators, interlocks, and power supplies, and 14.2-46

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003
: 8.       Both rod block monitor (RBM) channels including trips, trip bypasses, annunciators and lamps, remote recorders, RMC system interlocks, and power supplies.
14.2.12.1.20      Traversing In-Core Probe System Preoperational Test
: a. Purpose To verify the operation of the traversing in-core probe (TIP) system including the TIP detector, controls and interlocks, containment secure lamp, and containment isolation circuits.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. (Additionally, the TIP detector and dummy detector, ball valve time delay, core top and bottom limits, clutch, x-y recorder, and purge system will have been shown to be operational.)
: c. General Test Methods and Acceptance Criteria With the exception of the shear valve, which is not tested, verification of the TIP system is demonstrated by the proper integrated operation of the following:
: 1.       Indexer cross-calibration interlock,
: 2.       Shear valve control monitor lamp, and
: 3.       Drive motor manual control and override, automatic control and stop, and low speed control.
14.2.12.1.21      Rod Worth Minimizer System Preoperational Test
: a. Purpose To verify the operation of the rod worth minimizer (RWM) system under its various modes of operation.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the 14.2-47

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 initiation of testing. Additionally, the rod position indication system (RPIS) will have been shown to be operational, rod sequence control (RSC) system bypassed, and computer diagnostic and special tests completed.
: c. General Test Methods and Acceptance Criteria Verification of the RWM system is demonstrated by the proper integrated operation of the following:
: 1.       Rod test option,
: 2.       System initialization both above and below the low power setpoints, and above and below the low power alarm points,
: 3.       RWM program,
: 4.       Rod withdrawal and insertion error block, and
: 5.       Rod drift scan, and annunciation.
The RWM program acceptance of an operator-supplied rod position value must be demonstrated.
14.2.12.1.22      Process Radiation Monitoring System Preoperational Test
: a. Purpose To verify the operation of the process radiation monitoring (PRM) system, including the offgas vent, offgas, main steam line, liquid process, and building ventilation radiation monitoring subsystems.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Additionally, the process radiation monitors, pulse preamplifiers, power supplies, indicator and trip units, are calibrated.
Insulation resistance and high potentiometer tests will have been completed.
14.2-48

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003
: c. General Test Methods and Acceptance Criteria Verification of the PRM system is demonstrated by the proper integrated operation of the following:
: 1.       Vent preamps, channels, trip points, annunciators and lamps, sample rack, and check source,
: 2.       Offgas vial sampler, log radiation monitor (LRM) and their related annunciators, lamps and recorders, and high/low flow detector,
: 3.       Main steam and LRM channels, trip points, and annunciators and lamps, High-High and Inop trip, and recorders,
: 4.       Liquid process preamps, channels, trip points, and annunciators and lamps, and recorders,
: 5.       Building ventilation system sensors, channels, trip points, and annunciators and lamps, recorders, and SGTS interlock, and
: 6.       Control center air monitoring sensors, channels, annunciators, and indicators.
14.2.12.1.23      Area Radiation Monitoring System Preoperational Test
: a. Purpose To verify the operation of the area radiation monitoring (ARM) system, including channels, trip points, alarms, and recorder.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Additionally, indicator, trip units, and power supplies are calibrated.
14.2-49

COLUMBIA GENERATING STATION                        Amendment 57 FINAL SAFETY ANALYSIS REPORT                       December 2003
: c. General Test Methods and Acceptance Criteria Verification of the ARM system capability is demonstrated by the proper integrated operation of the following:
: 1.       Monitor channels,
: 2.       Channel trip points,
: 3.       Alarm annunciators and lights, and
: 4.       Recorder.
14.2.12.1.24      Process Computer Interface System Preoperational Test
: a. Purpose To verify the operation of the process computer interface (PCI) system including computer inputs and printout.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Additionally, computer diagnostic checks and programming are completed.
: c. General Test Methods and Acceptance Criteria Verification of the PCI system is demonstrated by the proper integrated operation of the following:
: 1.       Analog input signals,
: 2.       Computer printout,
: 3.       Digital input signals, and
: 4.       Digital output signals.
14.2.12.1.25      Rod Sequence Control System Preoperational Test
: a. Purpose To verify the operation of the RSC system under its various modes of operation.
14.2-50

COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                           December 2003
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Additionally, the self-test feature of the RSC system is verified.
: c. General Test Methods and Acceptance Criteria Verification of the RSC system is demonstrated by the proper integrated operation of the following:
: 1. Low power setpoint and low power alarm point tests,
: 2. RSC system status displays and annunciators,
: 3. Reactor mode switch test,
: 4. System diagnostic and data quality tests,
: 5. Rod position data tests,
: 6. Single rod bypass provision,
: 7. Rod sequences tests,
: 8. Rod group assignment,
: 9. Constraints of rod movement tests,
: 10. 100% to 75% control rod density tests,
: 11. 5% to 50% control rod density tests, and
: 12. 0% control rod density to low power setpoint tests.
14.2.12.1.26      Remote Shutdown Preoperational Test
: a. Purpose To verify the feasibility and operability of the shutdown functions from the remote shutdown panel and its ability to bring the reactor to a cold condition in an orderly fashion.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Additionally, the control power should be supplied to the remote shutdown panel, and the independence of power supply voltage, and fuses should be verified.
14.2-51

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003
: c. General Test Methods and Acceptance Criteria Verification of the remote shutdown system is demonstrated by the proper integrated operation of the following tests:
: 1.      Operation of valves, controls, instruments, and pumps on systems available from this panel, and
: 2.      Transfer switch operation from the control room panels to the remote shutdown panel.
14.2.12.1.27     Offgas System Preoperational Test
: a. Purpose To verify the operation of the offgas system including valves, recombiner, condensers, coolers, filters, and hydrogen analyzers.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager (Assistant Plant Manager) has approved the initiation of testing. Additionally, the instrument air system, electrical power, and cooling water should be operational.
: c. General Test Methods and Acceptance Criteria Verification of the offgas system is demonstrated by the following tests:
: 1.      Valve operation including fail safe and isolation features and valve status lights indicate the correct valve position,
: 2.      Pump operation,
: 3.      Level and temperature control and indication,
: 4.      Recombiner and preheater tests,
: 5.      Condenser, cooler, and moisture separator tests,
: 6.      Gas dryer and cooler tests,
: 7.      Filter efficiency, 14.2-52

COLUMBIA GENERATING STATION                        Amendment 57 FINAL SAFETY ANALYSIS REPORT                       December 2003
: 8.       Hydrogen analyzer performance test, and
: 9.       Purge and bleed air rate test.
14.2.12.1.28      Environs Radiation Monitoring Preoperational Test
: a. Purpose To verify the operation of the environs radiation monitoring system, including dosimeters, sampling pump, and filter equipment.
: b. Prerequisites System lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Additionally, indicator power supplies are calibrated according to the vendors instruction manual.
: c. General Test Methods and Acceptance Criteria Verification of the environs radiation monitoring system capability is demonstrated by the proper operation of the following:
: 1.       Air sample equipment, and
: 2.       Thermoluminescent detector (TLD) (passive dosimeters).
14.2.12.1.29      Main Steam System Preoperational Test
: a. Purpose To verify the proper operation of the MSIVs and related controls.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing.
14.2-53

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003
: c. General Test Methods and Acceptance Criteria Verification of the main steam system is demonstrated by the proper integrated operation of the following:
: 1.       Automatic isolation of the MSIVs,
: 2.       Minimum closing times are met,
: 3.       MSIV accumulator capacity tests are satisfactory, and
: 4.       Valves, heaters, blowers, and initiating logic of the MSIV leakage control system.
14.2.12.1.30      Radwaste Building Heating, Ventilating, and Air Conditioning System Preoperational Test
: a. Purpose To verify that the radwaste building heating, ventilating, and air conditioning (HVAC) system will function in accordance with the design requirements as set forth in the design specifications.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The 480-V ac power system, control air supply service air system, and the turbine service water system is capable of supporting this test as necessary.
: c. General Test Methods and Acceptance Criteria Verification of the radwaste building HVAC system is demonstrated by the proper integrated operation of the following:
: 1.       Ventilation fans and their related controls,
: 2.       Filters and instrumentation,
: 3.       Dampers and controls, and
: 4.       Annunciators and protective devices.
14.2-54

COLUMBIA GENERATING STATION                        Amendment 58 FINAL SAFETY ANALYSIS REPORT                       December 2005 14.2.12.1.31      Closed Cooling Water System Preoperational Test
: a. Purpose To verify the operation of the RCC system including pumps, valves, logic, and annunciator.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The following support systems must have received readiness verifications:
: 1.       Control and service air (CAS/SA),
: 2.       Makeup water treatment,
: 3.       Essential 480-V ac power, and
: 4.       Instrumentation power.
: c. General Test Methods and Acceptance Criteria Verification of the RCC system is demonstrated by the proper integrated operation of the following:
: 1.       Surge tank level control,
: 2.       System pumps and control logic,
: 3.       Chemical addition pump and control, and
: 4.       Remote-operated valves.
14.2.12.1.32      Primary Containment Atmospheric Control System Preoperational Test (SYSTEM DEACTIVATED)
: a. Purpose To verify the operation of the primary containment atmospheric control (CAC) system including blowers, coolers, valves, instruments, and alarms.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Primary containment, essential 480-V ac power, standby LDCN-05-002                                 14.2-55

COLUMBIA GENERATING STATION                        Amendment 58 FINAL SAFETY ANALYSIS REPORT                       December 2005 service water (SW), instrument power, and control air systems must have received readiness verification.
: c. General Test Methods and Acceptance Criteria Verification of the primary CAC system is demonstrated by the proper integrated operation of the following:
: 1.       Isolation and control valves,
: 2.       Blowers,
: 3.       Instrumentation,
: 4.       Alarms, and
: 5.       Recombiner components to the extent that flow paths are verified.
Primary CAC system hydrogen/oxygen recombining performance capabilities are not demonstrated during the preoperational test.
14.2.12.1.33      Primary Containment Cooling System Preoperational Test
: a. Purpose To verify the operation of the primary containment cooling system including fans, dampers, related controls, and instrumentation.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The 480-V ac power, instrument power, and RCC systems must have received readiness verification.
: c. General Test Methods and Acceptance Criteria Verification of the primary containment cooling system is demonstrated by the proper integrated operation of the following:
: 1.       Fans and control logic,
: 2.       Cooling coils,
: 3.       Dampers, cooling water flow control valves and related controls,
: 4.       Instrumentation,
: 5.       Related loss-of-power logic, and
: 6.       Annunciators.
14.2-56

COLUMBIA GENERATING STATION                        Amendment 58 FINAL SAFETY ANALYSIS REPORT                       December 2005 Primary containment cooling system heat removal capabilities are not demonstrated during the preoperational test.
14.2.12.1.34      Primary Containment Instrument Air Preoperational Test
: a. Purpose To verify proper operation of the containment instrument air (CIA) system, including compressors, dryers, valves, and related controls and logic.
: b. Prerequisites The system lineup tests have been completed, and the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The plant service water supply system must receive a readiness classification.
: c. General Test Methods and Acceptance Criteria Verification of the CIA system capability is demonstrated by the proper integrated operation of the following:
: 1.       Logic and interlocks,
: 2.       CIA system air compressors,
: 3.       CIA system air dryers,
: 4.       System nonreturn check valves,
: 5.       Alarms and controls,
: 6.       Nitrogen backup supply, and
: 7.       Valve/component failure modes for those valves/components supplied by the CIA system to simulated loss of air supply.
14.2.12.1.35      Primary Containment Atmospheric Monitoring System Preoperational Test
: a. Purpose To verify the capability of the primary containment atmospheric monitoring system to monitor and display containment atmospheric conditions.
14.2-57

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Instrument power is available to system components.
: c. General Test Methods and Acceptance Criteria Verification of the primary containment atmospheric monitoring system capability is demonstrated by the proper integrated operation of the following:
: 1.       Samples and controls,
: 2.       Analyzers,
: 3.       Pressure and temperature instrumentation,
: 4.       Radiation monitors,
: 5.       Indicating/recording instrumentation, and
: 6.       Annunciators.
14.2.12.1.36      Standby Gas Treatment System Preoperational Test
: a. Purpose To verify the reliable operation of the standby gas treatment system (SGTS),
including fans, filter trains, and related controls.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The following systems must have readiness verification:
: 1.       Essential 480-V ac power,
: 2.       Instrument power,
: 3.       Control air, and
: 4.       Reactor building heating and ventilation.
: c. General Test Methods and Acceptance Criteria Verification of the SGTS is demonstrated by the proper integrated operation of the following:
: 1.       SGTS fans and control logic, 14.2-58

COLUMBIA GENERATING STATION                             Amendment 57 FINAL SAFETY ANALYSIS REPORT                            December 2003
: 2.      Filter trains and related instruments,
: 3.      Automatic valves and control logic,
: 4.      System interconnections to reactor building heating and ventilation and primary containment atmospheric control system, and
: 5.      Annunciators.
14.2.12.1.37     Loss of Power and Safety Testing Preoperational Test
: a. Purpose To verify the operation of the 230/115-kV, 6.9-kV, 4.16-kV, and 480-V distribution systems.
To verify the integrated ability of the plant electrical distribution and safety systems to operate on normal and standby power sources during accident conditions.
To verify that loss of a single ac or dc distribution system division (exclusive of the HPCS diesel generator and batteries) will not prevent the remaining systems from actuating during an accident condition.
: b. Prerequisites The system lineup tests and the 69/N (N = number of diesels) consecutive starts from the emergency diesel generators have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The 125-V dc system and the emergency core cooling systems (ECCS) are available to support testing.
: c. General Test Methods and Acceptance Criteria Verification of the 230/115-kV, 6.9-kV, 4.16-kV, and 480-V distribution systems operability shall be demonstrated by the following:
: 1.      Demonstration of circuit integrity and integrated operation of circuit breakers, controls and interlocks, instrumentation, automatic transfer features, and protective devices and alarms.
14.2-59

COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003
: 2. Demonstration of proper system response to a loss of the 230-kV and 115-kV distribution systems independently and simultaneously both with and without loss-of-coolant accident (LOCA)/containment isolation signals.
: 3. Demonstration of proper system response to a loss of the 230/115-kV distribution systems and one individual standby diesel generator during an ECCS/containment isolation actuation.
Signals for these tests shall be simulated from the actual initiating devices when this is practical.
: 4. Testing of the diesel generators will include the following:
(a)     Sequential loading of each diesel generator unit, (b)     Maintenance of specified frequency and voltage during the loading sequence, (c)     Capability to reject and restart their largest single load any time after the design loading sequence is complete, and (d)     Capability to supply power to vital equipment during loss of station normal power conditions.
: 5. Electrical independence will be verified during testing by (a)     Verifying that operation of the division/equipment being tested and the nonactuation of deenergized buses/equipment does not affect the proper operation of the remaining buses/equipment.
(b)     Monitoring of the major distribution buses to ensure absence of voltage.
Main power transformers supplying power from the offsite system cannot be full load tested; they are tested according to this procedure to the design emergency load. All other in-plant power sources are load tested in their individual preoperational tests.
14.2-60

COLUMBIA GENERATING STATION                        Amendment 57 FINAL SAFETY ANALYSIS REPORT                       December 2003 14.2.12.1.38      Instrument Power Preoperational Test
: a. Purpose To verify the operation of the instrument power systems.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing.
The 125-V dc and the 480-V ac power systems are energized and capable of supplying power to the instrument power systems.
: c. General Test Methods and Acceptance Criteria Verification of the instrument power systems shall be accomplished by demonstrating circuit integrity and integrated operation of
: 1.       Static inverters, transformers, and buses,
: 2.       Controls and interlocks,
: 3.       Transfer features,
: 4.       Instrumentation, and
: 5.       Protective devices and alarms.
14.2.12.1.39      Emergency Lighting System Preoperational Test
: a. Purpose To verify the operation of the emergency lighting system within the design requirements of the system.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The 125-V dc system has received a readiness verification.
14.2-61

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003
: c. General Test Methods and Acceptance Criteria Verification of the emergency lighting system is to demonstrate proper automatic operation of the system and to provide sufficient lighting during loss of normal lighting.
14.2.12.1.40      Standby Alternating Current Power System Preoperational Test
: a. Purpose To verify the operation of the standby ac power system including diesel engines, auxiliaries, generators, controls, and instrumentation.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing.
The following support systems or components must have received readiness verification:
: 1.       Standby service water,
: 2.       125/250-V dc power,
: 3.       Instrument power, and
: 4.       Essential 4160-V ac power.
: c. General Test Methods and Acceptance Criteria Verification of the standby ac power system is demonstrated by the proper integrated operation of the following:
: 1.       The diesel engines and auxiliaries,
: 2.       The generators, exciters, and voltage regulators,
: 3.       Fuel storage and supply system,
: 4.       Start and control logic circuitry and interlocks,
: 5.       Protective devices,
: 6.       Instrumentation, and
: 7.       Annunciators.
Testing will be performed to demonstrate the following design features.
14.2-62

COLUMBIA GENERATING STATION                         Amendment 60 FINAL SAFETY ANALYSIS REPORT                        December 2009
: 1.       The diesel generators performance capability to establish frequency, voltage, and load acceptance with a specified time interval on initiation of an automatic start signal under both cold and hot conditions.
: 2.       Specified full- and over-load performance capabilities.
: 3.       The diesel generators capability to reject the maximum rated load without exceeding speeds or voltage which will cause tripping.
14.2.12.1.41      250-V Direct Current Power System Preoperational Test
: a. Purpose To verify the operation of the 250-V dc power system including batteries, chargers, controls, interlocks, instruments, and protective devices.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Battery room ventilation and 480-V ac power supply to the chargers have received readiness verification.
: c. General Test Methods and Acceptance Criteria Verification of the 250-V dc power system is demonstrated by the proper integrated operation of the following:
: 1.       Battery chargers including capability to recharge the battery in accordance with Section 8.3.2.1.4.3,
: 2.       Batteries (including charge and discharge rate/capacity tests and load profiles described in Table 8.3-14),
: 3.       Protective relays and devices,
: 4.       System control logic,
: 5.       Instrumentation (including ground detection),
: 6.       Breakers, and
: 7.       Annunciators.
LDCN-08-025                                  14.2-63

COLUMBIA GENERATING STATION                         Amendment 60 FINAL SAFETY ANALYSIS REPORT                        December 2009 14.2.12.1.42      125-V Direct Current Power System Preoperational Test
: a. Purpose To verify the operation of the 125-V dc power system including batteries, chargers, controls, interlocks, instruments, and protective devices.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Battery room ventilation and 480-V ac power supply to the chargers have received readiness verification.
: c. General Test Methods and Acceptance Criteria Verification of the 125-V dc power system is demonstrated by the proper integrated operation of the following:
: 1.       Battery chargers including capability to recharge the battery in accordance with Section 8.3.2.1.1.3,
: 2.       Batteries (including charge and discharge rate/capacity tests and load profiles described in Tables 8.3-11 and 8.3-12),
: 3.       Protective relays and devices,
: 4.       System control logic,
: 5.       Instrumentation (including ground detection),
: 6.       Breakers, and
: 7.       Annunciators.
14.2.12.1.43      24-V Direct Current Power System Preoperational Test
: a. Purpose To verify the operation of the 24-V dc power system.
LDCN-08-025                                  14.2-64

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing.
: c. General Test Methods and Acceptance Criteria Verification of the 24-V dc power system shall include demonstrations of battery capacity and battery charger capabilities described in Section 8.3.2.1.3.3.
14.2.12.1.44      Plant Service Water System Preoperational Test
: a. Purpose To demonstrate the proper operation of the plant service water system, including pumps, valves, and related controls.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing.
The following support systems or components must have received readiness verification:
: 1.       4160-V ac power,
: 2.       480-V ac power,
: 3.       Instrument power,
: 4.       Service water pump house structure,
: 5.       Various heat exchangers or coolers utilizing service water, and
: 6.       Tower makeup (TMU).
: c. General Test Methods and Acceptance Criteria Verification of the plant service water system is demonstrated by the proper operation and performance of the service water pumps, the operation of filters, remote-operated valves, related controls, and instrumentation.
14.2-65

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998 14.2.12.1.45      Standby Service Water System Preoperational Test
: a. Purpose To verify the proper operation of the SW system for normal and abnormal plant operating modes.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The following support systems or components must have received readiness verification:
: 1.       Essential 4160-V ac power, 2        Instrument power,
: 3.       Control air,
: 4.       Standby service water pump house structure,
: 5.       Various heat exchangers or coolers utilizing SW, and
: 6.       Tower makeup (TMU).
: c. General Test Methods and Acceptance Criteria Verification of this system is demonstrated by the proper integrated operation and performance of the following:
: 1.       Pumps and related controls,
: 2.       Remote-operated valves and controls,
: 3.       Automatic-operated valves and control logic,
: 4.       Instrumentation,
: 5.       Annunciators,
: 6.       Standby service water system control logic response to a simulated loss of normal station power event,
: 7.       Pumps net positive suction head (NPSH) adequate and no vortexing,
: 8.       Proper operation of basin siphon cross connection, and 14.2-66

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998
: 9.       The preoperational test program includes tests to confirm the performance characteristics of the spray ponds (see Section 9.2.5).
14.2.12.1.46      Plant Communications System Preoperational Test
: a. Purpose To demonstrate that the plant communications and evacuation alarm system will provide effective communication between various plant locations and to verify proper operation of the emergency evacuation alarm components and system.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing.
: c. General Test Methods and Acceptance Criteria Proper operation of all the communication system components and the emergency evacuation alarm system and components will be demonstrated.
14.2.12.1.47      Reactor Building Emergency Cooling System Preoperational Test
: a. Purpose To demonstrate the proper integrated operation of the reactor building emergency equipment cooling system including fans, cooling coils, instrumentation, and controls.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The following support systems or components must have received readiness verification:
: 1.       Electrical power to motors, control circuits, and instrumentation, and
: 2.       Standby service water system.
14.2-67

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998
: c. General Test Methods and Acceptance Criteria Verification of this system is demonstrated by the proper integrated operation of the fan coil units, their associated controls, interlocks, and annunciators.
14.2.12.1.48      Control, Cable, and Critical Switchgear Rooms Heating, Ventilating, and Air Conditioning System Preoperational Test
: a. Purpose To verify that the control, cable, and critical switchgear rooms HVAC systems will function in accordance with the design requirements as set forth in the design specifications.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The following support systems have received readiness verification:
: 1.       480-V ac power,
: 2.       Instrument power, and
: 3.       Chilled water.
: c. General Test Methods and Acceptance Criteria Verification of the control, cable, and critical switchgear rooms HVAC system is demonstrated by the proper integrated operation of the following:
: 1.       Supply and exhaust fans and their related controls,
: 2.       Filters, dampers, valves, and related instrumentation and control logic,
: 3.       Coolers, and
: 4.       Annunciators.
14.2.12.1.49      Standby Service Water Pump House Heating and Ventilating System Preoperational Test
: a. Purpose To verify that the SW pump house heating and ventilating system will function in accordance with the design requirements as set forth in the design specifications.
14.2-68

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The 480-V ac power system must have received readiness verification.
: c. General Test Methods and Acceptance Criteria Verification of the SW pump house heating and ventilating system is demonstrated by the proper integrated operation of the following:
: 1.       Ventilation fans and their related controls,
: 2.       Filters and instrumentation,
: 3.       Dampers and controls, and
: 4.       Annunciators.
14.2.12.1.50      Reactor Building Crane Preoperational Test
: a. Purpose To verify the operation of the reactor building crane.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Construction load tests of 125% static and 100%
operational are complete.
Contractor use of the reactor building crane for construction purposes is complete.
: c. General Test Methods and Acceptance Criteria Verification of the reactor building crane is demonstrated by the proper integrated operation of the following:
: 1.       Crane traverse components,
: 2.       Hook traverse and hoist components,
: 3.       Controls and indicators, 14.2-69

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998
: 4.       Safety devices, and
: 5.       Instrumentation.
14.2.12.1.51      Primary Containment Integrated Leak Rate Preoperational Test
: a. Purpose To verify overall primary containment integrity by pressurizing to specified test pressures and conducting integrated leak rate measurements.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The following supporting activities, systems, or components must have been completed or received readiness verification:
: 1.       All type B and C local leak testing completed, documented, and verified as a system lineup test; see Section 6.2.6.1,
: 2.       All containment isolation valves fully operable and closed in the normal manner,
: 3.       All containment-associated piping hangers, supports, restraints, and anchors have been installed and properly set,
: 4.       Residual heat removal and core spray systems preoperational tests complete, and
: 5.       A containment area survey completed to locate, isolate, or remove any instrumentation, light bulbs, etc., which may be damaged by high external pressure.
: c. General Test Methods and Acceptance Criteria Verification of primary containment integrity is demonstrated by pressurizing to the required test pressure. See Section 6.2.6.1 for a detailed test description.
The drywell-wetwell leakage test will be performed as part of this test to verify the acceptance criteria described in Section 3.8.3.7.
14.2-70

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 14.2.12.1.52      Secondary Containment Integrated Leak Rate Preoperational Test
: a. Purpose To verify overall secondary containment integrity by subjecting the reactor building to a specified negative pressure and measuring the inleakage.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The following supporting activities or systems/components must have been completed or received readiness verification:
: 1.       Reactor building structure complete with personnel and vehicle air lock (railroad bay) doors installed and operable,
: 2.       Reactor building conduit, pipe, and other structural penetrations sealed, and
: 3.       Standby gas treatment system.
: c. General Test Methods and Acceptance Criteria Verification of secondary containment integrity is demonstrated by operating the SGTS at a specific capacity while maintaining the reactor building internal structure at a specified negative pressure.
14.2.12.1.53      Diesel Generator Building Heating and Ventilating System Preoperational Test
: a. Purpose To verify that the diesel generator building heating and ventilating system will function in accordance with the design requirements as set forth in the design specifications.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The 480-V ac power system must have received readiness verification.
LDCN-02-036                                 14.2-71

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998
: c.      General Test Methods and Acceptance Criteria Verification of the diesel generator building heating and ventilating system is demonstrated by the proper integrated operation of the following:
: 1.       Ventilation fans and their related controls,
: 2.       Filters and instrumentation,
: 3.       Dampers and controls, and
: 4.       Annunciators.
14.2.12.1.54         Seismic Monitoring System Preoperational Test
: a.      Purpose To verify the operation of the seismic monitoring system.
: b.      Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing.
: c.      General Test Methods and Acceptance Criteria Verification of the seismic monitoring system is demonstrated by the proper integrated operation of the following:
: 1.       Annunciators, and
: 2.       Instrumentation.
14.2.12.2      General Discussion of Startup Tests All those tests comprising the startup test phase (Table 14.2-4) are discussed in this section.
For each test a description is provided for test purpose, test prerequisites, test description, and statement of test acceptance criteria, where applicable.
In describing the purpose of a test, an attempt is made to identify those operating and safety-oriented characteristics of the plant which are being explored.
Where applicable, a definition of the relevant acceptance criteria for the test is given and is designated either Level 1 or Level 2. A Level 1 criterion normally relates to the value of a process variable assigned in the design of the plant, components, systems, or associated 14.2-72

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998 equipment. If a Level 1 criterion is not satisfied, the plant will be placed in a suitable hold-condition until resolution is obtained. Tests compatible with this hold-condition may be continued. Following resolution, applicable tests must be repeated to verify that the requirements of the Level 1 criterion are now satisfied.
A Level 2 criterion is associated with expectations relating to the performance of systems. If a Level 2 criterion is not satisfied, operating and testing plans would not necessarily be altered.
Investigations of the measurements and of the analytical techniques used for the predictions would be started.
For transients involving oscillatory response, the criteria are specified in terms of decay ratio (defined as the ratio of successive maximum amplitudes of the same polarity). The decay ratio must be less than unity to meet a Level 1 criterion and less than 0.25 to meet a Level 2 criterion.
14.2.12.3      Startup Test Procedures 14.2.12.3.1         Test Number 1 - Chemical and Radiochemical 14.2.12.3.1.1 Purpose. The principal objectives of this test are to (a) secure information on the chemistry and radiochemistry of the reactor coolant, and (b) determine that the sampling equipment, procedures, and analytic techniques are adequate to supply the data required to demonstrate that the chemistry of all parts of the entire reactor system meet specifications and process requirements.
Specific objectives of the test program include evaluation of fuel performance, evaluations of demineralizer operations by direct and indirect methods, measurements of filter performance, confirmation of condenser integrity, demonstration of proper steam separator-dryer operation, measurement and calibration of the offgas system, and calibration of certain process instrumentation. Data for these purposes is secured from a variety of sources: plant operating records, regular routine coolant analysis, radiochemical measurements of specific nuclides, and special chemical tests.
14.2.12.3.1.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.1.3 Description. Prior to fuel loading a complete set of chemical and radiochemical samples will be taken to ensure that all required sample stations are functioning properly and to determine initial concentrations. Subsequent to fuel loading during reactor heatup and at each major power level change, samples will be taken and measurements will be made to determine the chemical and radiochemical quality of reactor water and reactor 14.2-73

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 feedwater, amount of radiolytic gas in the steam, gaseous activities leaving the air ejectors, decay times in the offgas lines and performance of filters and demineralizers.
Calibrations will be made of monitors in the stack, liquid waste system, and liquid process lines.
14.2.12.3.1.4 Criteria.
Level 1 Chemical factors defined in the Technical Specifications and Fuel Warranty must be maintained within the limits specified.
The activity of gaseous liquid effluents must conform to license limitations.
Water quality must be known at all times and should remain within the guidelines of the Water Quality Specifications.
Level 2 Not applicable.
14.2.12.3.2         Test Number 2 - Radiation Measurements 14.2.12.3.2.1 Purpose. The purposes of this test are to (a) determine the background radiation levels in the plant environs prior to operation for base data on activity buildup, and (b) monitor radiation at selected power levels to ensure the protection of personnel during plant operation.
14.2.12.3.2.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.2.3 Description. A survey of natural background radiation throughout the plant site will be made prior to fuel loading. Subsequent to fuel loading, during reactor heatup and at nominal power levels of 25%, 60%, and 100% of rated power, gamma dose rate measurements and where appropriate, neutron dose rate measurements will be made at significant locations throughout the plant. All potentially high radiation areas will be surveyed.
14.2-74

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998 14.2.12.3.2.4 Criteria.
Level 1 The radiation doses of plant origin and the occupancy times of personnel in radiation zones shall be controlled consistent with the guidelines of the Standards for Protection Against Radiation outlined in 10 CFR 20 and the NRC General Design Criteria in 10 CFR 50, Appendix A.
Level 2 Not applicable.
14.2.12.3.3        Test Number 3 - Fuel Loading 14.2.12.3.3.1 Purpose. The purpose of this test is to load fuel safely and efficiently to the full core size.
14.2.12.3.3.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing. Also the following prerequisites will be met prior to commencing fuel loading to ensure that this operation is performed in a safe manner:
: a. The status of all systems required for fuel loading will be specified and will be in the status required;
: b. Fuel and control rod inspections will be complete. Control rods will be installed and tested;
: c. At least three movable neutron detectors will be calibrated and operable. At lease three neutron detectors will be connected to the high flux scram trips.
They will be located so as to provide acceptable signals during fuel loading;
: d. Nuclear instruments will be source checked with a neutron source prior to loading or resumption if sufficient delays are incurred;
: e. The status of secondary containment will be specified and established;
: f. Reactor vessel status will be specified relative to internal component placement and this placement established to make the vessel ready to receive fuel;
: g. Reactor vessel water level will be established and minimum level prescribed; 14.2-75

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998
: h.      The standby liquid control system will be operable and in readiness;
: i.      Fuel handling equipment will have been checked and dry runs completed;
: j.      The status of protection systems, interlocks, mode switches, alarms, and radiation protection equipment will be prescribed and verified. The high flux trip points will be set for a relatively low power level;
: k.      Water quality must meet required specifications; and
: l.      A neutron source will be installed near the center of the core.
14.2.12.3.3.3 Description. Prior to fuel loading, control rods and neutron sources and detectors will be installed and tested. Fuel loading will begin at the center of the core and will proceed radially to the fully loaded configuration.
Control rod functional tests, subcriticality checks, and shutdown margin demonstrations will be performed periodically during the loading.
14.2.12.3.3.4 Criteria.
Level 1 The partially loaded core must be subcritical by at least 0.38% k/k with the analytically strongest rod fully withdrawn.
Level 2 Not applicable.
14.2.12.3.4         Test Number 4 - Full Core Shutdown Margin 14.2.12.3.4.1 Purpose. The purpose of this test is to demonstrate that the reactor will be subcritical throughout the first fuel cycle with any single control rod fully withdrawn.
14.2.12.3.4.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing. Also the following prerequisites will be complete prior to performing the full core shutdown margin test:
: a.      The predicted critical rod position is available,
: b.      The standby liquid control system is available, 14.2-76

COLUMBIA GENERATING STATION                            Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998
: c.      Nuclear instrumentation is available with neutron count rate of at least 0.5 counts per sec and signal to noise ratio greater than two, and
: d.      High-flux scram trips are set conservatively low.
14.2.12.3.4.3 Description. This test will be performed in the fully loaded core in the xenon-free condition. The shutdown margin test will be performed by withdrawing the control rods from the all-rods-in configuration until criticality is reached. If the highest worth rod will not be withdrawn in sequence, other rods may be withdrawn providing that the reactivity worth is equivalent. The difference between the measure Keff and the calculated Keff for the in sequence critical will be applied to the calculated value to obtain the true shutdown margin.
14.2.12.3.4.4 Criteria.
Level 1 The shutdown margin of the fully loaded, cold (68&deg;F or 20&deg;C), xenon-free core occurring at the most reactive time during the cycle must be at least 0.38% k/k with the analytically strongest rod (or its reactivity equivalent) withdrawn. If the shutdown margin is measured at some time during the cycle other than the most active time, compliance with the above criterion is shown by demonstrating that the shutdown margin is 0.38% k/k plus an exposure dependent correction factor which corrects the shutdown margin at that time to the minimum shutdown margin.
Level 2 Criticality should occur within +/-1% k/k of the predicted critical (predicted critical to be determined later).
14.2.12.3.5         Test Number 5 - Control Rod Drive System 14.2.12.3.5.1 Purpose. The purposes of the CRD system test are to (a) demonstrate that the CRD system operates properly over the full range of primary coolant temperatures and pressures from ambient to operating, and (b) determine the initial operating characteristics of the entire CRD system.
14.2.12.3.5.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing. The RMC system preoperational testing must be completed on CRDs being tested. The reactor vessel, RCC system, condensate supply system, and instrument air system must be operational to the extent required to conduct the test.
14.2-77

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 14.2.12.3.5.3 Description. The CRD tests performed during the startup test program are designed as an extension of the tests performed during the preoperational CRD system tests.
Thus, after it is verified that all CRDs operate properly when installed, they are tested periodically during heatup to ensure that there is not significant binding caused by thermal expansion of the core components.
Test Conditions Reactor Pressure with Core Loaded Accumulator                         psig (kg/cm2)
Action                         Pressure           0     600 (42.2)       800 (56.2)    Rated Position indication                             All Normal stroke times                             All                                     4*
insert/withdraw Coupling                                        All**                                   4*
Friction                                        All                                     4*
Scram                       Normal              All         4*              4*          All Scram                       Minimum             4*
Scram                       Zero                                                        4*
Scram                       Normal                                                      4***
NOTE:        Single CRD scrams should be performed with the charging valve closed. (Do not ride the charging pump head.)
Refers to four CRDs selected for continuous monitoring based on slow normal accumulator pressure scram times, or unusual operating characteristics, at zero reactor pressure or rated reactor pressure when this data is available. The four selected CRDs must be compatible with the RWM, RSC system, and CRD sequence requirements.
Established initially that this check is normal operating procedures.
Scram times of the four slowest CRDs (based on scram data at rated pressure will be determined at test condition 2, 3, and 6 during planned reactor scram).
14.2-78

COLUMBIA GENERATING STATION                            Amendment 53 FINAL SAFETY ANALYSIS REPORT                           November 1998 14.2.12.3.5.4 Criteria.
Level 1
: a. Each CRD must have a normal withdraw speed less than or equal to 3.6 in./sec (9.14 cm/sec), indicated by a full 12-ft stroke in greater than or equal to 40 sec.
: b. The mean scram time of all operable CRDs with functioning accumulators must not exceed the following times (scram time is measured from the time the pilot scram valve solenoids are deenergized):
Position Inserted From                  Scram Time Fully Withdrawn                          (sec) 45                                0.430 39                                0.868 25                                1.936 05                                3.497
: c. The mean scram time of the three fastest CRDs in a two-by-two array must not exceed the following times (scram time is measured from the time the pilot scram valve solenoids are deenergized):
Position Inserted From                  Scram Time Fully Withdrawn                          (sec) 45                                0.455 39                                0.920 25                                2.052 05                                3.706 Level 2
: a. Each CRD must have normal insert or withdraw speed of 3.0 +/- 0.6 in./sec (7.62 +/- 1.52 cm/sec), indicated by a full 12-ft stroke in 40 to 60 sec.
: b. With respect to the CRD friction tests, if the differential pressure variation exceeds 15 psid (1.1 kg/cm2) for a continuous drive in, a settling test must be performed, in which case the differential settling pressure should not be less than 30 psid (2.1 kg/cm2) nor should it vary by more than 10 psid (0.7 kg/cm2) over a full stroke.
14.2-79

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 Level 3
: a.      On receipt of a simulated or actual scram signal (maximum error), the flow control valve must close to its minimum position within 10 sec to 30 sec.
: b.      The CRD system flow should not change by more than +/- 3.0 gpm as reactor pressure varies from 0 to rated pressure.
: c.      The decay ratio of any oscillatory controlled variable must be 0.25 for any flow setpoint changes or for system disturbances caused by the CRDs being stroked.
14.2.12.3.6         Test Number 6 - Source Range Monitor Performance and Control Rod Sequence 14.2.12.3.6.1 Purpose. The purpose of this test is to demonstrate that the operational sources, SRM instrumentation, and rod withdrawal sequences provide adequate information to achieve criticality and increase power in a safe and efficient manner. The effect of typical rod movements on reactor power will be determined.
14.2.12.3.6.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing. The CRD system must be operational.
14.2.12.3.6.3 Description. Source range monitor count-range data will be taken during rod withdrawals to critical and compared with stated criteria on signal count-to-noise count ratio.
A withdrawal sequence has been calculated which completely specifies control rod withdrawals from the all-rods-in condition to the rated power configuration. Critical rod patterns will be recorded periodically as the reactor is heated to rated temperature.
Movement of rods in a prescribed sequence is monitored by the rod control and information system, which will prevent out of sequence withdrawal. Also not more than two rods may be inserted out of sequence.
As the withdrawal of each rod group is completed during the power ascension, the electrical power, steam flow, control valve position, and APRM response will be recorded.
14.2.12.3.6.4 Criteria.
Level 1 There must be a neutron signal-to-noise ratio of at least 2 to 1 on the required operable SRMs or fuel loading chambers.
LDCN-02-000                                    14.2-80

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 There must be a minimum count rate of 0.5 counts/sec on the required operable SRMs or fuel loading chambers.
The IRMs must be on scale before the SRMs exceed the rod block setpoint.
Level 2 Not applicable.
14.2.12.3.7       Test Number 7 Not applicable.
14.2.12.3.8       Test Number 8 Not applicable.
14.2.12.3.9       Test Number 9 See test number 16B in Section 14.2.12.3.16.2.
14.2.12.3.10      Test Number 10 - Intermediate Range Monitor System Performance 14.2.12.3.10.1 Purpose. The purpose of this test is to adjust the IRM system to obtain an optimum overlap with the SRM and APRM systems.
14.2.12.3.10.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing. All SRMs and pulse preamplifiers, IRMs and voltage preamplifiers, and APRMs have been calibrated in accordance with the vendors instructions.
14.2.12.3.10.3 Description. Initially the IRM system is set to maximum gain. After the APRM calibration, the IRM gains will be adjusted to optimize the IRM overlap with the SRMs and APRMs.
14.2.12.3.10.4 Criteria.
Level 1 Each IRM channel must be on scale before the SRMs exceed their rod block setpoint. Each APRM must be on scale before the IRMs exceed their rod block setpoint.
14.2-81

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 Level 2 Each IRM channel must be adjusted so that a half decade overlap with the SRMs and one decade overlap with the APRMs are ensured.
14.2.12.3.11       Test Number 11 - Local Power Range Monitor Calibration 14.2.12.3.11.1 Purpose. The purpose of this test is to calibrate the LPRM system.
14.2.12.3.11.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation for calibration has been checked and installed.
14.2.12.3.11.3 Description. The LPRM channels will be calibrated to make the LPRM readings proportional to the neutron flux in the LPRM water gap at the chamber elevation.
Calibration factors will be obtained through the use of either an off-line or a process computer calculation that relates the LPRM reading to average fuel assembly power at the chamber height.
14.2.12.3.11.4 Criteria.
Level 1 Not applicable.
Level 2 Each LPRM reading will be within 10% of its calculated value.
14.2.12.3.12       Test Number 12 - Average Power Range Monitor Calibration 14.2.12.3.12.1 Purpose. The purpose of this test is to calibrate the APRM system.
14.2.12.3.12.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation for calibration has been checked and installed.
14.2.12.3.12.3 Description. A heat balance will generally be made each shift and after each major power level change. Each APRM channel reading will be adjusted to be consistent with the core thermal power as determined from the heat balance. During heatup a preliminary calibration will be made by adjusting the APRM amplifier gains so that the APRM readings agree with the results of a constant heatup rate heat balance. The APRMs should be recalibrated in the power range by a heat balance as soon as adequate feedwater indication is 14.2-82

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 available. Recalibration of the APRM system will not be necessary from safety considerations if at least two APRM channels per RPS trip circuit have readings greater than or equal to core power.
14.2.12.3.12.4 Criteria.
Level 1 The APRM channels must be calibrated to read equal to or greater than the actual core thermal power.
Technical Specifications and Fuel Warranty Limits on APRM scram and rod block shall not be exceeded.
In the startup mode, all APRM channels must produce a scram at less than or equal to 15% of rated thermal power.
Level 2 If the above criteria are satisfied then the APRM channels will be considered to be reading accurately if they agree with the heat balance or the minimum value required based on peaking factor maximum linear heat generation rate (MLHGR) and fraction of rated power to within
(+7, -0)% of rated power.
14.2.12.3.13        Test Number 13 - Process Computer 14.2.12.3.13.1 Purpose. The purpose of this test is to verify the performance of the process computer under plant operating conditions.
14.2.12.3.13.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Computer diagnostic testing has been completed. Construction and construction testing on each input instrument and its cabling has been completed.
14.2.12.3.13.3 Description. Computer system program verifications and calculational program validations at static and at simulated dynamic input conditions will be preoperationally tested at the computer suppliers site and following delivery to the plant site.
Following fuel loading, during plant heatup and the ascension to rated power, the NSSS and the balance-of-plant system process variables sensed by the computer as digital or analog signals will become available. Verify that the computer is receiving correct values of NSSS process variables and that the results of performance calculations of the NSSS is correct. At steady-state power conditions the dynamic system test case will be performed.
14.2-83

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                       December 2003 As discussed in Test 19 the BUCLE offline computation system will be used to evaluate core performance until the process computer performance is verified. A manual computation method is available at the site if both the process computer and BUCLE are not available.
14.2.12.3.13.4 Criteria.
Level 1 Not applicable.
Level 2 Programs OD-1, P1, and OD-6 will be considered operational when
: a. The MCPR calculated by BUCLE and the process computer either
: 1. Are in the same fuel assembly and do not differ in value by more than 2%, or
: 2. For the case in which the MCPR calculated by the process computer is in a different assembly than that calculated by BUCLE, for each assembly, the MCPR and CPR calculated by the two methods shall agree within 2%.
: b. The MLHGR calculated by BUCLE and the process computer either
: 1. Are in the same fuel assembly and do not differ in value by more than 2%, or
: 2. For the case in which the MLHGR calculated by the process computer is in a different assembly than that calculated by BUCLE, for each assembly, the MLHGR and LHGR calculated by the two methods shall agree within 2%.
: c. The maximum average planar linear heat generation rate (MAPLHGR) calculated by BUCLE and the process computer either
: 1. Are in the same fuel assembly and do not differ in value by more than 2%, or
: 2. For the case in which the MAPLHGR calculated by the process computer is in different assembly than that calculated by BUCLE, for each 14.2-84

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 assembly, the MAPLHGR and APLHGR calculated by the two methods shall agree within 2%.
: d.      The LPRM gain adjustment factors calculated by BUCLE and the process computer agree to within 2%.
: e.      The remaining programs will be considered operational on successful completion of the static and dynamic testing.
14.2.12.3.14        Test Number 14 - Reactor Core Isolation Cooling System 14.2.12.3.14.1 Purpose. The purpose of this test is to verify the proper operation of the RCIC system over its expected operating pressure range.
14.2.12.3.14.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
14.2.12.3.14.3 Description. The RCIC system test consists of two parts: Injection to the condensate storage tank and injection to the reactor vessel. The initial condensate storage tank (CST) injections consist of manual and automatic starts at 150 psi and at rated reactor pressure. The pump discharge pressure during these tests is throttled to 100 psi above reactor pressure. This initial testing is done to demonstrate system operability and making initial controller adjustments. This is followed by vessel injections beginning with cold RCIC hardware; cold being defined as a minimum of 3 days without any kind of RCIC operation.
The vessel injections verify the adequacy of the startup transient and also include steady-state controller adjustments. Five consecutive successful system initiations starting from cold condition and with the same equipment settings are necessary to demonstrate system reliability.
Two of these initiations are vessel injection tests with one performed using the controllers on the remote shutdown panel.
After final controller settings are determined, three CST injections at rated pressure and/or 150 psig pressure are done with initially cold RCIC equipment. These runs provide a bench mark for future surveillance testing and provide further assurance of system reliability.
A demonstration of extended operation of 30 minutes of continuous running until pump and turbine oil temperature is stabilized is scheduled at a convenient time during the test program, probably in conjunction with one of the system reliability tests. During this demonstration, automatic RCIC suction transfer from the CST to the suppression pool will be performed to confirm system stability in this configuration.
14.2-85

COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                           December 2003 During vessel injections all reactor steam is routed to the turbine bypass valves. The steam admission valves of the main and feedwater turbines should be closed whenever the moisture carryover threshold is reached.
14.2.12.3.14.4 Criteria.
Level 1 The average pump discharge flow must be equal to or greater than 600 gpm after 30 sec have elapsed from automatic initiation at any reactor pressure between 150 psig and rated.
The RCIC turbine must not trip off or isolate during auto or manual start tests.
If any Level 1 criteria are not met, the reactor operation will be restricted to the power level defined by Figure 14.2-5. This restriction is in addition to any restrictions defined by the Technical Specifications.
Level 2 The turbine gland seal condenser system shall be capable of preventing steam leakage to the atmosphere.
The differential pressure switch for the RCIC steam supply line high flow isolation trip shall be adjusted to actuate at the valve specified in the Technical Specifications (about 300%).
The speed and flow control loops shall be adjusted so that the decay ratio of any RCIC system related variable is not greater than 0.25.
To provide an overspeed trip avoidance margin, the transient start first and subsequent speed peaks shall not exceed 5% above the rated RCIC turbine speed.
14.2.12.3.15        Test Number 15 Not applicable.
14.2.12.3.16        Test Numbers 16A and 16B 14.2.12.3.16.1 Test Number 16A - Selected Process Temperatures.
14.2.12.3.16.1.1 Purpose. The purpose of this test is to (a) ensure that the measured bottom head drain temperature corresponds to bottom head coolant temperature during normal operations, (b) identify any reactor operating modes that cause temperature stratification, (c) determine the proper setting of the low flow control limiter for the recirculation pumps to 14.2-86

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 avoid coolant temperature stratification in the RPV bottom head region, and (d) familiarize the plant personnel with the temperature differential limitations of the reactor system.
14.2.12.3.16.1.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
14.2.12.3.16.1.3 Description. The adequacy of bottom drain line temperature sensors will be determined by comparing it with recirculation loop coolant temperature when core flow is 100% of rated.
During initial heatup while at hot standby conditions, the bottom drain line temperature, recirculation loop suction temperature, and applicable reactor parameters are monitored as the recirculation flow is slowly lowered to either minimum stable flow or the low recirculation pump speed minimum valve position, whichever is the greater. The effects of cleanup flow will be investigated as operational limits allow. Using this data it can be determined whether coolant temperature stratification occurs and if so, what minimum recirculation flow will prevent it.
Monitoring the preceding information during planned pump trips will determine if temperature stratification occurs in the idle recirculation loops or in the lower plenum when one or more loops are inactive.
All data will be analyzed to determine if changes in operating procedures are required.
14.2.12.3.16.1.4 Criteria.
Level 1
: a. The reactor recirculation pumps shall not be started nor flow increased unless the coolant temperatures between the steam dome and bottom head drain are within 145&deg;F (81&deg;C).
: b. The recirculation pump in an idle loop must not be started, active loop flow must not be raised, and power must not be increased unless the idle loop suction temperature is with in 50&deg;F (28&deg;C) of the active loop suction temperature. If two pumps are idle, the loop suction temperature must be within 50&deg;F (28&deg;C) of the steam dome temperature before pump startup.
Level 2 During two-pump operation at rated core flow, the bottom head temperature as measured by the bottom drain line thermocouple should be within 30&deg;F (17&deg;C) of the recirculation loop temperatures.
14.2-87

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 14.2.12.3.16.2 Test Number 16B - Water Level Reference Leg Temperature Measurement.
14.2.12.3.16.2.1 Purpose. The purpose of this test is to measure the reference leg temperature and recalibrate the affected level instruments if the measured temperature is different than the value assumed during the initial calibration.
14.2.12.3.16.2.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing. All applicable system instrumentation is installed and calibrated.
14.2.12.3.16.2.3 Description. To monitor the reactor vessel water level, five level instrument systems are provided. These are
: a.      Shutdown range level system,
: b.      Narrow range level system,
: c.      Wide range level system,
: d.      Fuel zone level system, and
: e.      Upset range.
These systems are used respectively as follows:
: a.      Water level measurement in cold shutdown conditions (shutdown range level system),
: b.      Feedwater flow and water level control functions in hot operating conditions (narrow range level system),
: c.      Safety functions in hot operating conditions (wide range level system),
: d.      Safety functions in cold shutdown conditions (fuel zone level system), and
: e.      High water level protection, hot operating condition (upset range).
The test will be done at rated temperature and pressure and under steady-state conditions and will verify that the reference leg temperature of the level instrument is the value assumed during initial calibration. If not, the instruments will be recalibrated using the measured value.
14.2-88

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                       December 2003 14.2.12.3.16.2.4 Criteria.
Level 1 Not applicable.
Level 2 The indicator readings on the narrow range level system should agree with +/- 1.5 in. of the average readings or the reading calculated from the correct reference leg temperatures.
The wide and upset range level system indicators should agree within +/- 6 in. of the average readings or the readings calculated from the correct reference leg temperatures.
14.2.12.3.17        Test Number 17 - System Expansion 14.2.12.3.17.1 Purpose. The purpose of this test is to (a) verify that piping systems and components are unrestrained with respect to thermal expansion, (b) verify that suspension components are functioning in the specified manner, (c) provide confirmatory data for the calculated stress levels in nozzles and weldments, (d) perform an inspection to satisfy ASME Section XI, IWF-220 post heatup (shakedown) inspection requirements, and (e) satisfy the inspection requirements for the condensate and feedwater systems according to Regulatory Guide 1.68.1.
14.2.12.3.17.2 Prerequisites. Necessary preoperational tests have been completed. The preheatup examination program relating to component supports as contained in the CGS Preservice Inspection Program Plan has been completed. The POC has reviewed and the Plant Manager has approved the test procedure and initiation of testing. Instrumentation has been installed and calibrated.
14.2.12.3.17.3 Description. A significant mechanical design objective for nuclear piping support systems is to provide for unrestricted thermal expansion of piping and components, from ambient to rated temperature. The combination of visual and remote monitoring of selected piping systems will provide the data necessary to evaluate the support system. The criteria used for system selection is Standard Review Plan Section 3.9.2 and those systems with a normal operating temperature greater than 250&deg;F. The drywell piping systems selected for visual inspection and remote monitoring are the following:
: a.      Reactor recirculation,
: b.      Main steam,
: c.      Feedwater,
: d.      Residual heat removal (shutdown cooling supply and return line),
: e.      Reactor core isolation cooling (steam supply and head spray line),
14.2-89

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003
: f. Safety/relief valve discharge piping, and
: g. Reactor water cleanup.
In addition, visual inspections only of the following drywell systems will be conducted:
: a. High-pressure core spray,
: b. Low-pressure core spray,
: c. Sacrificial shield wall penetrations,
: d. Residual heat removal (LPCI) injection lines,
: e. Main steam flow instrumentation piping,
: f. Main steam drain piping,
: g. Reactor head vent piping,
: h. Reactor coolant sample piping, and
: i. Standby liquid control injection piping.
Piping support system components (hangers, sway struts, boxes, snubbers, and whip restraints) for the systems listed will be visually inspected at ambient (less than or equal to 200&deg;F), during the initial heatup cycle at an intermediate temperature (200&deg;F to 300&deg;F, equivalent to 30 psig reactor pressure) and at normal operating temperature (545&deg;F, equivalent to 1000 psig reactor pressure). Data from the remote monitoring instrumentation will be recorded and evaluated at similar intervals. Exceptions to this are feedwater, main steam relief valve (MSRV) discharge piping, and the reactor head spray and vent piping above the drywell bulkhead. The feedwater piping will attain rated temperatures only at higher reactor power levels, which precludes drywell entry. The MSRV piping is only heated up during valve actuation, which also represents a potential inspection personnel hazard. The area above the bulkhead is considered hazardous due to confinement and high temperatures. The methods used to evaluate these are as follows:
: a. Feedwater drywell piping is instrumented and will be evaluated at 25% and 100% reactor power using the data collected by the lanyard potentiometers.
: b. Two MSRV lines will be instrumented allowing data evaluation to be applied to all lines during SRV actuation.
: c. The piping above the bulkhead will be visually inspected prior to drywell head installation.
Feedwater and the SRV piping systems will also be inspected during the shakedown inspection.
The instrumented nodes will be provided with three sensors to indicate movement in three orthogonal plans. The actual node locations will be selected through a coordinated effort between the CGS Plant Technical and Technology organizations. In this way the analytically best suited node will be coupled with accessible locations. General Electric will provide 14.2-90

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 locations and acceptance criteria for the recirculation and main steam systems. The Energy Northwest Mechanics Department will provide similar information for the remainder of the systems tested. The instruments will provide thermal movement and vibration data that will be compared with predicted values. If these measured displacements confirm the calculated values, coupled with acceptable visual inspections, the piping system will be considered to have responded as designed. The type of lanyard potentiometer monitors used enable the collection of thermal movement and vibration data. With the acceptance criteria for all testing based on the system design, conformance to the acceptance criteria indicates adherence to the analytical limits.
On completion of the startup test, the piping response data and the completed test procedure will be reviewed by the Energy Northwest Engineering Department responsible for the Stress Report Review and GE. The review will determine if the test results indicate the piping responded in a manner consistent with the Stress Report predictions and the ASME Code limits.
An Energy Northwest Level 3 inspector and the American Nuclear Insurers (ANI) will sign all data sheets performing ASME Section XI inspections.
The drywell piping testing/inspections will be conducted during the PATP as follows:
: a. The visual inspections and thermal expansion data will be taken during the initial reactor heatup at thermal equilibrium conditions,
: b. During the course of the PATP, data will be collected during steady state and transient conditions for vibration level evaluation, and
: c. Near the end of the PATP a final drywell entry and inspection is scheduled.
Visual inspections will be conducted on selected piping systems outside the drywell during thermal equilibrium, steady-state operation, and selected transient conditions. The systems selected are:
: a. Main steam,
: b. Condensate and feedwater,
: c. RCIC steam supply and exhaust,
: d. RCIC injection piping,
: e. RHR shutdown cooling supply and return,
: f. Reactor water cleanup, and
: g. Main steam leakage control system.
14.2-91

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 14.2.12.3.17.4 Criteria.
Level 1 Thermally induced displacement of system components shall be unrestrained with no evidence of binding or impairment.
Spring hangers shall not be bottomed out or have the spring fully stretched.
Snubbers shall not reach the limits of their travel. The displacements at the established transducer locations used to measure pipe deflections shall not exceed the allowable values.
The allowable values of displacement shall be based on not exceeding ASME Section III Code Stress allowables.
Level 2 Spring hangers will be in their operating range (between the hot and cold settings).
Snubber settings must be within their expected operating range.
The displacements at the established transducer locations shall not exceed the expected values.
14.2.12.3.18       Test Number 18 - Core Power Distribution 14.2.12.3.18.1 Purpose. The purpose of this test is to determine the reproducibility of the TIP system readings.
14.2.12.3.18.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing. The TIP detector and dummy detector, ball valve time delay, core top and bottom limits, clutch, x-y recorder, and purge system will have been shown to be operational. Instrumentation has been calibrated and installed.
14.2.12.3.18.3 Description. The TIP reproducibility consists of a random noise component and a geometric component. The geometric component is due to variation in the water gap geometry and TIP tube orientation from TIP location to location. Measurement of these components is obtained by taking repetitive TIP readings at a single TIP location, and by analyzing pairs of TIP readings taken at TIP locations which are symmetrical about the core diagonal of fuel loading symmetry.
One set of TIP data will be taken at the 50% power level and at least one other set at 75%
power or above.
14.2-92

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 The TIP data will be taken with the reactor operating with an octant symmetric rod pattern and at steady-state conditions.
The total TIP reproducibility is obtained by dividing the standard deviation of the symmetric TIP pair nodal ratios by two. The nodal TIP ratio is defined as the nodal base value of the TIP in the lower right half of the core divided by its symmetric counterpart in the upper left half.
The total TIP reproducibility value that is compared with the test criterion is the average value of the data sets taken.
The random noise uncertainty is obtained from successive TIP runs made at the common hole, with each of the TIP machines making six runs. The standard deviation of the random noise is derived by taking the square root of the average of the variances at nodal levels 5 through 22, where the nodal variance is obtained from the fractional deviations of the successive TIP values about their nodal mean value.
The geometric component of TIP reproducibility is obtained by statistically subtracting the random noise component from the total TIP reproducibility.
14.2.12.3.18.4 Criteria.
Level 1 Not applicable.
Level 2 The total TIP uncertainty (including random noise and geometrical uncertainties) obtained by averaging the uncertainties for all data sets shall be less than 6.0%.
The data acquired for random noise uncertainty does not have specific acceptance criteria value and is used only to aid in the analysis of the TIP uncertainty.
14.2.12.3.19        Test Number 19 - Core Performance 14.2.12.3.19.1 Purpose. The purposes of this test are to (a) evaluate the core thermal power, and (b) evaluate the following core performance parameters are within limits: (a) maximum linear heat generation rate (MLHGR), (b) minimum critical power ratio (MCPR), and (c) maximum average planar linear heat generation rate (MAPLHGR).
14.2.12.3.19.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
System instrumentation has been installed and calibrated, and test instrumentation has been calibrated.
14.2-93

COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                           December 2003 14.2.12.3.19.3 Description. The core performance evaluation is employed to determine the principal thermal and hydraulic parameters associated with core behavior. These parameters are
: a.      Core flow rate,
: b.      Core thermal power level,
: c.      MLHGR,
: d.      MAPLHGR, and
: e.      MCPR.
The core performance parameters will be evaluated by manual calculation techniques described in Startup Test Instruction 19 or may be obtained from the process computer.
If the process computer is used as a primary means to obtain these parameters, it must be proven that it agrees with BUCLE within 2% on all thermal parameters (see Test Number 13).
If both BUCLE and the process computer are not available, the manual calculation techniques described in Startup Test Instruction 19 can be used for the core performance evaluation.
14.2.12.3.19.4 Criteria.
Level 1 The MLHGR of any rod during steady-state conditions shall not exceed the limit specified by the Technical Specifications.
The steady-state MCPR shall not exceed the minimum limits specified by the Technical Specifications.
The MAPLHGR shall not exceed the limits specified by the Technical Specifications.
Steady-state reactor power shall be limited to the rated MWt and values on or below the design flow control line. Core flow shall not exceed its rated value.
Level 2 Not applicable.
14.2.12.3.20       Test Number 20 - Steam Production 14.2.12.3.20.1 Purpose. The purpose of performing this test is to demonstrate that the NSSS is providing steam sufficient to satisfy all appropriate warranties as defined in the contract.
14.2-94

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 14.2.12.3.20.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
14.2.12.3.20.3 Description. Warranty demonstration consists of recording sufficient data under steady-state conditions to determine the reactor power level, the pressure and quality of the steam, and the steam flow rate from the reactor.
These measurements will include the temperature, pressure, and flow rate of feedwater entering the reactor; the energy added to the reactor water by the recirculation drive pumps; the flow rate through and temperature entering and leaving the reactor cleanup system; the flow rate and temperature of the CRD cooling water; the carryover of reactor water into the steam lines, and the steam pressure outside the drywell near the MSIV.
Each set of measurements shall be taken at frequent intervals, every 5 or 10 minutes as appropriate, for a total test run duration of 4 hr. The average measure quantity, suitably corrected for all calibration factors, is used to determine NSSS output during the test run.
Where the contract requires a 100-hr demonstration, two test runs shall be made, one in the first 50 hr and one in the second 50 hr. The demonstrated output is the average of the values from the two test runs. During the balance of the 100-hr demonstration, the NSSS output shall be held constant within +/- 5% of the nominal steam flow rate as indicated by the installed plant feedwater instrumentation.
14.2.12.3.20.4 Criteria.
Level 1
: a. The NSSS parameters as determined by using normal operating procedures shall be within the appropriate license restrictions.
: b. The NSSS will be capable of supplying steam in an amount and quality corresponding to the final feedwater temperature and other conditions shown on the rated steam output curve in the NSSS technical description. The rated steam output curve provides the warrantable reactor vessel steam output as a function of feedwater temperature, as well as warrantable steam conditions at the outboard MSIVs.
: c. Thermodynamic parameters are consistent with the 1967 ASME steam tables.
Correction techniques for conditions that differ from the contracted conditions will be mutually agreed to prior to the performance of the test.
Level 2 Not applicable.
14.2-95

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 14.2.12.3.21       Test Number 21 - Core Power-Void Mode 14.2.12.3.21.1 Purpose. The purpose of this test is to measure the stability of the core power-void dynamic response and to demonstrate that its behavior is within specified limits.
14.2.12.3.21.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
System instrumentation has been installed and calibrated, and test instrumentation calibrated.
14.2.12.3.21.3 Description. The core power void loop mode that results from a combination of the neutron kinetics and core thermal hydraulic dynamics is least stable near the natural circulation end of the rated 100% power rod line. A fast change in the reactivity balance is obtained by a pressure regulator step change (see test 22) and by moving a very high worth rod only 1 or 2 notches. Both local flux and total core response will be evaluated by monitoring selected LPRMs during the transient.
14.2.12.3.21.4 Criteria.
Level 1 The transient response of any system-related variable to any test input must not diverge.
Level 2 The decay ratio for each system-related variable containing oscillatory modes must be less than or equal to 0.5.
14.2.12.3.22       Test Number 22 - Pressure Regulator 14.2.12.3.22.1 Purpose. The purposes of this test are to: (a) determine the optimum settings for the pressure control loop by analysis of the transients induced in the reactor pressure control system by means of the pressure regulators, (b) demonstrate the backup capability of the pressure regulators via simulated failure of the controlling pressure regulator and to set the regulating pressure difference between the two regulators at an appropriate value, (c) demonstrate smooth pressure control transition between the control valves and bypass valves when reactor steam generation exceeds steam used by the turbine, and (d) demonstrate that affected parameters are within acceptable limits during pressure-regulator-induced transient maneuvers.
14.2.12.3.22.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2-96

COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                           December 2003 14.2.12.3.22.3 Description. The pressure setpoint will be decreased rapidly and then increased rapidly by about 10 psi (0.7 kg/cm2) and the response of the system will be measured in each case. It is desirable to accomplish the setpoint change in less than 1 sec. At specified test conditions the load limit setpoint will be set so that the transient is handled by control valves, bypass valves, and both. The regulators will be tested by simulating a failure of a selected pressure regulator so that the other regulator will take over control. The response of the system will be measured and evaluated and regulator settings will be optimized.
14.2.12.3.22.4 Criteria.
Level 1 The transient response of any pressure control system related variable to any test input must not diverge.
Level 2
: a.      Pressure control system variables may contain oscillatory modes of response. In these cases, the decay ratio for each controlled mode of response must be less than or equal to 0.25,
: b.      The pressure response time from initiation of pressure setpoint change to the turbine inlet pressure peak shall be 10 sec,
: c.      Pressure control system deadband, delay, etc., shall be small enough that steady-state limit cycles (if any) shall produce steam flow variations no larger than +/- 0.5% of rated steam flow,
: d.      For all pressure regulator transients the peak neutron flux and/or peak vessel pressure shall remain below the scram settings by 7.5% and 10 psi respectively (maintain a plot of power versus the peak variable values along the 100% rod line), and
: e.      The variation in incremental regulation (ratio of the maximum to the minimum valve of the quantity, incremental change in pressure control signal/incremental change in steam flow, for each flow range) shall meet the following:
14.2-97

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 Steam Flow Obtained With Valves Wide Open (%)                 Variation 0 to 90                        4:1 90 to 97                       2:1 90 to 99                       5:1 Level 3
: a. Additional dynamics of the control system, outside of the regulator compensation filters, shall be equivalent to a time constant no greater than 0.10 sec. This also includes any dead time which may exist,
: b. Control or bypass valve motion must respond to pressure inputs with deadband (insensitivity) no greater than +/- 0.1 psi, and
: c. Dynamics of both pressure regulators will be essentially identical.
14.2.12.3.23        Test Number 23 - Feedwater System 14.2.12.3.23.1 23A - Water Level Setpoint and Manual Flow Changes.
14.2.12.3.23.1.1 Purpose. The purpose of this test is to verify that the feedwater system has been adjusted to provide acceptable reactor water level control.
14.2.12.3.23.1.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.23.1.3 Description. Reactor water level setpoint changes of approximately 3 in. to 6 in. (8 cm to 15 cm) will be used to evaluate (and adjust if necessary) the feedwater control system settings for all power and feedwater pump modes. The level setpoint changes will also demonstrate core stability to subcooling changes.
14.2.12.3.23.1.4 Criteria.
Level 1 The transient response of any level control system-related variable to any test must not diverge.
14.2-98

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 Level 2
: a. Level control system-related variables may contain oscillatory modes of response. In these cases, the decay ratio for each controlled mode of response must be less than or equal to 0.25;
: b. The open loop dynamic flow response of each feedwater actuator (turbine or valve) to small (<10%) step disturbances shall be
: 1.       Maximum time to 10% of a step disturbance             1.1 sec
: 2.       Maximum time from 10% to 90% of a                     1.9 sec step disturbance
: 3.       Peak overshoot (% of step disturbance)                15%
: 4.       Settling time, 100%, +/- 5%                             14 sec
: c. The average rate of response of the feedwater actuator to large (>20% of pump flow) step disturbances shall be between 10% and 25% rated feedwater flow/sec. This average response rate will be assessed by determining the time required to pass linearly through the 10% and 90% response points; and
: d. At steady-state generation for the 3/1 element system, the input scaling to be mismatch gain should be adjusted such that level error due to biased mismatch gain output should be within +/- 1 in.
Level 3
: a. The dynamic response of each individual level or flow sensor shall be as fast as possible. Band width must be at least 4.0 radians/sec (faster than 0.25 sec equivalent time constant), except for the steam flow sensors which must have band width of at least 1.0 radian/sec (faster than 1.0 sec equivalent time constant);
: b. Vessel level, feedwater flow, and steam flow sensors must be installed with sufficiently short lines and proper damping adjustment so that no resonances exist;
: c. Initial settings of the function generators should give a straight line. The function generators must be adjusted so that the change in slope (actual fluid flow change divided by demand change for small disturbances) shall not exceed a factor of 2 to 1 (maximum slope versus minimum slope) over the entire 20% to 14.2-99

COLUMBIA GENERATING STATION                          Amendment 54 FINAL SAFETY ANALYSIS REPORT                         April 2000 100% feed flow range. Also the function generators should be used to minimize the differences between feedwater actuators (pumps and/or valves); and
: d.      All auxiliary controls which have direct impact on reactor level and feedwater control (e.g., feed pump minimum recirculation flow valve control) should be functional, responsive, and stable. The minimum low valve control should be fast enough to avoid pump trips and yet slower than the feedwater startup valve to avoid possible reactor flux scram due to a cold water slug.
14.2.12.3.23.2 23B - Loss of Feedwater Heating 14.2.12.3.23.2.1 Purpose. The purpose of this test is to demonstrate adequate response to a feedwater temperature loss.
14.2.12.3.23.2.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.23.2.3 Description. The condensate/feedwater system will be studied to determine the single failure that will cause the largest loss in feedwater heating. This event will then be performed at between 80% and 90% power with the recirculation flow near its rated value.
14.2.12.3.23.2.4 Criteria.
Level 1
: a.      For the feedwater heater loss test, the maximum feedwater temperature decrease due to a single failure case must be 100&deg;F. The resultant MCPR must be greater than the fuel thermal safety limit; and
: b.      The increase in simulated heat flux cannot exceed the predicted Level 2 value by more than 2%. The predicted value will be based on the actual test values of feedwater temperature change and power level.
Level 2 The increase in simulated heat flux cannot exceed the predicted value in the Transient Safety Analysis Design Report referenced to the actual feedwater temperature change and power level.
LDCN-99-000                                   14.2-100

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998 14.2.12.3.23.3 22C - Feedwater Pump Trip.
14.2.12.3.23.3.1 Purpose. The purpose of this test is to demonstrate the capability of the automatic core flow runback feature to prevent low water level scram following the trip of one feedwater pump.
14.2.12.3.23.3.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.23.3.3 Description. One of the two operating feedwater pumps will be tripped and the automatic recirculation runback circuit will act to drop the power to within the capacity of the remaining feedwater pump. Prior to the test a simulation of the feedwater pump trip will be done to verify the runback capability of the recirculation system. This test should be performed after test 23D (limiting pump speeds).
14.2.12.3.23.3.4 Criteria.
Level 1 Not applicable.
Level 2 The reactor shall avoid low water level scram by a 3-in. margin from an initial water level halfway between the high- and low-level alarm setpoints.
14.2.12.3.23.4 23D - Maximum Feedwater Runout Capability.
14.2.12.3.23.4.1 Purpose. This test calibrates the feedwater flow and determines if the maximum feedwater runout capability is compatible with the licensing.
14.2.12.3.23.4.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.23.4.3 Description. The test is divided into two parts: first, the initial calibration of the speed controller and second, verification of calibration by measured data which includes a verification that the maximum feedwater flows do not exceed the flows (different flows at different vessel pressures) in the FSAR.
: a.      The speed controller calibration is done by first obtaining vendor pump performance curves. The pump performance curves are then used to determine 14.2-101

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 the turbine speed corresponding to the maximum allowable flow rated vessel pressure specified by the FSAR and the minimum speed that corresponds to 0%
flow at 865 psia. Additionally, for good level control system performance it should reach 115% nuclear boiler rated (NBR) flow at 1080 psia and 90% NBR flow at 1024 psi in the one pump tripped condition. Adjustable equipment (i.e.,
feed pump turbine speed loops, mechanical limiters, and feedwater control system function generator, etc.) are set to prevent the feedwater pumps from exceeding their maximum allowed output and yet allow the desirable performance; and
: b. During the data collection and verification of calibration portion of the test, pressure, flow, and controller data will be collected between 60%-100% power.
Measured data will be compared against expected values to ensure proper calibration. The measured maximum flow will be adjusted to the FSAR pressures using the measured data. The maximum flows stated in the FSAR are used as licensing assumptions; therefore, the FSAR maximum flows should not be exceeded. If, however, the FSAR maximum flows are exceeded two options exist. The system can be adjusted so that the licensing assumption is not exceeded or an additional penalty can be applied to the CPR. The CPR can be revised by applying a 0.01 adder for each 5% of rated feedwater flow difference (between the determined actual maximum flow and the FSAR maximum flow).
14.2.12.3.23.4.4 Criteria.
Level 1 Maximum speed attained shall not exceed the speeds which will give the following flows with the normal complement of pumps operating.
: a. F% NBR at P psia, and
: b.    [F% + A(P-P rated)] % NBR at P rated, psig where: F = 135%, P = 1075 psia, A = 0.2%/psig.
Level 2 The maximum speed must be greater than the calculated speeds required to supply:
: a. With rated complement of pumps -115% NBR at 1075 psi, and
: b. One feedwater pump tripped condition -68% NBR at 1025 psia.
NOTE:         Level 1 test criteria are originated from NSSS transient Performance Engineering Unit. Level 2 test criteria are originated from the Control System Design Unit.
14.2-102

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 14.2.12.3.24        Test Number 24 - Turbine Valve Surveillance 14.2.12.3.24.1 Purpose. The purpose of this test is to demonstrate the acceptable procedures and maximum power levels for recommended periodic surveillance testing of the main turbine, control, and stop and bypass valves without producing a reactor scram.
14.2.12.3.24.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.24.3 Description. Individual main turbine control and stop and bypass valves are tested routinely during plant operation as required for turbine surveillance testing. At several test points the response of the reactor will be observed. It is recommended that the maximum possible power level for performance of these tests along the 100% load line be established.
First, actuation should be between 45% and 65% power and used to extrapolate to the next test point between 75% and 90% power and ultimately to the maximum power test condition with ample margin to scram. Note the proximity to APRM flow bias scram point and preconditioning cladding interim operating management recommendation (PCIOMR) envelope.
Each valve test will be manually initiated and reset. The rate of valve stroking and timing of the close-open sequence will be such that the minimum practical disturbance is introduced and that PCIOMR limits are not exceeded.
14.2.12.3.24.4 Criteria.
Level 1 Not applicable.
Level 2
: a.      Peak neutron flux must be at least 7.5% below the scram trip setting. Peak vessel pressure must remain at least 10 psi below the high pressure scram setting. Peak heat flux must remain at least 5.0% below its scram trip point; and
: b.      Peak steam flow in each line must remain 10% below the high flow isolation trip setting.
14.2-103

COLUMBIA GENERATING STATION                             Amendment 53 FINAL SAFETY ANALYSIS REPORT                           November 1998 14.2.12.3.25       Test Number 25 - Main Steam Isolation Valves 14.2.12.3.25.1 25A - Main Steam Isolation Valve Function Tests.
14.2.12.3.25.1.1 Purpose. The purposes of this test are to (a) functionally check the MSIVs for proper operation at selected power levels, (b) determine isolation valve closure times, and (c) determine a maximum power at which full closures of a single valve can be performed without a scram.
14.2.12.3.25.1.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.25.1.3 Description. At 5% and greater reactor power levels, individual fast closure of each MSIV will be performed to verify their functional performance and to determine closure times. The times to be determined are (a) the time from deenergizing the solenoids until the valve is 100% closed (tsol), and (b) the valve stroke time (ts) Time tsol equals the interval from deenergizing the solenoids until the valve reaches 90% closed plus 1/8 times the interval from 10% to 90% closure. Time ts equals the interval from when the valve starts to move until it is 100% closed and is based on the interval from 10% to 90% closure and linear valve travel from 0% to 100% closure.
To determine the maximum power level at which full individual closures can be performed without a scram, first actuation will be performed between 40% to 55% power and used to extrapolate to the next test point between 60% and 85% power and ultimately to the maximum power test condition with ample margin to scram.
14.2.12.3.25.1.4 Criteria.
Level 1 The MSIV stroke time (ts) shall be not faster than 3.0 sec (average of the fastest valve in each steam line) and for any individual valve 2.5 sec ts5 sec. Total effective closure time for any individual MSIV shall be tsol plus the maximum instrumentation delay time as determined in preoperational test GE-4 and shall be 5.5 sec.
Level 2
: a. The reactor shall not scram or isolate, and
: b. During full closure of individual valves, peak valve pressure must be 10 psi (0.7 kg/cm2) below scram, peak neutron flux must be 7.5% below scram, and 14.2-104

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 steam flow in individual lines must be 10% below the isolation trip setting. The peak heat flux must be 5% less than its trip point.
14.2.12.3.25.2 25B - Full Reactor Isolation.
14.2.12.3.25.2.1 Purpose. The purpose of this test is to determine the reactor transient behavior that results from the simultaneous full closure of all MSIVs.
14.2.12.3.25.2.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.25.2.3 Description. A test of the simultaneous full closure of all MSIVs will be performed at >75% of rated thermal power. Correct performance of the RCIC and relief valves will be shown. Reactor process variables will be monitored to determine the transient behavior of the system during and following the main steam line isolation.
14.2.12.3.25.2.4 Criteria.
Level 1
: a.      Reactor must scram to limit the severity of the neutron flux and simulated fuel surface heat flux transient,
: b. Feedwater system settings must prevent flooding of the steam lines,
: c.      The recorded MSIV full closure times must meet the previously stated timing specifications (test 25A), and
: d.      The positive change in vessel dome pressure occurring within 30 sec after closure of all MSIV valves must not exceed the Level 2 criteria by more than 25 psi. The positive change in simulated heat flux shall not exceed the Level 2 criteria by more than 2% of rated value.
Level 2
: a. The temperature measured by the thermocouples on the discharge side of the SRVs must return to within 10&deg;F of the temperature recorded before the valve was opened. If pressure sensors are available, they shall return to their initial state upon valve closure;
: b.      For the full MSIV closure from full power predicted analytical results based on beginning-of-cycle design basis analysis, assuming no equipment failures and 14.2-105

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998 applying appropriate parametric corrections, will be used as the basis to which the actual transient is compared.
: c.      Initial action of RCIC and HPCS shall be automatic if low water level (L2) is reached, and system performance shall be within specification, and
: d.      Recirculation pump trip shall be initiated if low water level (L2) is reached.
Recirculation pump power will shift to the LFMGs if low water level (L3) is reached.
14.2.12.3.26        Test Number 26 - Relief Valves 14.2.12.3.26.1 Purpose. The purposes of this test are to (a) verify the proper operation of the main system relief valves, (b) verify that the discharge piping is not blocked, (c) verify their proper seating following operation, (d) obtain signature information of relief valve response for subsequent comparisons, and (e) determine their capacities.
14.2.12.3.26.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.26.3 Description. The main steam relief valves will each be opened using the manual control mode so that at any time only one is open. During heatup at 250 psig (17.5 kg/cm2), each valve will be opened and closed to demonstrate proper functioning. Flow verification of each relief valve will be determined at rate pressure by observing bypass or control valve motion and by observing a change in discharge thermocouple readings. Proper reseating of each relief valve will be verified by observation of temperatures in the relief valve discharge piping. At selected test conditions each valve will be manually actuated and appropriate system parameters recorded during the transient. Data analysis will include a comparison of the system response during each of the valve actuations. Capacity of each relief valve will be determined at rated pressure by the amount of bypass or control valve closure required to maintain reactor pressure.
14.2.12.3.26.4 Criteria.
Level 1 There should be positive indication of steam discharge during the manual actuation of each valve.
The sum of capacity measurements from all relief valves shall be equal to or greater than 15.8 x 106 lb/hr at an inlet pressure of 103% at 1205 psig. The total flow capacity of the SRVs used in the automatic depressurization system must be equal to or greater than 4.8 x 106 lb/hr 14.2-106

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 at 1125 psig when the valve having the highest measured capacity is assumed to be out of service.
Level 2 Relief valve leakage shall be low enough that the temperature measured by the thermocouples in the discharge side of the valves returns to within 10&deg;F (5.6&deg;C) of the temperature recorded before the valve was opened. The thermocouples are expected to be operating properly.
The pressure regulator must satisfactorily control the reactor transient and close the control valves or bypass valves by an amount equivalent to the relief valve discharge. The valve transients recorder signatures for each valve must be returned to GE in San Jose for relative system response comparison.
Each relief valve shall have a capacity between 90% and 122.5% of its expected value corrected to an inlet pressure of 103% at 1205 psig.
No more than 25% of the relief valves may have an individual corrected flow rate that is between 90% and 100% of their expected flow rates.
The transient recorder signatures for each valve must be analyzed for relative system response comparison.
14.2.12.3.27        Test Number 27 - Turbine Trip and Generator Load Rejection 14.2.12.3.27.1 Purpose. The purpose of this test is to demonstrate the response of the reactor and its control systems to protective trips in the turbine and generator.
14.2.12.3.27.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing. All controls and interlocks are checked and instrumentation calibrated. The plant electrical system will be aligned in the normal mode for the operating condition at which the test is performed.
14.2.12.3.27.3 Description. Turbine trip (closure of the main turbine stop valves within 0.1 sec) and generator trip (closure of the main turbine control valves in about 0.1 sec to 0.2 sec) will be performed at selected power levels during the startup test program. At low power levels, reactor protection following the trip is provided by high neutron flux and vessel high pressure scram. For the protective trips occurring at intermediate and higher power levels, reactor will scram by relays, actuated by control or stop valve motion.
A generator trip will be performed at low power level such that nuclear boiler steam generation is just within the bypass valve capacity to demonstrate scram avoidance.
14.2-107

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998 For the trips performed at intermediate power range, reactor scram is most important in controlling the transient peaks.
Above 40% power, the recirculation pump circuit breakers are both automatically tripped, and subsequent transient pressure rise will be limited by the opening of the bypass valves initially and the SRVs if necessary.
14.2.12.3.27.4 Criteria.
Level 1
: a. For turbine and generator trips at power levels greater than 50% NBR, there should be a delay of less than 0.1 sec following the beginning of control or stop valve closure before the beginning of bypass valve opening. The bypass valves should be opened to a point corresponding to greater than or equal to 80% of their capacity within 0.3 sec from the beginning of control or stop valve closure motion;
: b. Feedwater system settings must prevent flooding of the steam line following these transients;
: c. The two pump drive flow coastdown transient during the first 6 sec must be equal to or faster than that specified in test 30B (see Figure 14.2-6);
: d. The positive change in vessel dome pressure occurring within 30 sec after either generator or turbine trip must not exceed the Level 2 criteria by more than 25 psi;
: e. The positive change in simulated heat flux shall not exceed the Level 2 criteria by more than 2% of the rated value; and
: f. The total time delay from start of turbine stop valve motion or control valve motion to the complete suppression of electrical arc between the fully open contacts of the recirculation pump trip (RPT) circuit breakers shall be less than 190 msec.
Level 2
: a. There shall be no MSIV closure during the first 3 minutes of the transient, and operator action shall not be required during that period to avoid the MSIV trip.
(The operator may take action after the first 3 minutes, including switching out of run mode. The operator may also switch out of run mode in the first 14.2-108

COLUMBIA GENERATING STATION                             Amendment 53 FINAL SAFETY ANALYSIS REPORT                            November 1998 3 minutes if measured data confirms that his action did not prevent MSIV closure);
: b. The positive change in vessel dome pressure and in simulated heat flux which occurs within the first 30 sec after the initiation of either generator or turbine trip must not exceed the predicted values. [Predicted values will be referenced to actual test conditions of initial power life and dome pressure and will use beginning of life (BOL) nuclear data. Worst case design or Technical Specification values of all hardware performance shall be used in the prediction with the exception of control rod insertion time and the delay from beginning of turbine control valve or stop valve motion to the generation of the scram signal.
The predicted pressure and heat flux will be corrected for the actual measured values of these two parameters];
: c. For the generator grip within the bypass valves capacity, the reactor shall not scram for initial thermal power values within that bypass valve capacity;
: d. The measured bypass capacity (in percent of rated power) shall be equal or greater than that used for the FSAR analysis (3,576,000 lb/hr);
: e. Recirculation LFMG sets shall take over after the initial recirculation pump trips and adequate vessel temperature difference shall be maintained;
: f. Feedwater level control shall avoid loss of feedwater due to possible high level (L8) trip during the event;
: g. Low water level total recirculation pump trip, HPCS, and RCIC shall not be initiated; and
: h. The temperature measured by thermocouples on the discharge side of the SRVs must return to within 10&deg;F of the temperature recorded before the valve was opened. In addition the acoustical monitors should indicate the valve is closed after the transient is complete.
14.2.12.3.28        Test Number 28 - Shutdown From Outside the Main Control Room 14.2.12.3.28.1 Purpose. The purpose of this test is to demonstrate that the reactor can be brought down from a normal initial steady-state power level to the point where cooldown is established and under control with reactor vessel pressure and water level controlled from outside the control room.
14.2-109

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998 14.2.12.3.28.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.28.3 Description. The test will be performed at a low power level and will consist of demonstrating the capability to control reactor level and pressure from outside the control room. The reactor will be scrammed and isolated from the control room. Reactor pressure and water level will be controlled using SRVs, RCIC, and RHR from outside the control room during the subsequent cooldown. In addition, the RHR shutdown cooling mode will be placed in service from outside the control room. All other operator actions not directly related to maintaining vessel water level and pressure will be performed in the main control room.
Operation from the main control room to protect or secure systems not related to the controlled cooldown of the reactor is permitted during this test. These actions are recorded and later evaluated to determine if they had bearing on the transient.
14.2.12.3.28.4 Criteria.
Level 1 Not applicable.
Level 2 During a simulated main control room evacuation, the reactor must be brought to the point where cooldown can be initiated, and the reactor vessel pressure and water level must be controlled using equipment and controls outside the main control room.
14.2.12.3.29       Test Number 29 - Recirculation Flow Control 14.2.12.3.29.1 29A - Valve Position Control.
14.2.12.3.29.1.1 Purpose. The purpose of this test is to demonstrate the recirculation flow control systems capability while in the valve position (POS) mode.
14.2.12.3.29.1.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing. All controls are checked and instrumentation calibrated.
14.2.12.3.29.1.3 Description. The testing of the recirculation flow control system follows a building block approach while the plant is ascending from low to high power levels:
Components and inner control loops are tested first, followed by drive flow control and plant power maneuvers to adjust and then demonstrate the outer loop controller performance.
Preliminary component and valve position loop tests will be run when the plant is in cold 14.2-110

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 shutdown to visually observe the hydraulic cylinder response. While operating at low power with the pumps using the low frequency power supply, small step changes will input into the position controller and the response recorded.
14.2.12.3.29.1.4 Criteria.
Level 1 The transient response of any recirculation system related variables to any test input must not diverge.
Level 2
: a. Recirculation system related variables may contain oscillatory modes of response. In these cases, the decay ratio for each controlled mode of response must be less than or equal to 0.25,
: b. Maximum rate of change of valve position shall be 10 +/- 1% sec.
During TC-3 and TC-6 while operating on the high speed (60 Hz) source, gains and limiters shall be set to obtain the following response,
: c. Delay time for position demand step shall be For step inputs of 0.5% to 5% 0.15 sec.
For step inputs of 0.2% to 0.5%-
: d. Response time for position demand step shall be For step inputs of 0.5% to 5% 0.45 sec.
For step inputs of 0.2% to 0.5%-, and
: e. Overshoot after a small position demand input (1% to 5%) step shall be 10% of magnitude of input.
Level 3
: a. Gains shall be set to give as fast a response as possible for small position demand input within the overshoot criterion (e) and without additional valve duty cycle. (See test 29B, Section 14.2.12.3.29.2, for valve duty cycle measurement.)
: b. Position loop deadband shall be 0.2% of full valve stroke.
14.2-111

COLUMBIA GENERATING STATION                            Amendment 53 FINAL SAFETY ANALYSIS REPORT                           November 1998 NOTE:       At a minimum, performing tests near the high and low end of the specified range is acceptable for verifying step input response.
14.2.12.3.29.2 29B - Recirculation Flow Loop Control.
14.2.12.3.29.2.1 Purpose. The purposes of this test are to (a) demonstrate the core flow systems control capability over the entire flow control range, including both core flow neutron flux and load following modes of operation, and (b) determine that all electrical compensators and controllers are set for desired system performance and stability.
14.2.12.3.29.2.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing. All controls are checked and instrumentation calibrated.
14.2.12.3.29.2.3 Description. Following the initial position mode tests of 29A the final adjustment of the position loop gains, flow loop gains, and preliminary valves of the flux loop adjustments will be made on the mid-power line. This will be the most extensive testing of the recirculation control system. The core power distribution will be adjusted by control rods to permit broader range of maneuverability with respect to PCIOMR. In general, the controller dials and gains will be raised to meet the maneuvering performance objectives. Thus, the system will be set to be the slowest that will perform satisfactorily to maximize stability margins and to minimize equipment wear by avoiding controller overactivity.
Because of PCIOMR power maneuvering rate restrictions, the fast flow maneuvering adjustments are performed along a mid-power rod line, and extrapolation made to the expected results along the 100% rod line. The utility has the option to decide to
: a. Perform the faster power changes on the 100% rod line that are greater than what the PCIOMR allow, or
: b. To accept the mid-power load line demonstrations as acceptable proof of maneuverability.
For immediate commercial operation, the flux loop will be set slower and the operator will limit manual mode maneuvers. If PCIOMRs are ever withdrawn, the tested faster auto settings can be inserted onto the controller with only a brief dynamic test, rather than a full startup test.
14.2-112

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 14.2.12.3.29.2.4 Criteria.
Level 1 The transient response of any recirculation system related variable to any test input must not diverge.
Level 2
: a. The decay ratio of the flow loop response to any test inputs shall be <0.25,
: b. The flow loops provide equal flows in the two loops during steady-state operation. Flow loop gains should be set to correct a flow imbalance in less than 25 sec,
: c. The delay time for flow demand step (5%) shall be 0.4 sec or less,
: d. The response time for flow demand step (5%) shall be 1.1 sec or less,
: e. The maximum allowable flow over shoot for step demand of 5% of rated shall be 6% of the demand step, and
: f. The flow demand step settling time shall be 6 sec.
Level 3
: a. Incremental gain from function generator for valve position demand input to sensed drive flow shall not vary by more than 2 to 1 over the entire flow range, and
: b. Flow loop upper limit should be checked for proper setting.
Flux Loop Criteria Level 1 The flux loop response to test inputs shall not diverge.
Level 2
: a. Flux over shoot to a flux demand step shall not exceed 2% of rated for a step demand of 20% of rated, 14.2-113

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998
: b. The delay time for flux response to a flux demand step shall be 0.8 sec,
: c. The response time for flux demand stop shall be 2.5 sec, and
: d. The flux setting time shall be 15 sec for a flux demand step 20% of rated.
Scram Avoidance and General Criteria Level 1 Not applicable.
Level 2 For any one of the above loops test maneuvers, the trip avoidance margins must be at least the following:
: a. For APRM 7.5%, and
: b. For simulated heat flux 5.0%.
Flux Estimator Test Criteria Level 1 Not applicable.
Level 2
: a. Switching between estimated and sensed flux should not exceed 5 times/5 minutes at steady state, and
: b. During flux step transient there should be no switching to sensed flux or if switching does occur, it should switch back to estimated flux within 20 sec of the transient.
Flux Control Valve Duty Test Criteria Level 1 Not applicable.
14.2-114

COLUMBIA GENERATING STATION                            Amendment 55 FINAL SAFETY ANALYSIS REPORT                          May 2001 Level 2 The flow control valve duty cycle in any operating mode shall not exceed 0.2% Hz. Flow control valve duty cycle is defined as Integrated valve movement in percent (% Hz) 2x time span in seconds 14.2.12.3.30        Test Number 30 - Recirculation System 14.2.12.3.30.1 30A - One Pump Trip.
14.2.12.3.30.1.1 Purpose. The purposes of this test are to (a) obtain recirculation system performance data during the pump trip, flow coastdown, and pump restart, and (b) verify that the feedwater control system can satisfactorily control water level without a resulting turbine trip/scram.
14.2.12.3.30.1.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.30.1.3 Description. The reactor coolant recirculation system consists of the reactor vessel and two piping loops. Each loop contains a constant speed centrifugal recirculation pump, a flow control valve and two isolation valves located in the drywell, and 10 jet pumps in parallel, situated in the reactor downcomer and discharges through a manifold system to the nozzles of the 10 jet pumps. Here the flow is augmented by suction flow from the downcomer and delivered to the reactor inlet plenum.
A potential threat to plant availability is the high water level turbine trip scram caused by the level upswell that results after an unexpected recirculation one pump trip. The change in core flow and the resultant power decrease causes void formation which the level sensing system senses as a rise in water level. The one-pump trip tests are to prove that the water level will not rise enough to threaten a high level trip of the main turbine or the feedwater pumps.
14.2.12.3.30.1.4 Criteria.
Level 1 The reactor shall not scram during the one-pump trip recovery.
LDCN-01-000                                    14.2-115

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 Level 2 The reactor water level margin to avoid a high level trip shall be 3.0 in. during the one-pump trip.
NOTE: Margin to trip is defined as Margin (high level trip <8 setpoint) - (maximum water level reached ruing test) - (high level alarm <7 setpoint - initial water level) a       The simulated heat flux margin to avoid a scram shall be 5.0% during the one-pump trip and also during the recovery, and
: b.      The APRM margin to avoid a scram shall be 7.5% during the one-pump trip recovery.
14.2.12.3.30.2 30B - Recirculation Trip of Two Pumps.
14.2.12.3.30.2.1 Purpose. The purpose of the test is to record and verify acceptable performance of the recirculation two pump circuit trip system.
14.2.12.3.30.2.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.30.2.3 Description. In case of higher power turbine or generator trips, there is an automatic opening of circuit breakers in the pump power supply. The result is a fast core flow coastdown that helps reduce peak neutron and heat flow in such events. This two-pump trip test verifies that this flow coastdown is satisfactory prior to the high power turbine/generator trip tests and subsequent operation.
14.2.12.3.30.2.4 Criteria.
Level 1 The two-pump-drive flow coastdown transient during the first 6 sec must be bounded by the limiting curves. (See Figure 14.2-6.)
(The limiting curves will be determined based on measurement of the recirculation flow delta P using the elbow flow meters, transmitter time delay, and time constant.)
14.2-116

COLUMBIA GENERATING STATION                        Amendment 53 FINAL SAFETY ANALYSIS REPORT                       November 1998 Level 2 Not applicable.
14.2.12.3.30.3 30C - System Performance.
14.2.12.3.30.3.1 Purpose. The purpose of this test is to record recirculation system parameters during the power test program.
14.2.12.3.30.3.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.30.3.3 Description. Recirculation system parameters will be recorded at several power-flow conditions and in conjunction with single pump trip recoveries and internals vibration testing (if applicable).
14.2.12.3.30.3.4 Criteria.
Level 1 Not applicable.
Level 2
: a.      The core flow shortfall shall not exceed 5% at rated power,*
: b.      The measured core delta P shall not be 70.6 psi above prediction,*
: c.      The calculated jet pump M ration shall not be 0.2 points below prediction,*
: d.      The drive flow shortfall shall not exceed 5% at rated power,*
: e.      The measured recirculation pump efficiency shall not be 78% points below the vendor tested efficiency, and
: f.      The nozzle and riser plugging criteria shall not be exceeded.
The GE Steam Generation System Design Unit will provide predictions for the comparisons for these criteria.
14.2-117

COLUMBIA GENERATING STATION                            Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998 14.2.12.3.30.4 30D - Recirculation Pump Runback.
14.2.12.3.30.4.1 Purpose. The purpose of this test is to verify the adequacy of the recirculation runback to mitigate a scram on the loss of one feedwater pump.
14.2.12.3.30.4.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.30.4.3 Description. While operating at near rated recirculation flow, a loss of a feedwater pump will be simulated. The transient and final condition will be studied to determine the adequacy of the system in preventing a scram during the scheduled loss of a single feedwater pump test (test 23C).
14.2.12.3.30.4.4 Criteria.
Level 1 Not applicable.
Level 2 The recirculation flow control valves shall runback on a trip of the runback circuit.
14.2.12.3.30.5 30E - Recirculation System Cavitation.
14.2.12.3.30.5.1 Purpose. The purpose of this test is to verify that no recirculation system cavitation will occur in the operable region of the power-flow map.
14.2.12.3.30.5.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.30.5.3 Description. Both the jet pumps and the recirculation pumps will cavitate at conditions of high flow and low power where NPSH demands are high and little feedwater subcooling occurs. However, the recirculation flow will automatically run back on sensing a decrease in subcooling (as measured by the difference between the steam and recirculation loop temperature), to lower the reactor power. The maximum recirculation flow is limited by approximate stops which will run back the recirculation flow away from the possible cavitation region. It will be verified that these limits are sufficient to prevent operation where recirculation pump or jet pump cavitation is predicted to occur.
14.2-118

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 The recirculation system flow control valves will cavitate at conditions of high differential pressure and low power (low subcooling). The recirculation flow will automatically run back on sensing a decrease in subcooling (as measured by a low feedwater flow). This limit will be verified to ensure that operation is prevented where flow control valve cavitation may occur.
In both the above cases, flow runback is caused by a shift in the power supply to the recirculation pump motors from normal power to the LFMGs.
14.2.12.3.30.5.4 Criteria.
Level 1 Not applicable.
Level 2 Runback logic shall have settings adequate to prevent operation in areas of potential cavitation.
14.2.12.3.31        Test Number 31 - Loss of Turbine-Generator and Offsite Power 14.2.12.3.31.1 Purpose. This test determines electrical equipment and reactor system transient performance during a loss of auxiliary power.
14.2.12.3.31.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate. The plant electrical system will be aligned in the normal mode for the operating condition at which the test is performed.
14.2.12.3.31.3 Description. The loss of auxiliary power test will be performed at 20% to 30% of rated power. The proper response of reactor plant equipment, automatic switching equipment, and the proper sequencing of the diesel generator load will be verified.
Appropriate reactor parameters will be recorded during the resultant transient.
14.2.12.3.31.4 Criteria.
Level 1
: a.      Reactor protection system actions shall prevent violation of fuel thermal limits.
: b.      All safety systems, such as the RPS, the diesel generators, and HPCS must function properly without manual assistance. The HPCS and/or RCIC system action, if necessary, shall keep the reactor water level above the initiation level 14.2-119

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998 of the LPCS, LPCI, automatic depressurization systems, and MSIV closure.
Diesel generators shall start automatically and when they reach rated frequency and voltage the diesel breakers will close and restore power to the engineered safety features (ESF) buses.
Level 2
: a. Proper instrument display to the reactor operator shall be demonstrated, including power monitors, pressure, water level, control rod position, suppression pool temperature, and reactor cooling system status. Displays shall not be dependent on specially installed instrumentation, and
: b. If SRVs open, the temperature measured by thermocouples on the discharge side of the SRVs must return to within 10&deg;F of the temperature recorded before the valve was opened. If pressure sensors are available, they shall return to their initial state on valve closure.
14.2.12.3.32        Not Applicable 14.2.12.3.33        Test Number 33 - Piping Vibration 14.2.12.3.33.1 Purpose. The purpose of this test is to verify that the design stress levels due to piping vibration are not exceeded and satisfy the inspection requirements for condensate and feedwater systems according to Regulatory Guide 1.68.1.
14.2.12.3.33.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been installed and calibrated.
14.2.12.3.33.3 Description. This test is an extension of test 17 and has been procedurally combined with the system expansion test. During reactor operation, it is desirable to show that destructive level piping vibrations do not occur during steady-state conditions and during planned transients. Acceptable vibration levels are verified by measurement (using the same sensors used in test 17) and by visual observation during system walkdowns for selected piping systems outside containment. See Section 14.2.12.3.17.2 for systems selected and selection criteria.
14.2.12.3.33.4 Criteria.
Level 1 The measured vibration amplitude (peak-to-peak) of the systems monitored shall not exceed the maximum allowable displacements.
14.2-120

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998 Level 2 The measured amplitude (peak-to-peak) of vibration shall not exceed the expected values.
Visual Inspection Acceptance Criteria The vibration levels experienced will be evaluated as acceptable if they are too small to be detected by the naked eye with consideration given to the following:
: a.      Proximity to sensitive equipment (pumps, valves, motor control centers, control panels, etc.),
: b.      Branch connection behavior, and
: c.      Performance of nearby component supports.
If an acceptable assessment of the observed deflections cannot be performed and corrective measures are not available, the inspector will then obtain the magnitude and frequency of the vibration using a portable vibration instrument. The information will then be evaluated by the piping design engineer to verify acceptance. Unacceptable vibration levels will be treated as a Level 1 violation.
14.2.12.3.34        Test Number 34 - Reactor Pressure Vessel Internals Vibration 14.2.12.3.34.1 Purpose. The purpose of this test is to provide information needed to confirm the similarity between the reactor internals design and the prototype with respect to flow-induced vibration. Testing is in response to Regulatory Guide 1.20 for a vibration measurement program for nonprototype, Category IV reactor internals, and the GE vibration test specification 22A6601, Revision 0.
14.2.12.3.34.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.34.3 Description. During operation, the reactor structure may be forced into many modes of vibrations. Analytical work indicates that unacceptable level vibrations will not occur.
Detailed descriptions of sensor locations are given in GE Test Specification 22A6601, Revision 0.
14.2-121

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 Sensors used for the measurements are resistance wire strain gauges and accelerometers with double integrating output signal conditioning. Sensors will be installed in a manner to sense the most probable mode of vibration as indicated by analysis.
The test program consists of at power tests performed with the system at normal operating pressure and temperature.
During the vibration test the vibration engineer will monitor and record vibrating amplitudes and frequencies obtained from the sensors mounted on the various components. The measured amplitudes and frequencies are then compared to the acceptance criteria to ensure that all measured vibration amplitudes are within acceptable levels.
14.2.12.3.34.4 Criteria.
Level 1 The peak stress intensity may exceed 10,000 psi (single amplitude) when the component deformed in a manner corresponding to one of its normal or natural modes, but the fatigue usage factor must not exceed 1.0.
Level 2 The peak stress intensity shall not exceed 10,000 psi (single amplitude) when the component is deformed in a manner corresponding to one of its normal or natural modes. This is the low stress limit which is suitable for sustained vibration in the reactor environment for the design life of the reactor components.
14.2.12.3.35        Test Number 35 - Recirculation System Flow Calibration 14.2.12.3.35.1 Purpose. The purpose of this test is to perform complete calibration of the installed recirculation system flow instrumentation.
14.2.12.3.35.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.35.3 Description. During the testing program at operating conditions, which allow the recirculation system to be operated at rated flow at rated power, the jet pump flow instrumentation will be adjusted to provide correct flow indication based on the jet pump flow.
After the relationship between drive flow and core flow is established, the flow biased APRM/RBM system will be adjusted to match this relationship.
14.2-122

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998 14.2.12.3.35.4 Criteria.
Level 1 Not applicable.
Level 2 Jet pump flow instrumentation shall be adjusted such that the jet pump total flow recorder will provide a correct core flow indication at rated conditions.
The APRM/RBM flow-bias instrumentation shall be adjusted to function properly at rated conditions.
The flow control system shall be adjusted to limit maximum core flow to 102.5% of rated by limiting the flow control valve opening position.
14.2.12.3.36       Test Number 70 - Reactor Water Cleanup System 14.2.12.3.36.1 Purpose. The purpose of this test is to demonstrate specific aspects of the mechanical operability of the RWCU system. (This test, performed at rated reactor pressure and temperature, is actually the completion of the preoperational testing that could not be done without nuclear heating.)
14.2.12.3.36.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.36.3 Description. With the reactor at rated temperature and pressure, process variables will be recorded during steady-state operation in three modes as defined by the system process diagram: hot shutdown with loss of RPV recirculation pumps, normal, and blowdown. A comparison of the bottom head flow indicator and the RWCU inlet flow indicator will be made. The RWCU system sample station shall be tested at hot process conditions.
14.2.12.3.36.4 Criteria.
Level 1 Not applicable.
14.2-123

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998 Level 2 The temperature at the tube side outlet of the nonregenerative heat exchangers shall not exceed 130&deg;F (54&deg;C) in the blowdown mode and shall not exceed 120&deg;F in the normal mode.
The pump available NPSH will be 13 ft or greater during the hot shutdown with loss of RPV recirculation pumps mode defined in the process diagrams.
The cooling water supplied to the nonregenerative heat exchangers shall be less than 6% above the flow corresponding to the heat exchanger capacity (as determined from the process diagram) and the existing temperature differential across the heat exchangers. The outlet temperature shall not exceed 180&deg;F.
Recalibrate bottom head flow indicator (R610) against RWCU flow indicator (R609) if the deviation is greater than 25 gpm.
Pump vibration shall be less than or equal to 2 mils peak-to-peak (in any direction) as measured on the bearing housing and 2 mils peak-to-peak shaft vibration as measured on the coupling end.
14.2.12.3.37       Test Number 71 - Residual Heat Removal System 14.2.12.3.37.1 Purpose. The purpose of this test is to demonstrate the ability of the RHR system to remove heat from the reactor system so that the refueling and nuclear system servicing can be performed.
14.2.12.3.37.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.37.3 Description. During the first suitable reactor cooldown, the shutdown cooling mode of the RHR system will be demonstrated. Unfortunately, the decay heat load is insignificant during the startup test period. Use of the mode with low core exposure could result in exceeding the 100&deg;F/hr cooldown rate of the vessel if both RHR heat exchangers are used simultaneously. Late in the test program after accumulating significant core exposure, this demonstration would more adequately demonstrate the heat exchanger capacity.
14.2.12.3.37.4 Criteria.
Level 1 Not applicable.
14.2-124

COLUMBIA GENERATING STATION                            Amendment 53 FINAL SAFETY ANALYSIS REPORT                           November 1998 Level 2 The RHR system shall be capable of operating in the suppression pool cooling and shutdown cooling modes (with each heat exchanger) at the flow rates and temperature differentials determined by the flow rates and temperature differentials indicated on the process diagrams.
14.2.12.3.38       Test Number 72 - Drywell Atmosphere Cooling System 14.2.12.3.38.1 Purpose. The purpose of this test is to verify the ability of the drywell atmosphere cooling system to maintain design conditions in the drywell during operating conditions and post scram conditions.
14.2.12.3.38.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.38.3 Description. During heatup and power operation, data will be taken to ascertain that the drywell atmospheric conditions are within design limits.
14.2.12.3.38.4 Criteria.
Level 1 Not applicable.
Level 2 The drywell cooling system shall maintain drywell air temperatures at or below the design values as specified for the NSSS equipment.
14.2.12.3.39       Test Number 73 - Cooling Water Systems 14.2.12.3.39.1 Purpose. The purpose of the test is to verify that the heat removal performance of the SW system, the reactor building RCC system, and the plant service water (TSW) system is adequate.
14.2.12.3.39.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.39.3 Description. The SW, the RCC, and the TSW systems heat exchanger heat transport capabilities will be verified. Verification will be conducted in the following manner.
The system water flow rate through each heat exchanger will be measured. The system water 14.2-125

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998 temperature drop across each heat exchanger will also be measured. From these acquired water flow rates and temperature drop data, the heat transport rates will be calculated. Where available, the calculated heat transport data will be compared directly with design calculations to determine acceptability. For those systems in which no design calculations of the heat transport rate have been directly calculated, the heat removal performance of the particular heat exchanger will be considered acceptable if the components serviced by the cooling system exhibit proper operation. If proper performance is not experienced, adjustments in the heat transport capability (i.e., increased flow to the heat exchanger or increased flow to a particular load) would be made. In addition to the heat exchanger heat transport rate verification, the actual SW pump head will be determined for all three SW pumps. This actual SW pump head will be compared to the design requirements for acceptability.
14.2.12.3.39.4 Criteria.
Level 1 Not applicable.
Level 2 The system heat transport parameters either meet the requirements of the design specifications, or provide adequate cooling to the components serviced such that they operate satisfactorily.
14.2.12.3.40        Test Number 74 - Offgas System 14.2.12.3.40.1 Purpose. The purposes of this test are to verify the proper operation of the offgas system over its expected operating parameters and to determine the performance of the activated carbon adsorbers.
14.2.12.3.40.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.40.3 Description. The pressure, temperature, relative humidity, system flow, and percentage of radiolytic hydrogen in the offgas are periodically monitored during startup and at steady-state conditions. Prior to initial steam flow to the main condenser, charcoal bed hold-up times will be measure experimentally using a pulsed Krypton-85 gas injection technique. The charcoal bed dynamic adsorption coefficient will then be determined by established analytical methods. The performance of the catalytic recombiner will be compared the catalytic recombiner guaranteed performance curve.
14.2-126

COLUMBIA GENERATING STATION                          Amendment 54 FINAL SAFETY ANALYSIS REPORT                        April 2000 14.2.12.3.40.4 Criteria.
Level 1 The release of radioactive gaseous and particulate effluents must not exceed the limits specified in the Technical Specifications. There shall be no loss of flow of dilution steam to the noncondensing stage when the steam jet air ejectors are pumping.
Level 2 The system flow, pressure, temperature, and relative humidity shall comply with design specifications. The catalytic recombiner, the hydrogen analyzer, the activated carbon bed, and the filters shall be performing their required function.
LDCN-99-000                                  14.2-127

COLUMBIA GENERATING STATION             Amendment 53 FINAL SAFETY ANALYSIS REPORT            November 1998 Table 14.2-1 Preoperational Tests Section Reference                                 Title 14.2.12.1.1 Reactor Feedwater System 14.2.12.1.2 Condensate System 14.2.12.1.3 Fire Protection System 14.2.12.1.4 Reactor Water Cleanup System 14.2.12.1.5 Standby Liquid Control System 14.2.12.1.6 Nuclear Boiler System 14.2.12.1.7 Residual Heat Removal System 14.2.12.1.8 Reactor Core Isolation Cooling 14.2.12.1.9 Reactor Recirculation System and Control 14.2.12.1.10 Reactor Manual Control System 14.2.12.1.11 Control Rod Drive Hydraulic System 14.2.12.1.12 Fuel Handling and Vessel Servicing Equipment 14.2.12.1.13 Low Pressure Core Spray System 14.2.12.1.14 High Pressure Core Spray 14.2.12.1.15 Fuel Pool Cooling and Cleanup System 14.2.12.1.16 Leak Detection System 14.2.12.1.17 Liquid and Solid Radwaste System 14.2.12.1.18 Reactor Protection System 14.2.12.1.19 Neutron Monitoring System 14.2.12.1.20 Traversing In-Core Probe System 14.2.12.1.21 Rod Worth Minimizer System 14.2.12.1.22 Process Radiation Monitoring System 14.2.12.1.23 Area Radiation Monitoring System 14.2-129

COLUMBIA GENERATING STATION                        Amendment 53 FINAL SAFETY ANALYSIS REPORT                      November 1998 Table 14.2-1 Preoperational Tests (Continued)
Section Reference                                  Title 14.2.12.1.24 Process Computer Interface System 14.2.12.1.25 Rod Sequence Control System 14.2.12.1.26 Remote Shutdown 14.2.12.1.27 Offgas System 14.2.12.1.28 Environs Radiation Monitoring System 14.2.12.1.29 Main Steam System 14.2.12.1.30 Radwaste Building Heating, Ventilation, and Air Conditioning System 14.2.12.1.31 Closed Cooling Water System 14.2.12.1.32 Primary Containment Atmospheric Control System 14.2.12.1.33 Primary Containment Cooling System 14.2.12.1.34 Primary Containment Instrument Air System 14.2.12.1.35 Primary Containment Atmospheric Monitoring System 14.2.12.1.36 Standby Gas Treatment System 14.2.12.1.37 Loss of Power and Safety Testing 14.2.12.1.38 Instrument Power System 14.2.12.1.39 Emergency Lighting 14.2.12.1.40 Standby Alternating Current Power System 14.2.12.1.41 250-V Direct Current Distribution System 14.2.12.1.42 125-V Direct Current Distribution System 14.2.12.1.43 24-V Direct Current Distribution System 14.2.12.1.44 Plant Service Water System 14.2.12.1.45 Standby Service Water System 14.2.12.1.46 Plant Communication System 14.2-130

COLUMBIA GENERATING STATION                        Amendment 53 FINAL SAFETY ANALYSIS REPORT                       November 1998 Table 14.2-1 Preoperational Tests (Continued)
Section Reference                                  Title 14.2.12.1.47 Reactor Building Emergency Cooling System 14.2.12.1.48 Control Cable and Critical Switchgear Rooms Heating, Ventilation, and Air Conditioning System 14.2.12.1.49 Standby Service Water Pump House Heating and Ventilating System 14.2.12.1.50 Reactor Building Crane 14.2.12.1.51 Primary Containment Integrated Leak Rate Test 14.2.12.1.52 Secondary Containment Integrated Leak Rate Test 14.2.12.1.53 Diesel Generator Building Heating and Ventilating System 14.2-131

Table 14.2-2 Major Plant Transients Test Condition Approximate Power      20-25      60-75         95-100
(% rated)
Approximate Core Flow    37         100           100 Test                     Title                           (% rated)
COLUMBIA GENERATING STATION 23C     Feedwater pump trip                                                                            X 23B     Loss of feedwater heating                                                                      X 25      MSIVs (all valves, full isolation)                                                             X 14.2-132 FINAL SAFETY ANALYSIS REPORT 27      T-G stop valve fast close                                                        X 27      T-G control valve fast close                                         X                         X 28      Shutdown from outside control room                                   X 30      Recirculation pump trips                                                         X             X 31      Loss of generator and offsite power                                  X Test condition                                                      1, 2         3             6 Amendment 53 November 1998

Table 14.2-3 Stability Tests Test Condition Approximate Power      20   40   60-75   60-75     95-100   40-50
(% rated)
Approximate Core      37   50   100      55        100      NC Test                    Title                Flow (% rated)
COLUMBIA GENERATING STATION 21    Core power - void mode response                                                X                  X 22    Pressure regulator setpoint                                X    X      X       X         X        X changes 14.2-133 22    Pressure regulator backup                                  X    X      X       X         X        X FINAL SAFETY ANALYSIS REPORT regulator 23A   Feedwater system: water level                              X    X      X       X         X        X setpoint change 23B   Feedwater system: heater loss                                                            X 24    Turbine valve surveillance                                                     Xa        Xb 29    Recirculation flow control system                          X    X      X       X         X        X Test condition                                             1    2      3       5         6        4 Amendment 53 a
45-65% Power November 1998 b
75-90% Power

Table 14.2-4 Power Ascension Test Program Test Conditionsa Cold Test or Open      Heat Test                  Name             RPV         Up      1       2       3         4        5    6    Warranty COLUMBIA GENERATING STATION 1          Chemical and radiochemical       X          X       X       X       X                       X 2          Radiation measurements           X          X       X       X       X                       X 3          Fuel loading                     X 14.2-134 4          Full core shutdown margin        X FINAL SAFETY ANALYSIS REPORT 5          Control rod drive                X          X               Xb      Xb                      Xb 6          SRM performance and control      X          X       X       X                          X    X rod sequence 7          Not applicable 8          Not applicable 9          See 16B 10         IRM performance                  X          X       X 11         LPRM calibration                            X       X               X                       X               Amendment 53 November 1998

Table 14.2-4 Power Ascension Test Program (Continued)
Test Conditionsa Cold Test or Open     Heat Test                Name                 RPV        Up      1       2       3          4        5    6   Warranty COLUMBIA GENERATING STATION 12      APRM calibration                             X       X       X      X                    X    X      X 13      Process computer                   X         X       Xc 14      RCIC                                         X       X 14.2-135 15      Not applicable FINAL SAFETY ANALYSIS REPORT 16A     Selected process temperatures                X       X       X      X           X             X 16B     Water level reference leg                    X       X       X      X           X        X    X temperature measurement 17      System expansion and piping        X         X       X       X      X                         X vibration 18      Core power distribution                                             X                         X 19      Core performance                                     X       X      X           X        X    X      X Amendment 53 20      Steam production                                                                                     X 21      Core power void mode response                                                   X        X November 1998

Table 14.2-4 Power Ascension Test Program (Continued)
Test Conditionsa Cold Test or Open     Heat Test                Name                 RPV        Up      1        2      3          4        5       6     Warranty COLUMBIA GENERATING STATION 22      Pressure regulator: setpoint                       X,BP      X,BP   X,NO      X,BP     X,BP,    X,M, changes                                                             BP,M               M        BP Backup regulator                                   X,BP      X,BP   X,NO      X,BP     X,NO,    X,M, BP,M               BP,M     BP 14.2-136 23      Feedwater system FINAL SAFETY ANALYSIS REPORT C feedwater pump trip                                                                            Md A water level setpoint change                        X        X     X,M         X        X      X,M B heater loss                                                                                    Xe D maximum runout capability                  Xf      Xf                         X        X 24      Turbine valve surveillance                                                    X,g,h     X,i,j SP        SP 25      MSIVs:   each valve                          X     X,c S Amendment 53 one valve                                                           X,g,i,j X,k SP November 1998

Table 14.2-4 Power Ascension Test Program (Continued)
Test Conditionsa Cold Test or Open     Heat Test                    Name             RPV        Up      1        2      3          4        5     6     Warranty COLUMBIA GENERATING STATION full isolation                                                                X,b X,l SD 26      Relief valves:
14.2-137 Flow demonstration                               Xl,m FINAL SAFETY ANALYSIS REPORT Operational                               X      Xm 27      Turbine stop valve                                                  Xb,l Stop                                                             SD Generator load                                            X,BP                             Xb,l Rejection                                                                                  X,n SD 28      Shutdown from outside control                        X                                        Xo room Amendment 53 November 1998

Table 14.2-4 Power Ascension Test Program (Continued)
Test Conditionsa Cold Test or Open     Heat Test                Name                 RPV        Up      1        2       3          4        5      6     Warranty COLUMBIA GENERATING STATION 29      Recirculation flow control         L                 L       M,m     X,m        Lg     M,g Xg   L,g system                                                       X,m     L,m                        Xg Lm      M,m Am 14.2-138 30      Recirculation system:
FINAL SAFETY ANALYSIS REPORT Trip one pump                                                     Xl,n                       Xl,n Trip two pumps                                                    Xl,n System performance                                         X      Xl,m       Xg              Xl Runback                                                           Xd Noncavitation verification                                         X 31      Loss of T-G and offsite power                                X,b,l SD Amendment 53 32      Not applicable 33      Not applicable November 1998

Table 14.2-4 Power Ascension Test Program (Continued)
Test Conditionsa Cold Test or Open      Heat Test                  Name                   RPV         Up       1        2        3        4        5    6    Warranty COLUMBIA GENERATING STATION 34          RPV Internals                                                     Xm       Xm                Xg    Xg 36-69       Not applicable 70          Reactor water cleanup system                      X 14.2-139 71          Residual heat removal system                                                                       X FINAL SAFETY ANALYSIS REPORT 72          Drywell atmosphere cooling                        X                X        X                      X 73          Cooling water system                              X                                                X 74          Offgas system                          X          X       X                 X                      X a
See Figure 14.2-1 for test conditions region map.
b Perform test 5, timing of four slowest control rods in conjunction with these scrams.
c Between test conditions 1 and 3.
d Demonstrate recirculation system runback feature.
e 80%-90% power.                                                                                                             Amendment 53 November 1998 f
At either heatup or test condition 1.

Table 14.2-4 Power Ascension Test Program (Continued) g Between or at test conditions 5 and 6.
h Between 45% and 65% power on 100% load line.
i Future maximum power test point.
j Determine maximum power without scram.
COLUMBIA GENERATING STATION k
Between 40% and 55% power on the 100% load line.
l Do test 17 in conjunction with this test.
m Between test conditions 2 and 3.
14.2-140 n
FINAL SAFETY ANALYSIS REPORT Perform test 34 in conjunction with this test.
o After one of the scram transients from test condition, during the reactor cooldown, the last part of the shutdown from outside the control room test will be completed by demonstrating the operation of the shutdown cooling mode of RHR from the remote shutdown panel.
LEGEND L = Local position command mode operation, POS M = Flux command mode operation, FLX X = Combined flow command mode operation, FLO A = Automatic load following mode operation, ALF Amendment 53 SP = Scram possibility SD = Scram definite BP = Bypass valve response November 1998

Amendment 53 November 1998 130 120       A. Natural Circulation B. Low Recirculation Pump Speed Valve Minimum Position                                         (Truncate @ 100%
C. Low Recirculation Pump Speed Valve Maximum Position                                        Core Flow and Power) 110       D. Rated Recirculation Pump Speed Valve Minimum Position E. Analytical Lower Limit of Master Power Flow Control F. Analytical Upper Limit of Master Power Flow Control                                            F 100                                                                                                                        No. 6 105% Rod Line 90                                                                                                                       Rated 100% Rod Line                                                               Core Flow Line 80                                              No. 5                                   75% Rod Line Percent Power E                                                               No. 3 70 60                                        C D
B 50                            A No. 4 40                                                                                                          50% Rod Line No. 2 30                                                                                      Minimum Flow Control Line for Transfer to 100% SPD 20                                                                   Cavitation Region 10                                              Recommended Startup Path No. 1 0
0      10       20        30          40           50         60         70         80        90       100           110 Percent Core Flow Condition (TC) 1        Before main generator synchronization and recirc pumps operating on low frequency power supply from approximately 5 to 20 percent thermal power 2        Between 50% and 75% control rod lines, at or below the analytical lower limit of master flow control mode 3        From 50% to 75% control rod lines and core flow between 80% and maximum allowable 4        Natural circulation and within 5% of the intersection with 100% rod line 5        Mid-power range within 5% of 100% control rod line and 0 to +5% core flow of the minimum flow line, for master flow control in manual mode, and for automatic power control in auto mode 6        Within 0 to -5% of rated thermal power, and within 5% of rated core flow rate Test Condition Region Definition Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.93           Rev.           Figure   14.2-1 Form No. 960690

Amendment 53 November 1998 Licensing and          Technology                           Power Assurance              Director                        Generation Director                                               Director Quality            Engineering Assurance              Manager                Plant                   Other Plants Manager                                    Manager Plant QA/QC                                   Assistant Manager                                 Plant Manager
        *Test Group             Plant        Technical      Operations           Maintenance              HP/Chem Manager           Administrative   Manager         Manager               Manager                Manager Manager Test Group Supervisor Test Group Supervisor Test Group Supervisor Matrix Management QA Audit Function
* Reports Administratively to Test and Startup Programs Manager Test and Startup Relation to Other Energy Columbia Generating Station                              Northwest Departments Final Safety Analysis Report Draw. No. 960222.77           Rev.          Figure 14.2-2 Form No. 960690

Amendment 53 November 1998 Plant Manager Assistant Plant Manager Plant QA/QC Industrial Safety Manager AE, NSSS and Project Support Maintenance         Training            Operations                         Administration      Technical         HP/Chemistry Manager           Manager               Manager                              Manager          Manager             Manager Test Group                             Test Group                          Test Group Manager                                Manager                              Manager Test Group                               Test Group                        Test Group Supervisor                                Supervisor                        Supervisor Plan/Sched Test Engineers                            Test Engineers                    Test Engineers Engineers Test Group                               Test Group                        Test Group Supervisor                                Supervisor                        Supervisor Test Engineers                            Test Engineers                    Test Engineers Engineering Support S/U                                   Test Group                        Test Group Services                                 Supervisor                        Supervisor Systems Completion               S/U Support                                   Test Engineers                    Test Engineers Coordinator                 Group S/U Support Hanger Engineers Coordinator S/U Support Craft CGS Startup Organization Columbia Generating Station Final Safety Analysis Report Draw. No. 960222.78         Rev.        Figure  14.2-3 Form No. 960690

LEGEND: 1 PREPARE PREOP TEST PROCEDURES                                                                                                                  Amendment 53 2 REVIEW                                                                                                                                       November 1998 3 APPROVE                       NOTE: TIME SCALE LISTED ACROSS THE 4 TEST ACTIVITY                       BOTTOM OF PAGE IS IN MONTHS                                                                                                   FUEL LOAD 1              2      3          4 CONDENSATE 1        2   3   4 PLANT SERVICE WATER 1           2  3    4 STANDBY SERVICE WATER 1             2           3           4                                 4 FEEDWATER 1              2        3    4 PRIMARY CONTAINMENT ATMOSPHERIC CONTROL 1            2       3        4 PRIMARY CONTAINMENT COOLING 1              2     3      4 PRIMARY CONTAINMENT INSTRUMENT AIR 1                    2      3      4 PRIMARY CONTAINMENT ATMOSPHERIC MONITORING 1              2        3 4 125V DC DISTRIBUTION 1                        2           3        4 LOSS OF POWER AND SAFETY TEST 1               2       3 4 250V DC DISTRIBUTION 1              2      3   4 INSTRUMENT POWER 1              2       3    4 EMERGENCY LIGHTING 1            2      3 4 24V DC DISTRIBUTION 1                     2       3    4 STANDBY AC POWER 1                 2       3            4              4 HIGH PRESSURE CORE 1              2      3      4 LOW PRESSURE CORE SPRAY 1               2       3     4 STANDBY GAS TREATMENT 1             2         3 4                                 4 RESIDUAL HEAT REMOVAL 1              2         3      4 FUEL HANDLING & VESSEL SERVICING EQUIPMENT 1        2      3       4 FUEL POOL COOLING 1            2      3 4 SECONDARY CONTAINMENT ILRT 1                 2       3 4 PRIMARY CONTAINMENT ILRT 1              2      3      4 NUCLEAR BOILER 1               2       3           4 REACTOR WATER CLEANUP 1                 2         3       4 CONTROL ROD DRIVE MANUAL CONTROL 1                    2        3      4 CONTROL ROD DRIVE HYDRAULIC 1            2     3 4 ROD WORTH MINIMIZER 1             2      3 4 ROD SEQUENCE CONTROL 1            2       3 4 TRAVERSING INCORE PROBE 1                   2        3      4                    4 REACTOR RECIRCULATION 1             2       3      4 REACTOR CORE ISOLATION COOLING 1          2      3                                              4 PROCESS COMPUTER 1           2       3      4 STANDBY LIQUID CONTROL 1             2      3     4 LEAK DETECTION 1                     2     3       4 NEUTRON MONITORING 1          2       3       4 CLOSED COOLING WATER 1                    2       3     4                   4 REACTOR PROTECTION 1              2      3       4 PROCESS RADIATION MONITORING 1             2       3    4 AREA RADIATION MONITORING 1             2       3    4 ENVIRONS MONITORING 1          2        3 4 REACTOR BUILDING CRANE 1            2      3   4 REACTOR BUILDING EMERGENCY COOLING 1       2      3     4 CONTROL, CABLE, & CRITICAL SWCHGR ROOMS HVAC 1         2   3 4 STANDBY SERVICE WATER PUMPHOUSE H&V 1              2      3      4 DIESEL GENERATOR BUILDING H&V V 1                     2       3    4 SECURITY 1                    2       3           4 OFFGAS 1               2      3     4 MAIN STEAM 1               2       3          4 PLANT COMMUNICATION 1                    2        3     4 REMOTE SHUTDOWN 1                    2      3            4 LIQUID AND SOLID RADWASTE 1             2      3           4 RADWASTE BUILDING HVAC 1                    2      3                  4 FIRE PROTECTION Preoperational Test Schedule Columbia Generating Station Final Safety Analysis Report Draw. No.      960690.83                          Rev.                      Figure    14.2-4 Form No. 960690

Amendment 53 November 1998 450 400 350 300 Time Delay, Sec Unsafe 250 200 150 100 Safe up to 50        Limited Power 0
0   10      20       30    40       50      60            70     80   90         100 Percent Rated Power 100 90 80 70 Percent RCIC Design Flow Safe 60 50 40 30 Unsafe 20 10 0
0   10      20       30    40       50      60            70     80   90         100 Percent Rated Power RCIC Acceptance Criteria Curves for Capacity Columbia Generating Station                         and Actuation Time Final Safety Analysis Report Draw. No. 960690.82        Rev. Figure   14.2-5 Form No. 960690

Amendment 53 November 1998 100 90 80 Percent Drive Flow 70 60 50 40 30 0   1   2      Time    3     After    4    Start  5       6 in Seconds                 of TCV/TSV Movement Maximum Acceptable Drive Flow Response Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.81      Rev. Figure   14.2-6 Form No. 960690

COLUMBIA GENERATING STATION                                      Amendment 60 FINAL SAFETY ANALYSIS REPORT                                     December 2009 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS Section                                                                                           Page 15.0 GENERAL................................................................................. 15.0-1 15.0.1 ANALYTICAL OBJECTIVE........................................................ 15.0-3 15.0.2 ANALYTICAL CATEGORIES ..................................................... 15.0-3 15.0.2.1 Single Loop Operation (SLO) ..................................................... 15.0-4 15.0.3 EVENT EVALUATION.............................................................. 15.0-5 15.0.3.1 Identification of Causes and Frequency Classification ........................ 15.0-5 15.0.3.1.1 Unacceptable Results for Incidents of Moderate Frequency
[Anticipated (Expected) Operational Transients] ............................ 15.0-6 15.0.3.1.2 Unacceptable Results for Infrequent Incidents
[Abnormal (Unexpected) Operational Transients]........................... 15.0-6 15.0.3.1.3 Unacceptable Results for Limiting Faults [Design-Basis (Postulated) Accidents] ........................................................... 15.0-6 15.0.3.2 Sequence of Events and Systems Operation..................................... 15.0-7 15.0.3.2.1 Single Failures or Operator Errors ............................................. 15.0-8 15.0.3.2.1.1 General ........................................................................... 15.0-8 15.0.3.2.1.2 Initiating Event Analysis....................................................... 15.0-8 15.0.3.2.1.3 Single Active Component Failure or Single Operator Error Analysis ................................................................... 15.0-9 15.0.3.3 Core and System Performance .................................................... 15.0-9 15.0.3.3.1 Mathematical Model .............................................................. 15.0-10 15.0.3.3.2 Input Parameters and Initial Conditions for Analyzed Events ............. 15.0-11 15.0.3.3.3 Consideration of Uncertainties .................................................. 15.0-11 15.0.3.3.3.1 Core Flow Uncertainty Analysis ............................................. 15.0-12 15.0.3.3.4 Results............................................................................... 15.0-13 15.0.3.4 Barrier Performance................................................................. 15.0-14 15.0.3.5 Radiological Consequences ........................................................ 15.0-14 15.

==0.4 REFERENCES==
 ......................................................................... 15.0-14 15.1 DECREASE IN REACTOR COOLANT TEMPERATURE ..................... 15.1-1 15.1.1 LOSS OF FEEDWATER HEATING .............................................. 15.1-1 15.1.1.1 Identification of Causes and Frequency Classification ........................ 15.1-1 15.1.1.1.1 Identification of Causes .......................................................... 15.1-1 15.1.1.1.2 Frequency Classification ......................................................... 15.1-1 15.1.1.2 Sequence of Events and Systems Operation..................................... 15.1-1 15.1.1.2.1 The Effect of Single Failures and Operator Errors.......................... 15.1-2 LDCN-08-035                                       15-i

COLUMBIA GENERATING STATION                                      Amendment 61 FINAL SAFETY ANALYSIS REPORT                                     December 2011 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.1.1.3 Core and System Performance .................................................... 15.1-2 15.1.1.3.1 Mathematical Model .............................................................. 15.1-2 15.1.1.3.2 Input Parameters and Initial Conditions ....................................... 15.1-2 15.1.1.3.3 Results ............................................................................... 15.1-3 15.1.1.3.4 Considerations of Uncertainties ................................................. 15.1-3 15.1.1.4 Barrier Performance ................................................................. 15.1-3 15.1.1.5 Radiological Consequences ........................................................ 15.1-3 15.1.2 FEEDWATER CONTROLLER FAILURE - MAXIMUM DEMAND ...... 15.1-3 15.1.2.1 Identification of Causes and Frequency Classification ........................ 15.1-3 15.1.2.1.1 Identification of Causes .......................................................... 15.1-3 15.1.2.1.2 Frequency Classification ......................................................... 15.1-3 15.1.2.2 Sequence of Events and Systems Operation ..................................... 15.1-4 15.1.2.2.1 Sequence of Events and Systems Operation - Single Loop Operation ... 15.1-4 15.1.2.2.2 The Effect of Single Failures and Operator Errors .......................... 15.1-5 15.1.2.3 Core and System Performance .................................................... 15.1-5 15.1.2.3.1 Mathematical Model .............................................................. 15.1-5 15.1.2.3.2 Input Parameters and Initial Conditions ....................................... 15.1-6 15.1.2.3.3 Results ............................................................................... 15.1-6 15.1.2.3.4 Consideration of Uncertainties .................................................. 15.1-7 15.1.2.4 Barrier Performance ................................................................. 15.1-7 15.1.2.5 Radiological Consequences ........................................................ 15.1-7 15.1.3 PRESSURE REGULATOR FAILURE - OPEN ................................. 15.1-7 15.1.3.1 Identification of Causes and Frequency Classification ........................ 15.1-7 15.1.3.1.1 Identification of Causes .......................................................... 15.1-7 15.1.3.1.2 Frequency Classification ......................................................... 15.1-7 15.1.3.2 Sequence of Events and Systems Operation ..................................... 15.1-8 15.1.3.2.1 Sequence of Events ............................................................... 15.1-8 15.1.3.2.2 Systems Operation................................................................. 15.1-8 15.1.3.2.3 The Effect of Single Failures and Operator Errors .......................... 15.1-8 15.1.3.3 Core and System Performance .................................................... 15.1-9 15.1.3.3.1 Mathematical Model .............................................................. 15.1-9 15.1.3.3.2 Input Parameters and Initial Conditions ....................................... 15.1-9 15.1.3.3.3 Results ............................................................................... 15.1-9 15.1.3.3.4 Consideration of Uncertainties .................................................. 15.1-9 15.1.3.4 Barrier Performance ................................................................. 15.1-10 15.1.3.5 Radiological Consequences ........................................................ 15.1-10 LDCN-10-029                                       15-ii

COLUMBIA GENERATING STATION                                      Amendment 61 FINAL SAFETY ANALYSIS REPORT                                     December 2011 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.1.4 INADVERTENT SAFETY/RELIEF VALVE OPENING ..................... 15.1-10 15.1.4.1 Identification of Causes and Frequency Classification ........................ 15.1-10 15.1.4.1.1 Identification of Causes .......................................................... 15.1-10 15.1.4.1.2 Frequency Classification ......................................................... 15.1-10 15.1.4.2 Sequence of Events and Systems Operation ..................................... 15.1-11 15.1.4.2.1 Sequence of Events ............................................................... 15.1-11 15.1.4.2.2 Systems Operation................................................................. 15.1-11 15.1.4.2.3 The Effect of Single Failures and Operator Errors .......................... 15.1-11 15.1.4.3 Core and System Performance .................................................... 15.1-11 15.1.4.3.1 Mathematical Model .............................................................. 15.1-11 15.1.4.3.2 Input Parameters and Initial Conditions ....................................... 15.1-11 15.1.4.3.3 Results ............................................................................... 15.1-12 15.1.4.4 Barrier Performance ................................................................. 15.1-12 15.1.4.5 Radiological Consequences ........................................................ 15.1-12 15.1.5 SPECTRUM OF STEAM PIPING FAILURES INSIDE AND OUTSIDE OF CONTAINMENT IN A PRESSURIZED WATER REACTOR .............................................................................. 15.1-12 15.1.6 INADVERTENT RESIDUAL HEAT REMOVAL SHUTDOWN COOLING OPERATION ............................................................ 15.1-12 15.1.6.1 Identification of Causes and Frequency Classification ........................ 15.1-13 15.1.6.1.1 Identification of Causes .......................................................... 15.1-13 15.1.6.1.2 Frequency Classification ......................................................... 15.1-13 15.1.6.2 Sequence of Events and Systems Operation ..................................... 15.1-13 15.1.6.2.1 Sequence of Events ............................................................... 15.1-13 15.1.6.2.2 System Operation .................................................................. 15.1-13 15.1.6.2.3 Effect of Single Failures and Operator Action ............................... 15.1-14 15.1.6.3 Core and System Performance .................................................... 15.1-14 15.1.6.4 Barrier Performance ................................................................. 15.1-14 15.1.6.5 Radiological Consequences ........................................................ 15.1-14 15.

==1.7 REFERENCES==
 ......................................................................... 15.1-14 15.2 INCREASE IN REACTOR PRESSURE ............................................. 15.2-1 15.2.1 PRESSURE REGULATOR FAILURE - CLOSED.............................. 15.2-1 15.2.1.1 Identification of Causes and Frequency Classification ........................ 15.2-1 15.2.1.1.1 Identification of Causes .......................................................... 15.2-1 15.2.1.1.2 Frequency Classification ......................................................... 15.2-1 LDCN-10-029                                       15-iii

COLUMBIA GENERATING STATION                                      Amendment 59 FINAL SAFETY ANALYSIS REPORT                                     December 2007 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                           Page 15.2.1.2 Sequence of Events and Systems Operation..................................... 15.2-1 15.2.1.2.1 Sequence of Events ............................................................... 15.2-1 15.2.1.2.2 Systems Operation................................................................. 15.2-2 15.2.1.2.3 The Effect of Single Failures and Operator Errors.......................... 15.2-2 15.2.1.3 Core and System Performance .................................................... 15.2-2 15.2.1.3.1 Mathematical Model .............................................................. 15.2-2 15.2.1.3.2 Input Parameters and Initial Conditions ....................................... 15.2-3 15.2.1.3.3 Results............................................................................... 15.2-3 15.2.1.3.4 Consideration of Uncertainties .................................................. 15.2-3 15.2.1.4 Barrier Performance................................................................. 15.2-3 15.2.1.5 Radiological Consequences ........................................................ 15.2-3 15.2.2 GENERATOR LOAD REJECTION ............................................... 15.2-4 15.2.2.1 Identification of Causes and Frequency Classification ........................ 15.2-4 15.2.2.1.1 Identification of Causes .......................................................... 15.2-4 15.2.2.1.2 Frequency Classification ......................................................... 15.2-4 15.2.2.1.2.1 Generator Load Rejection ..................................................... 15.2-4 15.2.2.1.2.2 Generator Load Rejection with Bypass Failure............................ 15.2-4 15.2.2.2 Sequence of Events and System Operation ...................................... 15.2-4 15.2.2.2.1 Sequence of Events ............................................................... 15.2-5 15.2.2.2.1.1 Generator Load Rejection - Turbine Control Valve Fast Closure...... 15.2-5 15.2.2.2.1.2 Generator Load Rejection with Failure of Bypass ........................ 15.2-5 15.2.2.2.2 System Operation.................................................................. 15.2-5 15.2.2.2.2.1 Generator Load Rejection with Bypass ..................................... 15.2-5 15.2.2.2.2.2 Generator Load Rejection with Failure of Bypass ........................ 15.2-5 15.2.2.2.3 The Effect of Single Failures and Operator Errors.......................... 15.2-5 15.2.2.3 Core and System Performance .................................................... 15.2-6 15.2.2.3.1 Mathematical Model .............................................................. 15.2-6 15.2.2.3.1.1 Generator Load Rejection with Bypass ..................................... 15.2-6 15.2.2.3.1.2 Generator Load Rejection with Bypass Failure............................ 15.2-6 15.2.2.3.2 Input Parameters and Initial Conditions ....................................... 15.2-7 15.2.2.3.3 Results............................................................................... 15.2-7 15.2.2.3.3.1 Generator Load Rejection with Bypass ..................................... 15.2-7 15.2.2.3.3.2 Generator Load Rejection with Failure of Bypass ........................ 15.2-7 15.2.2.3.4 Consideration of Uncertainties .................................................. 15.2-7 15.2.2.4 Barrier Performance................................................................. 15.2-8 15.2.2.4.1 Generator Load Rejection........................................................ 15.2-8 LDCN-06-057, 07-011                              15-iv

COLUMBIA GENERATING STATION                                      Amendment 61 FINAL SAFETY ANALYSIS REPORT                                     December 2011 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.2.2.4.2 Generator Load Rejection with Failure of Bypass ........................... 15.2-8 15.2.2.5 Radiological Consequences ........................................................ 15.2-8 15.2.3 TURBINE TRIP ........................................................................ 15.2-8 15.2.3.1 Identification of Causes and Frequency Classification ........................ 15.2-8 15.2.3.1.1 Identification of Causes .......................................................... 15.2-8 15.2.3.1.2 Frequency Classification ......................................................... 15.2-8 15.2.3.1.2.1 Turbine Trip ..................................................................... 15.2-8 15.2.3.1.2.2 Turbine Trip with Failure of Bypass ........................................ 15.2-9 15.2.3.2 Sequence of Events and Systems Operation ..................................... 15.2-9 15.2.3.2.1 Sequence of Events ............................................................... 15.2-9 15.2.3.2.1.1 Turbine Trip ..................................................................... 15.2-9 15.2.3.2.1.2 Turbine Trip with Failure of Bypass ........................................ 15.2-9 15.2.3.2.2 Systems Operation................................................................. 15.2-9 15.2.3.2.2.1 Turbine Trip ..................................................................... 15.2-9 15.2.3.2.2.2 Turbine Trip with Failure of Bypass ........................................ 15.2-9 15.2.3.2.2.3 Turbine Trip at Low Power with Failure of Bypass ...................... 15.2-9 15.2.3.2.3 The Effect of Single Failures and Operator Errors .......................... 15.2-10 15.2.3.2.3.1 Turbine Trips at Power Levels Greater Than 30% Nuclear Boiler Rated ...................................................................... 15.2-10 15.2.3.2.3.2 Turbine Trips at Power Levels Less Than 30% Nuclear Boiler Rated ...................................................................... 15.2-10 15.2.3.3 Core and System Performance .................................................... 15.2-10 15.2.3.3.1 Mathematical Model .............................................................. 15.2-10 15.2.3.3.1.1 Turbine Trip with Bypass ..................................................... 15.2-10 15.2.3.3.1.2 Turbine Trip with Bypass Failure ............................................ 15.2-10 15.2.3.3.2 Input Parameters and Initial Conditions ....................................... 15.2-10 15.2.3.3.3 Results ............................................................................... 15.2-11 15.2.3.3.3.1 Turbine Trip ..................................................................... 15.2-11 15.2.3.3.3.2 Turbine Trip with Failure of Bypass ........................................ 15.2-11 15.2.3.3.3.3 Turbine Trip with Bypass Valve Failure, Low Power ................... 15.2-11 15.2.3.3.4 Considerations of Uncertainties ................................................. 15.2-12 15.2.3.4 Barrier Performance ................................................................. 15.2-12 15.2.3.4.1 Turbine Trip........................................................................ 15.2-12 15.2.3.4.2 Turbine Trip with Failure of Bypass ........................................... 15.2-12 15.2.3.4.2.1 Turbine Trip with Failure of Bypass at Low Power ...................... 15.2-12 15.2.3.5 Radiological Consequences ........................................................ 15.2-12 LDCN-10-029                                        15-v

COLUMBIA GENERATING STATION                                      Amendment 61 FINAL SAFETY ANALYSIS REPORT                                     December 2011 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.2.4 MAIN STEAM LINE ISOLATION VALVE CLOSURES..................... 15.2-12 15.2.4.1 Identification of Causes and Frequency Classification ........................ 15.2-13 15.2.4.1.1 Identification of Causes .......................................................... 15.2-13 15.2.4.1.2 Frequency Classification ......................................................... 15.2-13 15.2.4.1.2.1 Closure of All Main Steam Line Isolation Valves ........................ 15.2-13 15.2.4.1.2.2 Closure of One Main Steam Line Isolation Valve ........................ 15.2-13 15.2.4.2 Sequence of Events and Systems Operation ..................................... 15.2-13 15.2.4.2.1 Sequence of Events ............................................................... 15.2-13 15.2.4.2.2 Systems Operation................................................................. 15.2-14 15.2.4.2.2.1 Closure of All Main Steam Line Isolation Valves ........................ 15.2-14 15.2.4.2.2.2 Closure of One Main Steam Line Isolation Valve ........................ 15.2-14 15.2.4.2.3 The Effect of Single Failures and Operator Errors .......................... 15.2-14 15.2.4.3 Core and System Performance .................................................... 15.2-14 15.2.4.3.1 Mathematical Model .............................................................. 15.2-14 15.2.4.3.2 Input Parameters and Initial Conditions ....................................... 15.2-15 15.2.4.3.3 Results ............................................................................... 15.2-15 15.2.4.3.3.1 Closure of All Main Steam Line Isolation Valves ........................ 15.2-15 15.2.4.3.3.2 Closure of One Main Steam Line Isolation Valve ........................ 15.2-15 15.2.4.3.4 Considerations of Uncertainties ................................................. 15.2-16 15.2.4.4 Barrier Performance ................................................................. 15.2-16 15.2.4.4.1 Closure of All Main Steam Line Isolation Valves ........................... 15.2-16 15.2.4.4.2 Closure of One Main Steam Line Isolation Valve ........................... 15.2-16 15.2.4.5 Radiological Consequences ........................................................ 15.2-16 15.2.5 LOSS-OF-CONDENSER VACUUM .............................................. 15.2-17 15.2.5.1 Identification of Causes and Frequency Classification ........................ 15.2-17 15.2.5.1.1 Identification of Causes .......................................................... 15.2-17 15.2.5.1.2 Frequency Classification ......................................................... 15.2-17 15.2.5.2 Sequence of Events and Systems Operation ..................................... 15.2-17 15.2.5.2.1 Sequence of Events ............................................................... 15.2-17 15.2.5.2.2 Systems Operation................................................................. 15.2-17 15.2.5.2.3 The Effect of Single Failures and Operator Errors .......................... 15.2-18 15.2.5.3 Core and System Performance .................................................... 15.2-18 15.2.5.3.1 Mathematical Model .............................................................. 15.2-18 15.2.5.3.2 Input Parameters and Initial Conditions ....................................... 15.2-18 15.2.5.3.3 Results ............................................................................... 15.2-18 15.2.5.3.4 Consideration of Uncertainties .................................................. 15.2-18 LDCN-10-029                                       15-vi

COLUMBIA GENERATING STATION                                      Amendment 61 FINAL SAFETY ANALYSIS REPORT                                     December 2011 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.2.5.4 Barrier Performance ................................................................. 15.2-19 15.2.5.5 Radiological Consequences ........................................................ 15.2-19 15.2.6 LOSS OF ALTERNATING CURRENT POWER ............................... 15.2-20 15.2.6.1 Identification of Causes and Frequency Classification ........................ 15.2-20 15.2.6.1.1 Identification of Causes .......................................................... 15.2-20 15.2.6.1.1.1 Loss of Auxiliary Power Transformers ..................................... 15.2-20 15.2.6.1.1.2 Loss of All Grid Connections................................................. 15.2-20 15.2.6.1.2 Frequency Classification ......................................................... 15.2-20 15.2.6.1.2.1 Loss of Auxiliary Power Transformers ..................................... 15.2-20 15.2.6.1.2.2 Loss of All Grid Connections................................................. 15.2-20 15.2.6.2 Sequence of Events and Systems Operation ..................................... 15.2-20 15.2.6.2.1 Sequence of Events ............................................................... 15.2-20 15.2.6.2.1.1 Loss of Auxiliary Power Transformers ..................................... 15.2-20 15.2.6.2.1.2 Loss of All Grid Connections................................................. 15.2-20 15.2.6.2.2 Systems Operation................................................................. 15.2-21 15.2.6.2.2.1 Loss of Auxiliary Power Transformers ..................................... 15.2-21 15.2.6.2.2.2 Loss of All Grid Connections................................................. 15.2-21 15.2.6.2.3 The Effect of Single Failures and Operator Errors .......................... 15.2-21 15.2.6.3 Core and System Performance .................................................... 15.2-22 15.2.6.3.1 Mathematical Model .............................................................. 15.2-22 15.2.6.3.2 Input Parameters and Initial Conditions ....................................... 15.2-22 15.2.6.3.2.1 Loss of Auxiliary Power Transformers ..................................... 15.2-22 15.2.6.3.2.2 Loss of All Grid Connections................................................. 15.2-22 15.2.6.3.3 Results ............................................................................... 15.2-22 15.2.6.3.3.1 Loss of Auxiliary Power Transformers ..................................... 15.2-22 15.2.6.3.3.2 Loss of All Grid Connections................................................. 15.2-23 15.2.6.3.4 Consideration of Uncertainties .................................................. 15.2-23 15.2.6.4 Barrier Performance ................................................................. 15.2-23 15.2.6.4.1 Loss of Auxiliary Power Transformers........................................ 15.2-23 15.2.6.4.2 Loss of All Grid Connections ................................................... 15.2-24 15.2.6.5 Radiological Consequences ........................................................ 15.2-24 15.2.7 LOSS-OF-FEEDWATER FLOW ................................................... 15.2-24 15.2.7.1 Identification of Causes and Frequency Classification ........................ 15.2-24 15.2.7.1.1 Identification of Causes .......................................................... 15.2-24 15.2.7.1.2 Frequency Classification ......................................................... 15.2-24 LDCN-10-029                                       15-vii

COLUMBIA GENERATING STATION                                      Amendment 61 FINAL SAFETY ANALYSIS REPORT                                     December 2011 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.2.7.2 Sequence of Events and Systems Operation ..................................... 15.2-24 15.2.7.2.1 Sequence of Events ............................................................... 15.2-24 15.2.7.2.2 Systems Operation................................................................. 15.2-25 15.2.7.2.3 The Effect of Single Failures and Operator Errors .......................... 15.2-25 15.2.7.3 Core and System Performance .................................................... 15.2-25 15.2.7.3.1 Mathematical Model .............................................................. 15.2-25 15.2.7.3.2 Input Parameters and Initial Conditions ....................................... 15.2-26 15.2.7.3.3 Results ............................................................................... 15.2-26 15.2.7.3.4 Consideration of Uncertainties .................................................. 15.2-26 15.2.7.4 Barrier Performance ................................................................. 15.2-26 15.2.7.5 Radiological Consequences ........................................................ 15.2-26 15.2.8 FEEDWATER LINE BREAK ....................................................... 15.2-26 15.2.9 FAILURE OF RESIDUAL HEAT REMOVAL SHUTDOWN COOLING ............................................................................... 15.2-27 15.2.9.1 Identification of Causes and Frequency Classification ........................ 15.2-27 15.2.9.1.1 Identification of Causes .......................................................... 15.2-27 15.2.9.1.2 Frequency Classification ......................................................... 15.2-27 15.2.9.2 Sequence of Events and Systems Operation ..................................... 15.2-27 15.2.9.2.1 Sequence of Events ............................................................... 15.2-27 15.2.9.2.1.1 Identification of Operator Actions ........................................... 15.2-28 15.2.9.2.2 Systems Operation................................................................. 15.2-28 15.2.9.2.3 The Effect of Single Failures and Operator Errors .......................... 15.2-28 15.2.9.3 Core and System Performance .................................................... 15.2-28 15.2.9.4 Results ................................................................................. 15.2-29 15.2.9.4.1 Full Power to Approximately 100 psig ........................................ 15.2-29 15.2.9.4.2 Approximately 100 psig to Cold Shutdown ................................... 15.2-30 15.2.9.4.3 Temperature Response - 3462 MWt ........................................... 15.2-31 15.2.9.4.4 Temperature Response - 3702 MWt ........................................... 15.2-32 15.2.9.5 Barrier Performance ................................................................. 15.2-32 15.2.9.6 Radiological Consequences ........................................................ 15.2-32 15.2.10 REFERENCES ........................................................................ 15.2-32 15.3 DECREASE IN REACTOR COOLANT SYSTEM FLOW RATE ............. 15.3-1 15.3.1 RECIRCULATION PUMP TRIP ................................................... 15.3-1 15.3.1.1 Identification of Causes and Frequency Classification ........................ 15.3-1 15.3.1.1.1 Identification of Causes .......................................................... 15.3-1 LDCN-10-029                                      15-viii

COLUMBIA GENERATING STATION                                      Amendment 59 FINAL SAFETY ANALYSIS REPORT                                     December 2007 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                           Page 15.3.1.1.2 Frequency Classification ......................................................... 15.3-1 15.3.1.1.2.1 Trip of One Recirculation Pump ............................................. 15.3-1 15.3.1.1.2.2 Trip of Two Recirculation Pumps ........................................... 15.3-1 15.3.1.2 Sequence of Events and Systems Operation..................................... 15.3-2 15.3.1.2.1 Sequence of Events ............................................................... 15.3-2 15.3.1.2.1.1 Trip of One Recirculation Pump ............................................. 15.3-2 15.3.1.2.1.2 Trip of Two Recirculation Pumps ........................................... 15.3-2 15.3.1.2.2 Systems Operation................................................................. 15.3-2 15.3.1.2.2.1 Trip of One Recirculation Pump ............................................. 15.3-2 15.3.1.2.2.2 Trip of Two Recirculation Pumps ........................................... 15.3-2 15.3.1.2.3 The Effect of Single Failures and Operator Errors.......................... 15.3-2 15.3.1.2.3.1 Trip of One Recirculation Pump ............................................. 15.3-2 15.3.1.2.3.2 Trip of Two Recirculation Pumps ........................................... 15.3-2 15.3.1.3 Core and System Performance .................................................... 15.3-2 15.3.1.3.1 Mathematical Model .............................................................. 15.3-2 15.3.1.3.2 Input Parameters and Initial Conditions ....................................... 15.3-3 15.3.1.3.3 Results............................................................................... 15.3-3 15.3.1.3.3.1 Trip of One Recirculation Pump ............................................. 15.3-3 15.3.1.3.3.2 Trip of Two Recirculation Pumps ........................................... 15.3-3 15.3.1.3.4 Consideration of Uncertainties .................................................. 15.3-3 15.3.1.4 Barrier Performance................................................................. 15.3-3 15.3.1.4.1 Trip of One Recirculation Pump................................................ 15.3-3 15.3.1.4.2 Trip of Two Recirculation Pumps .............................................. 15.3-4 15.3.1.5 Radiological Consequences ........................................................ 15.3-4 15.3.2 RECIRCULATION FLOW CONTROL FAILURE - DECREASING FLOW ................................................................................... 15.3-4 15.3.2.1 Identification of Causes and Frequency Classification ........................ 15.3-4 15.3.2.1.1 Identification of Causes .......................................................... 15.3-4 15.3.2.1.2 Frequency Classification ......................................................... 15.3-4 15.3.2.2 Sequence of Events and Systems Operation..................................... 15.3-4 15.3.2.2.1 Sequence of Events ............................................................... 15.3-4 15.3.2.2.1.1 Speed Decrease of One Recirculation Pump ............................... 15.3-4 15.3.2.2.1.2 Speed Decrease of Two Recirculation Pumps ............................. 15.3-4 15.3.2.2.2 Systems Operation................................................................. 15.3-5 15.3.2.2.2.1 Speed Decrease of One Recirculation Pump ............................... 15.3-5 15.3.2.2.2.2 Speed Decrease of Two Recirculation Pumps ............................. 15.3-5 15-ix

COLUMBIA GENERATING STATION                                      Amendment 60 FINAL SAFETY ANALYSIS REPORT                                     December 2009 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                           Page 15.3.2.2.3 The Effect of Single Failures and Operator Errors.......................... 15.3-5 15.3.2.3 Core and System Performance .................................................... 15.3-5 15.3.2.3.1 Mathematical Model .............................................................. 15.3-5 15.3.2.3.2 Input Parameters and Initial Conditions ....................................... 15.3-5 15.3.2.3.2.1 Speed Decrease of One Recirculation Pump ............................... 15.3-5 15.3.2.3.2.2 Speed Decrease of Two Recirculation Pumps ............................. 15.3-6 15.3.2.3.3 Results............................................................................... 15.3-6 15.3.2.3.3.1 Speed Decrease of One Recirculation Pump ............................... 15.3-6 15.3.2.3.3.2 Speed Decrease of Two Recirculation Pumps ............................. 15.3-6 15.3.2.3.4 Consideration of Uncertainties .................................................. 15.3-6 15.3.2.4 Barrier Performance................................................................. 15.3-6 15.3.2.4.1 Speed Decrease of One Recirculation Pump.................................. 15.3-6 15.3.2.4.2 Speed Decrease of Two Recirculation Pumps................................ 15.3-7 15.3.2.5 Radiological Consequences ........................................................ 15.3-7 15.3.3 RECIRCULATION PUMP SEIZURE ............................................. 15.3-7 15.3.3.1 Identification of Causes and Frequency Classification ........................ 15.3-7 15.3.3.2 Sequence of Events and Systems Operation..................................... 15.3-7 15.3.3.2.1 Sequence of Events ............................................................... 15.3-7 15.3.3.2.2 Systems Operation................................................................. 15.3-8 15.3.3.2.3 The Effect of Single Failures and Operator Errors.......................... 15.3-8 15.3.3.3 Core and System Performance .................................................... 15.3-8 15.3.3.3.1 Mathematical Model .............................................................. 15.3-8 15.3.3.3.2 Input Parameters and Initial Conditions ....................................... 15.3-8 15.3.3.3.3 Results............................................................................... 15.3-9 15.3.3.3.3.1 Considerations of Uncertainties .............................................. 15.3-9 15.3.3.4 Barrier Performance................................................................. 15.3-9 15.3.3.5 Radiological Consequences ........................................................ 15.3-9 15.3.4 RECIRCULATION PUMP SHAFT BREAK ..................................... 15.3-9 15.3.4.1 Identification of Causes and Frequency Classification ........................ 15.3-9 15.3.4.1.1 Identification of Causes .......................................................... 15.3-10 15.3.4.1.2 Frequency Classification ......................................................... 15.3-10 15.3.4.2 Sequence of Events and Systems Operation..................................... 15.3-10 15.3.4.2.1 Sequence of Events ............................................................... 15.3-10 15.3.4.2.2 Systems Operation................................................................. 15.3-10 15.3.4.2.3 The Effect of Single Failures and Operator Errors.......................... 15.3-10 LDCN-08-035                                       15-x

COLUMBIA GENERATING STATION                                    Amendment 60 FINAL SAFETY ANALYSIS REPORT                                   December 2009 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                         Page 15.3.4.3 Core and System Performance .................................................... 15.3-11 15.3.4.3.1 Qualitative Results ................................................................ 15.3-11 15.3.4.4 Barrier Performance................................................................. 15.3-11 15.3.4.5 Radiological Consequences ........................................................ 15.3-11 15.

==3.5 REFERENCES==
 ......................................................................... 15.3-11 15.4 REACTIVITY AND POWER DISTRIBUTION ANOMALIES................. 15.4-1 15.4.1 ROD WITHDRAWAL ERROR - LOW POWER................................ 15.4-1 15.4.1.1 Control Rod Removal Error During Refueling ................................. 15.4-1 15.4.1.1.1 Identification of Causes and Frequency Classification...................... 15.4-1 15.4.1.1.2 Sequence of Events and Systems Operation .................................. 15.4-1 15.4.1.1.2.1 Initial Control Rod Removal .................................................. 15.4-1 15.4.1.1.2.2 Fuel Insertion With Control Rod Removed ................................ 15.4-1 15.4.1.1.2.3 Second Control Rod Removal ................................................ 15.4-1 15.4.1.1.2.4 Control Rod Removal Without Fuel Removal ............................. 15.4-1 15.4.1.1.2.5 Effect of Single Failure and Operator Errors .............................. 15.4-2 15.4.1.1.3 Core and System Performances................................................. 15.4-2 15.4.1.1.4 Barrier Performance .............................................................. 15.4-2 15.4.1.1.5 Radiological Consequences ...................................................... 15.4-2 15.4.1.2 Continuous Rod Withdrawal During Reactor Startup ......................... 15.4-2 15.4.1.2.1 Identification of Causes and Frequency Classification...................... 15.4-2 15.4.1.2.2 Sequence of Events and Systems Operation .................................. 15.4-3 15.4.1.2.2.1 Sequence of Events ............................................................. 15.4-3 15.4.1.2.2.2 Effects of Single Failure and Operator Errors ............................. 15.4-3 15.4.1.2.3 Core and System Performance .................................................. 15.4-3 15.4.1.2.4 Barrier Performance .............................................................. 15.4-3 15.4.1.2.5 Radiological Consequences ...................................................... 15.4-3 15.4.2 ROD WITHDRAWAL ERROR - AT POWER .................................. 15.4-4 15.4.2.1 Identification of Causes and Frequency Classifications ....................... 15.4-4 15.4.2.1.1 Identification of Causes .......................................................... 15.4-4 15.4.2.1.2 Frequency Classification ......................................................... 15.4-4 15.4.2.2 Sequence of Events and Systems Operation..................................... 15.4-4 15.4.2.2.1 Sequence of Events ............................................................... 15.4-4 15.4.2.2.2 Systems Operation................................................................. 15.4-4 15.4.2.2.3 Effect of Single Failure and Operator Errors................................. 15.4-5 LDCN-08-035                                    15-xi

COLUMBIA GENERATING STATION                                      Amendment 63 FINAL SAFETY ANALYSIS REPORT                                     December 2015 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.4.2.3 Core and System Performance .................................................... 15.4-5 15.4.2.3.1 Mathematical Model .............................................................. 15.4-5 15.4.2.3.2 Input Parameters and Initial Conditions ....................................... 15.4-5 15.4.2.3.2.1 Rod Block Monitor System Operation ...................................... 15.4-6 15.4.2.3.3 Results ............................................................................... 15.4-6 15.4.2.3.4 Considerations of Uncertainties ................................................. 15.4-6 15.4.2.4 Barrier Performance ................................................................. 15.4-6 15.4.2.5 Radiological Consequences ........................................................ 15.4-7 15.4.3 CONTROL ROD MALOPERATION (SYSTEM MALFUNCTION OR OPERATOR ERROR) ................................................................ 15.4-7 15.4.4 STARTUP OF IDLE RECIRCULATION PUMP ............................... 15.4-7 15.4.4.1 Identification of Causes and Frequency Classification ........................ 15.4-7 15.4.4.1.1 Identification of Causes .......................................................... 15.4-7 15.4.4.1.2 Frequency Classification ......................................................... 15.4-7 15.4.4.1.2.1 Normal Restart of Recirculation Pump at Power.......................... 15.4-7 15.4.4.1.2.2 Abnormal Startup of Idle Recirculation Pump ............................. 15.4-7 15.4.4.2 Sequence of Events and Systems Operation ..................................... 15.4-7 15.4.4.2.1 Sequence of Events ............................................................... 15.4-7 15.4.4.2.2 Systems Operation................................................................. 15.4-8 15.4.4.2.3 The Effect of Single Failures and Operator Errors .......................... 15.4-8 15.4.4.3 Core and System Performance .................................................... 15.4-8 15.4.4.3.1 Mathematical Model .............................................................. 15.4-8 15.4.4.3.2 Input Parameters and Initial Conditions ....................................... 15.4-8 15.4.4.3.3 Results ............................................................................... 15.4-8 15.4.4.3.4 Consideration of Uncertainties .................................................. 15.4-9 15.4.4.4 Barrier Performance ................................................................. 15.4-9 15.4.4.5 Radiological Consequences ........................................................ 15.4-9 15.4.5 RECIRCULATION FLOW CONTROL FAILURE WITH INCREASING FLOW ................................................................. 15.4-9 15.4.5.1 Identification of Causes and Frequency Classification ........................ 15.4-9 15.4.5.1.1 Identification of Causes .......................................................... 15.4-9 15.4.5.1.2 Frequency Classification ......................................................... 15.4-9 15.4.5.2 Sequence of Events and Systems Operation ..................................... 15.4-10 15.4.5.2.1 The Effect of Single Failures and Operator Errors .......................... 15.4-10 15.4.5.3 Core and System Performance .................................................... 15.4-10 15.4.5.3.1 Mathematical Model .............................................................. 15.4-10 LDCN-10-004                                       15-xii

COLUMBIA GENERATING STATION                                      Amendment 63 FINAL SAFETY ANALYSIS REPORT                                     December 2015 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.4.5.3.2 Input Parameters and Initial Conditions ....................................... 15.4-11 15.4.5.3.3 Results ............................................................................... 15.4-11 15.4.5.3.4 Considerations of Uncertainties ................................................. 15.4-11 15.4.5.4 Barrier Performance ................................................................. 15.4-11 15.4.5.5 Radiological Consequences ........................................................ 15.4-12 15.4.6 CHEMICAL AND VOLUME CONTROL SYSTEM MALFUNCTIONS .. 15.4-12 15.4.7 MISPLACED BUNDLE ACCIDENT ............................................. 15.4-12 15.4.7.1 Identification of Causes and Frequency Classification ........................ 15.4-12 15.4.7.1.1 Identification of Causes .......................................................... 15.4-12 15.4.7.1.2 Frequency of Occurrence ........................................................ 15.4-13 15.4.7.2 Sequence of Events and Systems Operation ..................................... 15.4-13 15.4.7.2.1 Effect of Single Failure and Operator Errors................................. 15.4-13 15.4.7.3 Core and System Performance .................................................... 15.4-13 15.4.7.3.1 Mathematical Model .............................................................. 15.4-13 15.4.7.3.2 Input Parameters and Initial Conditions ....................................... 15.4-13 15.4.7.3.3 Results ............................................................................... 15.4-13 15.4.7.3.4 Considerations of Uncertainties ................................................. 15.4-14 15.4.7.4 Barrier Performance ................................................................. 15.4-14 15.4.7.5 Radiological Consequences ........................................................ 15.4-14 15.4.8 SPECTRUM OF ROD EJECTION ASSEMBLIES .............................. 15.4-14 15.4.9 CONTROL ROD DROP ACCIDENT ............................................. 15.4-14 15.4.9.1 Identification of Causes and Frequency Classification ........................ 15.4-14 15.4.9.1.1 Identification of Causes .......................................................... 15.4-14 15.4.9.1.2 Frequency Classification ......................................................... 15.4-15 15.4.9.2 Sequence of Events and Systems Operation ..................................... 15.4-15 15.4.9.2.1 Effect of Single Failures and Operator Errors ............................... 15.4-16 15.4.9.3 Core and System Performance .................................................... 15.4-16 15.4.9.3.1 Mathematical Model .............................................................. 15.4-16 15.4.9.3.2 Input Parameters and Initial Conditions ....................................... 15.4-16 15.4.9.3.3 Results ............................................................................... 15.4-16 15.4.9.4 Barrier Performance ................................................................. 15.4-17 15.4.9.5 Radiological Consequences ........................................................ 15.4-17 15.4.9.5.1 Fission Product Release from Fuel ............................................. 15.4-17 15.4.9.5.2 Fission Product Transport to the Environment ............................... 15.4-18 15.4.9.5.3 Results ............................................................................... 15.4-18 15.4.10 REFERENCES ........................................................................ 15.4-19 LDCN-10-004                                      15-xiii

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                           Page 15.5 INCREASE IN REACTOR COOLANT INVENTORY........................... 15.5-1 15.5.1 INADVERTENT HIGH-PRESSURE CORE SPRAY STARTUP ............ 15.5-1 15.5.1.1 Identification of Causes and Frequency Classification ........................ 15.5-1 15.5.1.1.1 Identification of Causes .......................................................... 15.5-1 15.5.1.1.2 Frequency Classification ......................................................... 15.5-1 15.5.1.2 Sequence of Events and Systems Operation..................................... 15.5-1 15.5.1.2.1 The Effect of Single Failures and Operator Errors.......................... 15.5-1 15.5.1.3 Core and System Performance .................................................... 15.5-2 15.5.1.3.1 Mathematical Model .............................................................. 15.5-2 15.5.1.3.2 Input Parameter and Initial Conditions ........................................ 15.5-2 15.5.1.3.3 Results............................................................................... 15.5-2 15.5.1.3.3.1 Consideration of Uncertainties ............................................... 15.5-2 15.5.1.4 Barrier Performance................................................................. 15.5-2 15.5.1.5 Radiological Consequences ........................................................ 15.5-2 15.5.2 CHEMICAL VOLUME CONTROL SYSTEM MALFUNCTION (OR OPERATOR ERROR) .......................................................... 15.5-2 15.5.3 BOILING WATER REACTOR TRANSIENTS WHICH INCREASE REACTOR COOLANT INVENTORY ............................................ 15.5-2 15.

==5.4 REFERENCES==
 ......................................................................... 15.5-3 15.6 DECREASE IN REACTOR COOLANT INVENTORY.......................... 15.6-1 15.6.1 INADVERTENT SAFETY/RELIEF VALVE OPENING ..................... 15.6-1 15.6.2 INSTRUMENT LINE PIPE BREAK............................................... 15.6-1 15.6.2.1 Identification of Causes and Frequency Classification ........................ 15.6-1 15.6.2.1.1 Identification of Causes .......................................................... 15.6-1 15.6.2.1.2 Frequency Classification ......................................................... 15.6-1 15.6.2.2 Sequence of Events and Systems Operation..................................... 15.6-1 15.6.2.2.1 The Effect of Single Failures and Operator Errors.......................... 15.6-2 15.6.2.3 Core and System Performance .................................................... 15.6-2 15.6.2.3.1 Qualitative Summary - Results .................................................. 15.6-2 15.6.2.4 Barrier Performance................................................................. 15.6-2 15.6.2.4.1 General .............................................................................. 15.6-2 15.6.2.5 Radiological Consequences ........................................................ 15.6-2 15.6.2.5.1 Results............................................................................... 15.6-3 15.6.3 STEAM GENERATOR TUBE FAILURE ........................................ 15.6-3 LDCN-03-003                                     15-xiv

COLUMBIA GENERATING STATION                                      Amendment 59 FINAL SAFETY ANALYSIS REPORT                                     December 2007 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                           Page 15.6.4 STEAM SYSTEM PIPING BREAK OUTSIDE CONTAINMENT .......... 15.6-3 15.6.4.1 Identification of Causes and Frequency Classification ........................ 15.6-3 15.6.4.1.1 Identification of Causes .......................................................... 15.6-3 15.6.4.1.2 Frequency Classification ......................................................... 15.6-3 15.6.4.2 Sequence of Events and Systems Operation..................................... 15.6-4 15.6.4.2.1 Sequence of Events ............................................................... 15.6-4 15.6.4.2.2 Systems Operation................................................................. 15.6-4 15.6.4.2.3 The Effect of Single Failures and Operator Errors.......................... 15.6-4 15.6.4.3 Core and System Performance .................................................... 15.6-4 15.6.4.3.1 Input Parameters and Initial Conditions ....................................... 15.6-4 15.6.4.3.2 Results............................................................................... 15.6-5 15.6.4.3.3 Considerations of Uncertainties................................................. 15.6-5 15.6.4.4 Barrier Performance................................................................. 15.6-5 15.6.4.5 Radiological Consequences ........................................................ 15.6-5 15.6.4.5.1 Results............................................................................... 15.6-6 15.6.5 LOSS-OF-COOLANT ACCIDENTS (RESULTING FROM SPECTRUM OF POSTULATED PIPING BREAKS WITHIN THE REACTOR COOLANT PRESSURE BOUNDARY) - INSIDE CONTAINMENT....... 15.6-6 15.6.5.1 Identification of Causes and Frequency Classification ........................ 15.6-7 15.6.5.1.1 Identification of Causes .......................................................... 15.6-7 15.6.5.1.2 Frequency Classification ......................................................... 15.6-7 15.6.5.2 Sequence of Events and Systems Operation..................................... 15.6-7 15.6.5.3 Core and System Performance .................................................... 15.6-7 15.6.5.4 Radiological Consequences ........................................................ 15.6-7 15.6.5.4.1 Design Basis Analysis ............................................................ 15.6-7 15.6.5.4.1.1 Fission Product Release from Fuel .......................................... 15.6-8 15.6.5.4.1.2 Fission Product Transport to the Environment ............................ 15.6-8 15.6.5.4.1.3 Suppression Pool pH Control ................................................. 15.6-9 15.6.5.4.1.4 Results ............................................................................ 15.6-9 15.6.6 FEEDWATER LINE BREAK - OUTSIDE CONTAINMENT................ 15.6-9 15.6.6.1 Identification of Causes and Frequency Classification ........................ 15.6-9 15.6.6.1.1 Identification of Causes .......................................................... 15.6-9 15.6.6.1.2 Frequency Classification ......................................................... 15.6-9 15.6.6.2 Sequence of Events and Systems Operation..................................... 15.6-9 15.6.6.2.1 Sequence of Events ............................................................... 15.6-9 15.6.6.2.2 Systems Operation................................................................. 15.6-9 LDCN-05-009, 06-043                              15-xv

COLUMBIA GENERATING STATION                                      Amendment 61 FINAL SAFETY ANALYSIS REPORT                                     December 2011 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.6.6.2.3 The Effect of Single Failures and Operator Errors .......................... 15.6-10 15.6.6.3 Core and System Performance .................................................... 15.6-10 15.6.6.3.1 Qualitative Summary ............................................................. 15.6-10 15.6.6.3.2 Qualitative Results ................................................................ 15.6-10 15.6.6.3.3 Consideration of Uncertainties .................................................. 15.6-10 15.6.6.4 Barrier Performance ................................................................. 15.6-10 15.6.6.5 Radiological Consequences ........................................................ 15.6-11 15.6.6.5.1 Fission Product Release .......................................................... 15.6-11 15.6.6.5.2 Fission Product Transport to the Environment ............................... 15.6-11 15.6.6.5.3 Results ............................................................................... 15.6-12 15.

==6.7 REFERENCES==
 ......................................................................... 15.6-12 15.7 RADIOACTIVE RELEASE FROM SUBSYSTEMS AND COMPONENTS ................................................................... 15.7-1 15.7.1 RADIOACTIVE GAS WASTE SYSTEM LEAK OR FAILURE ............. 15.7-1 15.7.2 LIQUID RADIOACTIVE SYSTEM FAILURE.................................. 15.7-1 15.7.3 POSTULATED RADIOACTIVE RELEASES DUE TO LIQUID RADWASTE TANK FAILURE ..................................................... 15.7-1 15.7.3.1 Identification of Causes and Frequency Classification ........................ 15.7-1 15.7.3.1.1 Identification of Causes .......................................................... 15.7-1 15.7.3.1.2 Frequency Classification ......................................................... 15.7-1 15.7.3.2 Sequence of Events and Systems Operation ..................................... 15.7-1 15.7.3.2.1 Sequence of Events ............................................................... 15.7-1 15.7.3.2.2 Systems Operation................................................................. 15.7-2 15.7.3.2.3 The Effects of Single Failures and Operator Errors ......................... 15.7-2 15.7.3.3 Core and System Performance .................................................... 15.7-2 15.7.3.4 Barrier Performance ................................................................. 15.7-2 15.7.3.5 Radiological Consequences ........................................................ 15.7-3 15.7.4 FUEL HANDLING ACCIDENT ................................................... 15.7-3 15.7.4.1 Identification of Causes and Frequency Classification ........................ 15.7-3 15.7.4.1.1 Identification of Causes .......................................................... 15.7-3 15.7.4.1.2 Frequency Classification ......................................................... 15.7-3 15.7.4.2 Sequence of Events and Systems Operation ..................................... 15.7-4 15.7.4.2.1 The Effects of Single Failures and Operator Errors ......................... 15.7-4 15.7.4.3 Core and System Performance .................................................... 15.7-4 15.7.4.3.1 Mathematical Model .............................................................. 15.7-4 LDCN-09-007                                      15-xvi

COLUMBIA GENERATING STATION                                      Amendment 63 FINAL SAFETY ANALYSIS REPORT                                     December 2015 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.7.4.3.2 Input Parameters and Initial Conditions ....................................... 15.7-5 15.7.4.3.3 Results ............................................................................... 15.7-5 15.7.4.4 Barrier Performance ................................................................. 15.7-5 15.7.4.5 Radiological Consequences ........................................................ 15.7-6 15.7.4.5.1 Design Basis Analysis ............................................................ 15.7-6 15.7.4.5.1.1 Fission Product Release From Fuel ......................................... 15.7-6 15.7.4.5.1.2 Fission Product Transport to the Environment ............................ 15.7-6 15.7.4.5.1.3 Results ............................................................................ 15.7-6 15.7.5 SPENT FUEL CASK DROP ACCIDENT ........................................ 15.7-6 15.

==7.6 REFERENCES==
 ......................................................................... 15.7-7 15.8 ANTICIPATED TRANSIENTS WITHOUT SCRAM............................. 15.8-1 15.8.0 CAPABILITIES OF PRESENT DESIGN TO ACCOMMODATE ANTICIPATED TRANSIENTS WITHOUT SCRAM ......................... 15.8-1 15.8.1 INADVERTENT CONTROL ROD WITHDRAWAL ......................... 15.8-2a 15.8.2 LOSS OF FEEDWATER ............................................................ 15.8-2a 15.8.2.1 Identification of Causes and Frequency Classification ........................ 15.8-2a 15.8.2.1.1 Identification of Causes .......................................................... 15.8-2a 15.8.2.1.2 Frequency Classification ......................................................... 15.8-3 15.8.2.2 Sequence of Events and System Operation ...................................... 15.8-3 15.8.2.2.1 Sequence of Events ............................................................... 15.8-3 15.8.2.2.1.1 Identification of Operator Actions ........................................... 15.8-3 15.8.2.2.2 System Operation .................................................................. 15.8-3 15.8.2.2.3 The Effect of Single Failure and Operator Errors ........................... 15.8-3 15.8.2.3 Core and System Performance .................................................... 15.8-4 15.8.2.3.1 Mathematical Model .............................................................. 15.8-4 15.8.2.3.2 Input Parameters and Initial Conditions ....................................... 15.8-4 15.8.2.3.3 Results ............................................................................... 15.8-4 15.8.2.3.4 Consideration of Uncertainties .................................................. 15.8-4 15.8.2.4 Barrier Performance ................................................................. 15.8-5 15.8.2.5 Radiological Consequences ........................................................ 15.8-5 15.8.3 LOSS OF ALTERNATE CURRENT POWER................................... 15.8-5 15.8.4 LOSS OF ELECTRICAL LOAD ................................................... 15.8-5 15.8.5 LOSS OF CONDENSER VACUUM ............................................... 15.8-5 15.8.6 TURBINE TRIP ........................................................................ 15.8-5 LDCN-10-004                                      15-xvii

COLUMBIA GENERATING STATION                                      Amendment 61 FINAL SAFETY ANALYSIS REPORT                                     December 2011 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.8.7 CLOSURE OF MAIN STEAM LINE ISOLATION VALVES ................ 15.8-6 15.8.7.1 Identification of Causes and Frequency Classification ........................ 15.8-6 15.8.7.1.1 Identification of Causes .......................................................... 15.8-6 15.8.7.1.2 Frequency Classification ......................................................... 15.8-6 15.8.7.2 Sequence of Events and System Operation ...................................... 15.8-6 15.8.7.2.1 Sequence of Events ............................................................... 15.8-6 15.8.7.2.1.1 Identification of Operator Actions ........................................... 15.8-6 15.8.7.2.2 System Operation .................................................................. 15.8-6 15.8.7.2.3 The Effect of Single Failures and Operator Errors .......................... 15.8-7 15.8.7.3 Core and System Performance .................................................... 15.8-7 15.8.7.3.1 Mathematical Model .............................................................. 15.8-7 15.8.7.3.2 Input Parameters and Initial Conditions ....................................... 15.8-7 15.8.7.3.3 Results ............................................................................... 15.8-7 15.8.7.3.4 Consideration of Uncertainties .................................................. 15.8-8 15.8.7.4 Barrier Performance ................................................................. 15.8-8 15.8.7.5 Radiological Consequences ........................................................ 15.8-8 15.8.8 INADVERTENT OPENING OF RELIEF VALVE ............................. 15.8-9 15.8.8.1 Identification of Causes and Frequency Classification ........................ 15.8-9 15.8.8.1.1 Identification of Causes .......................................................... 15.8-9 15.8.8.1.2 Frequency Classification ......................................................... 15.8-9 15.8.8.2 Sequence of Events and System Operation ...................................... 15.8-9 15.8.8.2.1 Sequence of Events ............................................................... 15.8-9 15.8.8.2.1.1 Identification of Operator Actions ........................................... 15.8-9 15.8.8.2.1.2 System Operation ............................................................... 15.8-9 15.8.8.2.2 The Effect of Single Failures and Operator Errors .......................... 15.8-9 15.8.8.3 Core and System Performance .................................................... 15.8-10 15.8.8.3.1 Mathematical Model .............................................................. 15.8-10 15.8.8.3.2 Input Parameters and Initial Conditions ....................................... 15.8-10 15.8.8.3.3 Results ............................................................................... 15.8-10 15.8.8.3.4 Consideration of Uncertainties .................................................. 15.8-11 15.8.8.4 Barrier Performance ................................................................. 15.8-11 15.8.8.5 Radiological Consequences ........................................................ 15.8-11 15.8.9 PRESSURE REGULATOR FAILURE - OPEN (PREGO)..................... 15.8-11 15.8.9.1 Identification of Causes and Frequency Classification ........................ 15.8-11 15.8.9.1.1 Identification of Causes .......................................................... 15.8-11 15.8.9.1.2 Frequency Classification ......................................................... 15.8-11 LDCN-09-007                                      15-xviii

COLUMBIA GENERATING STATION                                      Amendment 63 FINAL SAFETY ANALYSIS REPORT                                     December 2015 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.8.9.2 Sequence of Events and System Operation ...................................... 15.8-11 15.8.9.2.1 Sequence of Events ............................................................... 15.8-11 15.8.9.2.1.1 Identification of Operator Actions ........................................... 15.8-12 15.8.9.2.1.2 System Operation ............................................................... 15.8-12 15.8.9.2.3 The Effect of Single Failures and Operator Errors .......................... 15.8-12 15.8.9.3 Core and System Performance .................................................... 15.8-12 15.8.9.3.1 Mathematical Model .............................................................. 15.8-12 15.8.9.3.2 Input Parameters and Initial Conditions ....................................... 15.8-12 15.8.9.3.3 Results ............................................................................... 15.8-13 15.8.9.3.4 Consideration of Uncertainties .................................................. 15.8-13 15.8.9.4 Barrier Performance ................................................................. 15.8-13 15.8.9.5 Radiological Consequences ........................................................ 15.8-13 15.8.10 SINGLE REACTOR RECIRCULATION SYSTEM PUMP OPERATION ................................................................ 15.8-14 15.8.11 REFERENCES ........................................................................ 15.8-15 LDCN-10-004                                      15-xix

COLUMBIA GENERATING STATION                                    Amendment 63 FINAL SAFETY ANALYSIS REPORT                                   December 2015 Chapter 15 ACCIDENT ANALYSES LIST OF TABLES Number                                   Title                                                Page 15.0-1      Results Summary of Transient Events Applicable to Columbia Generating Station .............................................................. 15.0-17 15.0-1A     Summary of Transient Peak Value Results Single-Loop Operation .... 15.0-20 15.0-2      Input Parameters and Initial Conditions for Transients................... 15.0-21 15.0-2A     Input Parameters and Initial Conditions for Transients and Accidents for Single-Loop Operation........................................ 15.0-24 15.0-2B     Input Parameters and Initial Conditions for ARTS/MELLLA and GNF Reload Transient ......................................................... 15.0-26 15.0-3      Summary of Accidents ......................................................... 15.0-28 15.0-4      /Q (s/m3) values for the EAB and LPZ .................................... 15.0-29 15.0-5      Control Room Atmospheric Dispersion Factors (sec/m3) ................ 15.0-30 15.1-1      Sequence of Events for Figure 15.1-1 ....................................... 15.1-17 15.1-1A     Sequence of Events for Figure 15.1-3 ....................................... 15.1-18 15.1-2      Sequence of Events for Figure 15.1-2 ....................................... 15.1-19 15.1-3      Sequence of Events for Inadvertent Safety/Relief Valve Opening ..... 15.1-20 15.1-4      Sequence of Events for Inadvertent Residual Heat Removal Shutdown Cooling Operation ................................................. 15.1-21 15.2-1      Sequence of Events for Figure 15.2-1 ....................................... 15.2-35 15.2-2      Sequence of Events for Figure 15.2-2.1 .................................... 15.2-36 15.2-3      Sequence of Events for Figure 15.2-2.2 .................................... 15.2-37 15.2-4      Sequence of Events for Figure 15.2-3 ....................................... 15.2-38 LDCN-10-004                                  15-xx

COLUMBIA GENERATING STATION                                  Amendment 61 FINAL SAFETY ANALYSIS REPORT                                 December 2011 Chapter 15 ACCIDENT ANALYSES LIST OF TABLES (Continued)
Number                                 Title                                                Page 15.2-5      Sequence of Events for Figure 15.2-4 ....................................... 15.2-39 15.2-6      Sequence of Events for Figure 15.2-5 ....................................... 15.2-40 15.2-7      Sequence of Events for Figure 15.2-6 ....................................... 15.2-41 15.2-8      Trip Signals Associated with Loss-of-Condenser Vacuum .............. 15.2-42 15.2-9      Sequence of Events for Figure 15.2-7 ....................................... 15.2-43 15.2-10     Sequence of Events for Figure 15.2-8 ....................................... 15.2-44 15.2-11     Sequence of Events for Figure 15.2-9 ....................................... 15.2-45 15.2-12     Sequence of Events for Failure of Residual Heat Removal Shutdown Cooling .............................................................. 15.2-46 15.2-13     Evaluation of Failure of Residual Heat Removal Shutdown Cooling .............................................................. 15.2-47 15.3-1      Sequence of Events for Figure 15.3-1 ....................................... 15.3-13 15.3-2      Sequence of Events for Figure 15.3-2 ....................................... 15.3-14 15.3-3      Sequence of Events for Figure 15.3-3 ....................................... 15.3-15 15.3-4      Sequence of Events for Figure 15.3-4 ....................................... 15.3-16 15.3-5      Sequence of Events for Figure 15.3-5 ....................................... 15.3-17 15.3-6      Sequence of Events for Pump Seizure (for Single Loop Operation) ... 15.3-18 15.4-1      Sequence of Events - Rod Withdrawal Error in Power Range .......... 15.4-21 LDCN-10-029                               15-xxi

COLUMBIA GENERATING STATION                                     Amendment 59 FINAL SAFETY ANALYSIS REPORT                                    December 2007 Chapter 15 ACCIDENT ANALYSES LIST OF TABLES (Continued)
Number                                    Title                                                Page 15.4-2      Sequence of Events for an Abnormal Startup of an Idle Recirculation Loop ............................................................. 15.4-22 15.4-3      Reactor Recirculation Pump Flow Increase Input Parameters and Initial Conditions................................................................ 15.4-23 15.4-4      Control Rod Drop Accident Evaluation Parameters ...................... 15.4-24 15.4-5      Control Rod Drop Accident Activity Airborne in the Condenser (Curies) ............................................................. 15.4-26 15.4-6      Control Rod Drop Accident Activity Airborne to the Environment (Curies) .......................................................... 15.4-29 15.4-7      Control Rod Drop Accident Radiological Effects (rem) ................. 15.4-32 15.5-1      Input Parameters and Initial Conditions HPCS Injection ................ 15.5-5 15.6-1      Instrument Line Break Accident - Parameters Tabulated for Postulated Accident Analyses................................................. 15.6-13 15.6-2      Instrument Line Failure ........................................................ 15.6-15 15.6-3      Instrument Line Failure Radiological Effects .............................. 15.6-16 15.6-4      Sequence of Events for Steam Line Break Outside Containment....... 15.6-17 15.6-5      Steam Line Break Accident - Parameters Tabulated for Postulated Accident Analyses................................................. 15.6-18 15.6-6      Steam Line Break Accident Activity Release to Environment (Curies) .......................................................... 15.6-20 15.6-7      Steam Line Break Accident Radiological Effects of a Puff Release ... 15.6-21 LDCN-05-009                                  15-xxii

COLUMBIA GENERATING STATION                                     Amendment 59 FINAL SAFETY ANALYSIS REPORT                                   December 2007 Chapter 15 ACCIDENT ANALYSES LIST OF TABLES (Continued)
Number                                    Title                                                Page 15.6-8      Loss-of-Coolant Accident - Parameters Tabulated for Postulated Accident Analysis ................................................. 15.6-22 15.6-9      Loss-of-Coolant Accident Primary Containment Activity (Curies) .... 15.6-25 15.6-10     Loss-of-Coolant Accident Secondary Containment Activity (Curies) - 20 Minute Drawdown .................................. 15.6-26 15.6-11     Loss-of-Coolant Accident Activity Released to the Environment (Curies) - 20 Minute Drawdown ............................ 15.6-27 15.6-12     Loss-of-Coolant Accident (Design Basis Analysis)
Radiological Effects ............................................................ 15.6-28 15.6-13     Sequence of Events for Feedwater Line Break Outside Containment...................................................................... 15.6-29 15.6-14     Feedwater Line Break Accident - Parameters Tabulated for Postulated Accident Analysis............................................. 15.6-30 15.6-15     Feedwater Line Break Accident Activity Release to Environment (Curies) .......................................................... 15.6-32 15.6-16     Feedwater Line Break Accident Biological Effects of a Puff Release...................................................................... 15.6-33 15.7-1      Liquid Radwaste Tanks Failure - Parameters and Concentrations ..... 15.7-9 15.7-2      Fuel Handling Accident Parameters Tabulated for Postulated Accident Analysis ................................................. 15.7-10 15.7-3      Fuel Handling Accident Activity Airborne in Secondary Containment (Curies)........................................................... 15.7-12 15.7-4      Fuel Handling Accident Activity Released to the Environment (Curies) .......................................................... 15.7-13 LDCN-05-009                                 15-xxiii

COLUMBIA GENERATING STATION                                      Amendment 63 FINAL SAFETY ANALYSIS REPORT                                     December 2015 Chapter 15 ACCIDENT ANALYSES LIST OF TABLES (Continued)
Number                                      Title                                                Page 15.7-5      Fuel Handling Accident (Design Basis Analysis)
Radiological Effects ............................................................ 15.7-14 15.8-1      Anticipated Transients Without Scram Analysis Initial Conditions .... 15.8-17 15.8-1A     Anticipated Transients Without Scram Analysis for MELLLA Initial Conditions and Equipment Performance Characteristics ................. 15.8-17a 15.8-2      Anticipated Transients Without Scram Analysis Equipment Performance Characteristics .................................................. 15.8-18 15.8-3      Summary of Anticipated Transients Without Scram Results ............ 15.8-19 15.8-4      Sequence of Events for Loss of Feedwater ................................. 15.8-20 15.8-5      Sequence of Events for Main Steam Line Isolation Valve Closure (Long Term Transient) .............................................. 15.8-21 15.8-6      Deleted ............................................................................ 15.8-22 15.8-7      Sequence of Events for Inadvertent Open Relief Valve .................. 15.8-23 15.8-8      Sequence of Events for Pressure Regulator Failure Open (Long Term Transient) ......................................................... 15.8-24 LDCN-10-004                                    15-xxiv

COLUMBIA GENERATING STATION                     Amendment 60 FINAL SAFETY ANALYSIS REPORT                   December 2009 Chapter 15 ACCIDENT ANALYSES LIST OF FIGURES Number                                  Title 15.0-1      Scram Position and Reactivity Characteristics 15.0-2      Illustration of Single Recirculation Loop Operation Flows 15.1-1      Feedwater Controller Failure, Maximum Demand 15.1-2      Pressure Regulator Failure - Open at 106.2% Uprated Power, 100% Flow (Sheets 1 through 11) 15.1-3      Feedwater Controller Failure, Maximum Demand, EOC RPT OOS, Single Loop Operation and 75% Uprated Power, 57% Flow (Sheets 1 through 4) 15.2-1      Pressure Regulatory Failure - Down Scale Failure at 104.1% Uprated Power, 106% Flow 15.2-2.1    Generator Load Rejection with Bypass On - Original Rated Power (Sheet 1) 15.2-2.2    Generator Load Rejection with BP Failure 15.2-3      Turbine Trip, Trip Scram, Bypass, and RPT - On 15.2-4      Turbine Trip with Bypass Failure 15.2-5      Main Steam Line Isolation Valve Closure at 106.2% Uprated Power, 100% Rated Flow 15.2-6      Loss of Condenser Vacuum at 104.1% Uprated Power, 100% Rated Flow 15.2-7      Loss of Auxiliary Power Transformers - 106.2% Uprated Power, 100% Rated Flow 15.2-8      Loss of All Grid Connections - 104.1% Uprated Power, 100% Rated Flow 15.2-9      Loss of All Feedwater Flow - 106.2% Uprated Power, 100% Rated Flow LDCN-08-035                                15-xxv

COLUMBIA GENERATING STATION                       Amendment 60 FINAL SAFETY ANALYSIS REPORT                     December 2009 Chapter 15 ACCIDENT ANALYSES LIST OF FIGURES (Continued)
Number                            Title 15.2-10 Automatic Depressurization System/Residual Heat Removal Cooling Loops (Sheets 1 and 2) 15.2-11 Summary of Paths Available to Achieve Cold Shutdown 15.2-12 Activity C1 Alternate Shutdown Cooling Path Utilizing Residual Heat Removal Loop B 15.2-13 Residual Heat Removal Loop C 15.2-14 Residual Heat Removal Loop A (B) (Suppression Pool Cooling/Rated Pump Flow Test Mode) 15.2-15 Activity C2 Alternate Shutdown Cooling Path Utilizing Residual Heat Removal Loop A 15.2-16 Vessel Temperature and Pressure Versus Time (Activity C1.b.1 or C2) 15.2-17 Vessel Temperature and Pressure Versus Time (Activity C1.b.2) 15.2-18 Suppression Pool Temperature Versus Time (with 87&deg;F Service Water Temperature) (Activity C1.b.1 or C.2) 15.2-19 Suppression Pool Temperature Versus Time (with 87&deg;F Service Water Temperature) (Activity C1.b.2) 15.3-1  One Recirculation Pump Trip at 106.2% Uprated Power, 100% Flow (Sheets 1 through 5) 15.3-2  Two Recirculation Pump Trip at 106.2% Uprated Power, 100% Flow (Sheets 1 through 5) 15.3-3  Recirculation Flow Control Failure - Decreasing Flow in One Loop at 106.2% Uprated Power, 100% Flow (Sheets 1 through 5) 15-xxvi

COLUMBIA GENERATING STATION                        Amendment 60 FINAL SAFETY ANALYSIS REPORT                      December 2009 Chapter 15 ACCIDENT ANALYSES LIST OF FIGURES (Continued)
Number                                 Title 15.3-4      Recirculation Flow Control Failure - Decreasing Flow in Two Loops, (5%/Sec Ramp) at 106.2% Uprated Power, 100% Flow (Sheets 1 through 5) 15.3-5      Recirculation Pump Seizure at 106% Uprated Power, 100% Flow (Sheets 1 through 5) 15.3-6      SLO Recirculation Pump Seizure Results 15.4-1      Abnormal Startup of an Idle Recirculation Loop at 57.9% Uprated Power, 34.1% Flow (Sheets 1 through 5) 15.4-2      Leakage Path Model for Rod Drop Accident (Original Rated Power) 15.5-1      Inadvertent Start of High-Pressure Core Spray Pump at 102% Uprated Power, 88% Flow 15.6-1      Leakage Path for Instrument Line Break 15.6-2      Steam Flow Schematic for Steam Break Outside Containment 15.6-3      Leakage Path for LOCA 15.6-4      Leakage Path for Feedwater Line Break Outside Containment 15.7-1      Leakage Path for Fuel Handling Accident 15.8-1      Loss of Feedwater Event (Sheets 1 through 5) 15.8-2      Main Steam Isolation Valve Closure Event (Sheets 1 through 5) 15.8-3      Main Steam Isolation Valve Closure Event with Four SRVs Out-of-Service (Sheets 1 through 5) 15.8-4      Inadvertent Opening of Relief Valve Event (Sheets 1 through 5) 15.8-5      Pressure Regulator Failure - Open Event (Sheets 1 through 5)
LDCN-08-035                              15-xxvii

COLUMBIA GENERATING STATION                            Amendment 63 FINAL SAFETY ANALYSIS REPORT                           December 2015 Chapter 15 ACCIDENT ANALYSES 15.0    GENERAL This chapter discusses the effects of anticipated process disturbances and postulated component failures, their consequences, and the capabilities built into the plant to control or accommodate such failures and events. The analyses have been reviewed and revised, as needed, for the:
Reactor power uprate Installation of the adjustable speed drive for the reactor recirculation pumps Implementation of an alternative source term APRM/RBM Technical Specification (ARTS) improvement program Maximum Extended Load Line Limit Analysis (MELLLA)
Cycle specific changes These changes to the plant licensing and design basis and their impact are discussed in this chapter.
The scope of the situations analyzed includes anticipated (expected) operational occurrences, off-design abnormal (unexpected) transients that induce system operating condition disturbances, postulated accidents of low probability, and hypothetical events of extremely low probability. For each reload, the events are evaluated by the fuel vendor(s). The events identified as limiting during the evaluation are analyzed and the sections are revised.
The plant was originally licensed at 3323 MWt. In 1995, an amendment to the plant Operating License authorized an increase in power to 3486 MWt. The power uprate analysis was performed in accordance with the NRC-approved General Electric Company (GE) generic power uprate program for boiling water reactors (BWRs).
The postulated events in this chapter have been analyzed for power uprate conditions. The only exceptions to using uprated power are some non-limiting single loop operation (SLO) transients that were not reanalyzed as part of the GE power uprate transient analysis. Their text and figures are clearly marked with ORIGINAL POWER designation. Limiting events in terms of setting the fuel operating limits (e.g., Loss of Feedwater Heating, Generator Load Rejection Without Bypass) are reanalyzed on a cycle specific basis and therefore, may include fuel vendor results and references.
The events in this chapter have been analyzed for application of the adjustable speed drives (ASD) in place of the former reactor recirculation control system that used flow control valves (FCV). The uprated power for Columbia Generating Station is 3486 MWt which is 4.9%
higher than the original licensed power of 3323 MWt. All transient initial conditions are specified in Table 15.0-2, 15.0-2A, 15.0-2B or the individual transient event description sections. Several performance improvement packages have been included in the analysis:
LDCN-10-004                                     15.0-1

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015
: 1.      Final Feedwater Temperature Reduction (FFWTR) and Feedwater Heaters Out-Of-Service (FWHOOS) - Analyses were performed at a reduced feedwater temperature at rated thermal power for operations at end-of-cycle and during the cycle for limiting transients.
: 2.      Increased Core Flow (ICF) - Increased core flow allows for operation at 106% of the rated core flow. The limiting transients were performed for the end-of-cycle with control rods fully withdrawn. This envelopes the operation at increased core flow condition throughout the cycle.
3a. Extended Load Line Limit Analysis (ELLLA) - The consequences of the transients were evaluated to determine if operating limit adjustments are necessary for operation in the extended operating domain and compared with the evaluation at rated thermal power and increased core flow region. This comparison ensures bounding of the results at the extended operating domain.
3b. Maximum Extended Load Line Limit Analysis (MELLLA) - The consequences of the transients were evaluated to determine if operating limit adjustments are necessary for operation in the maximum extended operating domain and compared with the evaluation at rated thermal power and increased core flow region. This comparison ensures bounding of the results at the maximum extended operating domain.
: 4.      Single Loop Operation (SLO) - Limiting transients were re-analyzed for operation at SLO. Using adjustable speed drives (ASD), GE determined the maximum active loops recirculation flow at 105% of rated pump speed with resultant analyzed power and core flow conditions of 75% UP and 57% of rated core flow for SLO. Prior to power uprate, a comprehensive SLO analysis was performed. For non-limiting events, this analysis has been retained for completeness and historical purposes. These analyses are clearly marked with ORIGINAL POWER designation.
: 5.      End-of-Cycle RPT Out-of-Service (RPT OOS) - The recirculation pump trip (RPT) mitigates several transients that are more severe at end-of-cycle. The limiting transients were re-analyzed with RPT OOS at various power/flow conditions.
: 6.      Turbine Bypass Out-of-Service - Limiting transient events have been analyzed with turbine bypass valves out-of-service at limiting power and flow conditions.
: 7.      Average Power Range Monitor, Rod Block Monitor Technical Specifications (ARTS) -
The ARTS improvement program improves fuel thermal limits protection at off-rated conditions with a more rigorous application of power and flow dependent Minimum Critical Power Ratio (MCPR) and Linear Heat Generation Rate (LHGR) limits. The ARTS improvement program eliminates the Technical Specification requirement for total peaking factor setdown at off-rated conditions. The ARTS program includes modification of the Rod Block Monitor (RBM), from flow-based to power-based LDCN-10-004                                    15.0-2

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                         December 2015 setpoints, to improve the rod movement flexibility at less than rated power conditions, and establish an optimized configuration that improves the system response with respect to bundle power.
Additional updates address the implementation of the use of alternative source terms (AST) as described in the Regulatory Guide 1.183, July 2000, Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors. This methodology is based on the advances that have been made in understanding the timing, magnitude, and the chemical form of fission product releases from severe nuclear power plant accidents. The accidents that were reanalyzed by Energy Northwest with the AST:
Loss of coolant accident (LOCA)
Fuel handling accident (FHA)
Control rod drop accident (CRDA)
Main steam line break, outside containment, accident (MSLB)
The radiological consequences of these accidents were determined based on AST approved for use under 10 CFR 50.67. In accordance with the guidance provided in Regulatory Guide 1.183, the licensing and design basis are revised to reflect the application of full scope AST methodology (with the exception that the TID-14844 will continue to be used as the basis for equipment qualification (EQ) and radiation zone maps/shielding calculations). The accidents analyzed as part of the implementation of AST are subject to the limits specified in 10 CFR 50.67 and guidelines of Regulatory Guide 1.183.
15.0.1      ANALYTICAL OBJECTIVE The spectrum of postulated initiating events is divided into categories based on the type of disturbance and the expected frequency of the initiating occurrence. The limiting events in each combination of category and frequency are quantitatively analyzed.
15.0.2      ANALYTICAL CATEGORIES Transient and accident events contained in this report are provided in individual categories as specified by Regulatory Guide 1.70, Revision 2. The results of the events are summarized in Table 15.0-1. Events evaluated are assigned to one of the following applicable categories:
: a. Decrease in reactor coolant temperature:
Reactor vessel water (moderator) temperature reduction results in an increase in core reactivity. This could lead to fuel-cladding damage.
: b. Increase in reactor pressure:
Nuclear system pressure increases threaten to rupture the reactor coolant pressure boundary (RCPB). Increasing pressure also collapses the voids in the LDCN-10-004                                  15.0-3

COLUMBIA GENERATING STATION                          Amendment 63 FINAL SAFETY ANALYSIS REPORT                         December 2015 core-moderator, thereby increasing core reactivity and power level that could threaten fuel cladding due to overheating.
: c. Decrease in reactor coolant system flow rate:
A reduction in the core coolant flow rate could overheat the cladding as the coolant becomes unable to adequately remove the heat generated by the fuel.
: d. Reactivity and power distribution anomalies:
Transient events included in this category are those that could cause rapid increases in power due to increased core flow disturbance events. Increased core flow reduces the void content of the moderator increasing core reactivity and power level.
: e. Increase in reactor coolant inventory:
Increasing coolant inventory could result in excessive moisture carryover to components such as the main turbine, feedwater turbines, etc.
: f. Decrease in reactor coolant inventory:
Reductions in coolant inventory could threaten the fuel as the coolant becomes less able to remove heat generated in the core.
: g. Radioactive release from subsystems and components:
Loss of integrity of a radioactive containment component is postulated.
: h. Anticipated transients without scram:
To determine the capability of plant design to accommodate an extremely low probability event, a multi-system maloperation situation is postulated.
15.0.2.1     Single Loop Operation (SLO)
Operation with one recirculation loop results in a maximum power output that is 20% to 30% below that which is attainable for two-pump operation. Therefore, the consequences of abnormal operation transients from one-loop operation will be considerably less severe than those analyzed from a two-loop operational mode because of the associated reduction in operation power level.
15.0-4

COLUMBIA GENERATING STATION                            Amendment 63 FINAL SAFETY ANALYSIS REPORT                           December 2015 For pressurization, flow decrease, and cold water increase transients, results presented bound both the thermal and overpressure consequences of one-loop operation. The consequences of flow decrease transients are also bounded by the full power analysis. A single pump trip from one-loop operation is less severe than a two-pump trip from full power because of the reduced initial power level.
Cold water increase transients can result from either recirculation flow controller failure or introduction of colder water into the reactor vessel by events such as loss of feedwater heater.
For the former, the flow-dependent MCPR values are derived assuming both recirculation loop controllers fail. This condition produces the maximum possible power increase and, hence, maximum MCPR for transients initiated from less than rated power and flow. When operating with only one recirculation loop, the flow and power increase associated with this failure with only one recirculation loop will be less than that associated with both loops; therefore, the MCPR values derived with the two-pump assumption are conservative for SLO.
The latter event, loss of feedwater heating, is generally the most severe cold water increase event with respect to increase in core power. This event is caused by positive reactivity insertion from core inlet subcooling and it is relatively insensitive to initial power level.
A generic statistical loss of feedwater heater analysis using different initial power levels and other core design parameters concluded one-pump operation with lower initial power level is conservatively bounded by the full power two-pump analysis. Inadvertent restart of the idle recirculation pump has been analyzed and is applicable for SLO.
From the above discussions, the transient consequence from SLO is bounded by previously submitted full power analyses. The maximum power level that can be attained with one-loop operation is only restricted by the MCPR and overpressure limits established from a full-power analysis.
The following most limiting transients of coldwater increase, pressurization and flow decrease events are analyzed for SLO and the results are shown in Table 15.0-1A:
: a. Feedwater flow controller failure (maximum demand),
: b. Generator load rejection with bypass failure, and
: c. One pump seizure accident.
LDCN-10-004                                   15.0-4a

COLUMBIA GENERATING STATION                          Amendment 63 FINAL SAFETY ANALYSIS REPORT                         December 2015 15.0.3      EVENT EVALUATION 15.0.3.1       Identification of Causes and Frequency Classification Situations and causes that lead to the initiating event analyzed are described within the analytical categories. The frequency of occurrence of each event is summarized based on operating plant history for the transient event. Events for which inconclusive data exist are discussed separately within each event section.
Each initiating event within the major groups is assigned to one of the following frequency groups:
: a.      Incidents of moderate frequency - these are incidents that may occur during a calendar year to once per lifetime. This event is referred to as an anticipated (expected) operational transient.
: b.      Infrequent incidents - these are incidents that may occur during the life of the particular plant. This event is referred to as an abnormal (unexpected) operational transient.
: c.      Limiting faults - these are occurrences that are not expected to occur but are postulated because their consequences may result in the release of significant amounts of radioactive material. This event is referred to as a design basis (postulated) accident.
15.0-5

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 15.0.3.1.1    Unacceptable Results for Incidents of Moderate Frequency [Anticipated (Expected) Operational Transients]
The following are unacceptable safety results for incidents of moderate frequency:
: a. Release of radioactive material to the environs that exceeds the limits of 10 CFR 20,
: b. Reactor operation induced fuel cladding failure,
: c. Nuclear system stresses in excess of that allowed for the transient classification by applicable industry codes, and
: d. Containment stresses in excess of that allowed for the transient classification by applicable industry codes.
15.0.3.1.2    Unacceptable Results for Infrequent Incidents [Abnormal (Unexpected)
Operational Transients]
The following are unacceptable safety results for infrequent incidents:
: a. Release of radioactivity that results in dose consequences that exceed a small fraction of 10 CFR 50.67 values,
: b. Fuel damage that would preclude resumption of normal operation after a normal restart,
: c. Generation of a condition that results in consequential loss of function of the reactor coolant system, and
: d. Generation of a condition that results in a consequential loss of function of a necessary containment barrier.
15.0.3.1.3    Unacceptable Results for Limiting Faults [Design-Basis (Postulated)
Accidents]
The following are unacceptable safety results for limiting faults:
: a. Radioactive material release that results in dose consequences that exceed the requirements of 10 CFR 50.67, 15.0-6

COLUMBIA GENERATING STATION                              Amendment 60 FINAL SAFETY ANALYSIS REPORT                            December 2009
: b.      Failure of fuel cladding that would cause changes in core geometry such that core cooling would be inhibited,
: c.      Nuclear system stresses in excess of those allowed for the accident classification by applicable industry codes,
: d.      Containment stresses in excess of those allowed for the accident classification by applicable industry codes when containment is required, and
: e.      Radiation exposure to plant operations personnel in the main control room in excess of 5 rem total effective dose equivalent (TEDE) for the duration of the accident.
15.0.3.2       Sequence of Events and Systems Operation Each transient or accident is discussed and evaluated in terms of
: a.      A step-by-step sequence of events from initiation to final stabilized condition (e.g., termination of the accident),
: b.      The extent to which normally operating plant instrumentation and controls are assumed to function,
: c.      The extent to which plant and reactor protection systems are required to function,
: d.      The credit taken for the functioning of normally operating plant systems,
: e.      The operation of engineered safety systems that is required, and
: f.      The effect of a single failure or an operator error on the event.
The transient or accident discussion is specific to the event in that it is limited to the events and system operations related to the reactor core performance and postulated damage. In general, the step-by-step description ends when the analysis has demonstrated that the core performance results are within established limits. The stabilized condition does not imply that all actions to stabilize plant parameters or to recover from the transient or accident have been completed by plant personnel. In the stabilized condition, either the core has demonstrated compliance with requirements or the postulated or deterministic damage is complete. At this point, the transient or accident is terminated. After termination of the event, the operator actions or system operations are not event specific. The required actions and expected system operations, needed to establish cold shutdown or to initiate recovery actions, are symptom based and described in 15.0-7

COLUMBIA GENERATING STATION                           Amendment 60 FINAL SAFETY ANALYSIS REPORT                          December 2009 procedures. The events associated with a radiological release and radiological consequences of the transient or accident are also discussed.
15.0.3.2.1      Single Failures or Operator Errors 15.0.3.2.1.1 General. The events considered in this section were evaluated and are provided in this chapter in accordance with Regulatory 1.70, Revision 2.
15.0.3.2.1.2 Initiating Event Analysis.
: a.      The undesired opening or closing of any single valve (a check valve is not assumed to close against normal flow),
: b.      The undesired starting or stopping of any single component,
: c.      The malfunction or maloperation of any single control device,
: d.      Any single electrical component failure, or
: e.      Any single operator error.
Operator error is defined as an active deviation from written operating procedures or nuclear plant standard operating practices. The set of actions is limited as follows:
: a.      Those actions that could be performed by one person,
: b.      Those actions that would have constituted a correct procedure had the initial decision been correct, and
: c.      Those actions that are subsequent to the initial operator error and have an effect on the designed operation of the plant, but are not necessarily directly related to the operator error.
Examples of single operator errors are as follows:
: a.      An increase in power above the established flow control power limits by control rod withdrawal in the specified sequences,
: b.      The selection and complete withdrawal of a single control rod out of sequence,
: c.      An incorrect calibration of an average power range monitor (APRM), and 15.0-8

COLUMBIA GENERATING STATION                            Amendment 63 FINAL SAFETY ANALYSIS REPORT                           December 2015
: d.      Manual isolation of the main steam lines as a result of operator misinterpretation of an alarm or indication.
15.0.3.2.1.3 Single Active Component Failure or Single Operator Error Analysis.
: a.      The undesired action or maloperation of a single active component, or
: b.      Any single operator error where operator errors are defined as in Section 15.0.3.2.1.2.
15.0.3.3        Core and System Performance Fuel thermal and hydraulic design are described in Section 4.4.
The fuel cladding integrity safety limit is set so that no fuel damage is calculated to occur if the limit is not violated. Exceeding unacceptable results criteria for fuel cladding integrity for anticipated operational transients is avoided by meeting the following criteria provided in the NRC Standard Review Plan (NUREG-0800) Section 4.4:
: a.      The expected number of fuel rods in boiling transition should not exceed 0.1%
of the fuel rods in the core. This criterion is met by ensuring that the MCPR for any anticipated operational transient is calculated to be not less than the safety limit MCPR values given in the cycle-specific Core Operating Limits Report (COLR).
: b.      No fuel centerline melting nor uniform total cladding strain in excess of 1% will occur. This criterion is met by compliance with the operating limits for LHGR given in the cycle-specific COLR.
The operating limit for MCPR is developed as follows:
The MCPR calculated during the transient is compared to the safety limit. The MCPR safety limit is established using the critical power evaluation methods and includes consideration of the operating domain and manufacturing uncertainties and a conservative core power distribution as inputs. The operating limit MCPR is established such that the transient CPR for the dynamic anticipated operational occurrences and quasi steady-state anticipated operational occurrences are included in the evaluation. Thus, the operating limit MCPR is specified to maintain an adequate margin to boiling transition.
The MCPR operating limit is the maximum of (a) the applicable exposure dependent, full power and full flow MCPR limit, (b) the applicable exposure and power dependent MCPR limit, and (c) the flow dependent MCPR limit as specified in the cycle-specific COLR. This stipulation ensures that the safety limit MCPR will not be violated throughout the CGS LDCN-10-004                                     15.0-9

COLUMBIA GENERATING STATION                            Amendment 63 FINAL SAFETY ANALYSIS REPORT                           December 2015 operating regime. Full power MCPR limits are specified to define operating limits at rated power and a range of flow conditions that support extended load line operation. Power dependent MCPR limits are specified to define operating limits at other than rated power conditions. A flow dependent MCPR limit is specified to define operating limits at other than rated flow conditions.
With implementation of ARTS, the APRM total peaking factor setdown requirement is eliminated and power-dependent LHGR limits are substituted to ensure adherence to the fuel thermal mechanical design bases. Flow dependent LHGR limits are added to ensure adherence to all fuel thermal mechanical design bases during recirculation flow increase events.
ELLLA operation extends the power and flow operating regime for CGS above the rated rod line for SLO and two-loop recirculation pump operation (TLO). MELLLA further extends the power and flow operating regime but only for TLO. The COLR defines the ELLLA boundary for SLO and MELLLA boundary for TLO. The cycle specific Supplemental Reload Licensing Report (Reference 15.0-1) documents the reload analyses.
The CGS cycle-specific COLR provides the average planar linear heat generation rate (APLHGR) limits, the MCPR limits, and the linear heat generation rate (LHGR) limits as required by the Technical Specifications.
15.0.3.3.1        Mathematical Model Unless otherwise stated in the Mathematical Model description for the event being discussed, the following mathematical model was used to perform the Chapter 15 transient analyses.
Transients are analyzed using the transient analysis models described in Reference 15.0-5.
The three-dimensional transient analysis model TRACG was used to analyze transients involving significant reactor pressurization (i.e., limiting events). The point-kinetics transient analysis model REDY and the one-dimensional transient analysis model ODYN were used for transients not involving significant reactor pressurization (i.e., non-limiting events). The transient analysis model determines the transient pressure, power, heat flux, and average core flow which are required as input to both the hot channel analysis and to the transient critical power methodology. The TRACG transient analysis model also calculates the transient peak reactor vessel pressure to demonstrate conformance to the reactor pressure vessel safety limit, which is based on the reactor pressure vessel design pressure.
TRACG is a best-estimate code for analysis of BWR transients (Reference 15.0-5). It is based on a multi-dimensional, two-fluid model for the reactor thermal-hydraulics, and a three-dimensional neutron kinetics model for the reactor core. TRACG has a modular structure and flexible geometry capability. It contains a set of basic thermal-hydraulic components, such as vessel, channel, pipe, and tee components which are used as the building blocks to construct the system simulation. In addition to the basic thermal-hydraulic component models, TRACG contains a set of component models for the recirculation pumps, jet pumps, fuel channels, LDCN-10-004, 15-011                           15.0-10

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                         December 2015 steam separators, and dryers. TRACG also contains a control system model capable of simulating major BWR control systems.
The input data to the transient analysis model come from two sources: (1) the plant model or base deck, and (2) the BWR three-dimensional simulator PANACEA. The plant model provides the necessary input data for the simulation of the plant, including the plant and control systems performance characteristics. The BWR three-dimensional simulator supplies the core state, the neutron kinetics cross sections, and other data necessary to characterize the reactor core.
The TRACG analysis process begins by performing channel grouping and selecting limiting (hot) channels from the PANACEA wrapup file. After updating the TRACG Basedeck with any cycle specific OPL-3 changes, a TRACG Steady-State Initialization case, restarting from the PANACEA wrapup, is then run to establish initial conditions for the subsequent transient case. The Steady-State Initialization includes key parameters such as core power, core flow, vessel steam flow, core inlet subcooling, reactor dome pressure, vessel narrow range water level, steamline pressure drop, and turbine control valve initial position. These TRACG calculated steady state parameters are then compared with the corresponding PANACEA heat balance value or the cycle specific OPL-3 form to confirm that the steady state results are within methodology defined acceptance criteria. A TRACG Null Transient case is then run to establish the TRACG flux convergence criterion. Finally, the TRACG transient cases are run to calculate the limiting (hot) channel CPR/ICPR, pressure margins, and Limiting (hot) channel power and nodal integrated powers.
The GESAM SLMCPR calculational process, which includes the GEXL correlation, is then used to calculate the OLMCPR, based on plant specific transient bias and uncertainty inputs, the cycle specific SLMCPR, and the TRACG calculated CPR/ICPR. The limiting hot channel power and nodal integrated powers are then normalized and used for input to perform the plant/cycle/event specific fuel rod thermal/mechanical evaluation, which is a separate calculation.
The above mathematical models describe the models used in the introduction of GNF2 fuel.
Cycle specific analyses are performed using vendor specific models for the vendor supplying the reload fuel for the current cycle as described elsewhere in this chapter.
15.0.3.3.2      Input Parameters and Initial Conditions for Analyzed Events This section discusses the important input parameters used in the analysis for the event discussed. In some cases, the discussion references Table 15.0-2 (or 2A or 2B).
15.0.3.3.3      Consideration of Uncertainties Except for total core flow and TIP reading, the uncertainties used in the statistical analysis to determine the MCPR fuel cladding integrity safety limit are not dependent on whether coolant flow is provided by one or two recirculation pumps. Uncertainties used in the two-loop LDCN-15-011                                   15.0-11

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                         December 2015 operation analysis are documented in the FSAR. A 6% core flow measurement uncertainty has been established for single loop operation (compared to 2.5% for two-loop operation). This value conservatively reflects the one standard deviation (one sigma) accuracy of the core flow measurement system documented in Reference 15.0-2. In SLO, measurement and prediction uncertainties for radial power distribution and axial power distribution also increase. In the current methodology, axial power uncertainty is not an important parameter. The net effect of these revised uncertainties is an incremental increase in the required MCPR fuel cladding integrity safety limit. The MCPR safety limit for SLO is given in the cycle specific COLR.
15.0.3.3.3.1 Core Flow Uncertainty Analysis The uncertainty analysis procedure used to establish the core flow uncertainty for one-pump operation is essentially the same as for two-pump operation, with some exceptions. The core flow uncertainty analysis is described in Reference 15.0-2. The analysis of one-pump core flow uncertainty is summarized below.
For SLO, the total core flow can be expressed as follows (see Figure 15.0-2):
WC  WA  WI where:
WC  total core flow WA  active loop flow, and WI  inactive loop (true) flow.
By applying the propagation of errors method to the above equation, the variance of the total flow uncertainty can be approximated by:
2                          2 2W   2Wsys 1   2 W          a    2            C2 C
1  a A rand 1  a WI rand where:
W         = uncertainty of total core flow; C
Wsys     = uncertainty systematic to both loops; W         = random uncertainty of active loop only; A rand 15.0-12

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                       December 2015 WI         = random uncertainty of inactive loop only; rand C           = uncertainty of C coefficient; and a       = ratio of inactive loop flow (WI) to active loop flow (WA).
From an uncertainty analysis, the conservative, bounding values of Wsys ,  W       ,  WI      , and  C A rand        rand are 1.6%, 2.6%, 3.5% and 2.8% respectively. Based on the above uncertainties and a bounding value of 0.36* for a, the variance of the total flow uncertainty is approximately:
2                         2 2W  1.6 C
2           1 1  0.36 2.6 2 1  0.36 0.36  3.5 2  2.8 2  5.0% 2 When the effect of 4.1% core bypass flow split uncertainty at 12% (bounding case) bypass flow fraction is added to the above total core flow uncertainty, the active coolant flow uncertainty is:
2 2                                       0.12  4.1% 2  51 active coolant   5.0%                                . % 2 2
1  0.12 which is less than the 6% core flow uncertainty assumed in the statistical analysis.
In summary, core flow during one-pump operation is measured in a conservative way and its uncertainty has been conservatively evaluated.
15.0.3.3.4         Results This section discusses the results, in terms of core and system performance, of the event analyzed. The COLR provides operating limits that are the results of analytical evaluations that impact core operating parameters for the current cycle. In addition, critical parameters for the complete set of transients analyzed are shown in Table 15.0-1. From the data in Table 15.0-1, an evaluation of the limiting event for that particular category and parameter can This flow split ratio varies from about 0.13 to 0.36. The 0.36 value is a conservative bounding value. The analytical expected value of the flow split ratio for CGS is 0.23.
15.0-13

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                         December 2015 be made. The limiting events are reanalyzed for the current operating cycle. Table 15.0-3 provides a summary of accidents that may have radiological consequences.
15.0.3.4       Barrier Performance This section addresses the performance of the RCPB and the containment system during transients and accidents.
During transients that occur with no release of coolant to the containment, only RCPB performance is considered. If release to the containment occurs as in the case of limiting faults, then challenges to the containment are evaluated as well.
Piping systems within the secondary containment structure (i.e., the reactor building) have been analyzed for pipe break effects including jet impingement, jet reaction, pipe whip, and subcompartment pressurization. Where necessary, these loads were included in the design of the structure to ensure that the secondary containment can perform its required functions as defined in Section 6.2.3.
15.0.3.5       Radiological Consequences This section addresses the radiological release consequences during the incidents of moderate frequency (anticipated operational transients), infrequent incidents (abnormal operational transients), and limiting faults (design basis accidents [DBA]) events. For all events where consequences are limiting a detailed quantitative evaluation is presented. For nonlimiting events, a qualitative evaluation is presented or the results are referenced from a more limiting or enveloping case or event.
For limiting faults (DBA), conservative assumptions considered to be acceptable to the NRC for the purpose of worst case bounding of the event and determining the adequacy of the plant design to meet 10 CFR 50.67 requirements are assumed. This is referred to as the design basis analysis.
The atmospheric dispersion coefficients are presented in Tables 15.0-4 and 15.0-5. Reference will be made to these tables in the discussion of the analyses.
15.

==0.4      REFERENCES==

15.0-1          Supplemental Reload Licensing Report for Columbia (most recent version referenced in COLR).
15.0-2          General Electric Company, General Electric BWR Thermal Analysis Basis (GETAB); Data, Correlation, and Design Application, NEDO-10958-A, January 1977.
15.0-14

COLUMBIA GENERATING STATION                      Amendment 63 FINAL SAFETY ANALYSIS REPORT                     December 2015 15.0-3      GE Nuclear Energy, WNP-2 Power Uprate Transient Analysis Task Report, GE-NE-208-08-0393, Revision 0, September 1993 (Proprietary).
15.0-4      GE-Hitachi Report, Evaluation of Steam Flow Induced Error Impact on the L3 Setpoint Analysis Limit, GEH-NE-0000-0077-4603, December 2007.
15.0-5      General Electric Company, General Electric Standard Application for Reactor Fuel, NEDE-24011-P-A, and supplement for United States, NEDE-24011-P-A-US (most recent approved version referenced in COLR).
LDCN-15-011                             15.0-15

LDCN-15-011 Table 15.0-1 Results Summary of Transient Events Applicable to Columbia Generating Stationa Maximum     Maximum    Maximum      Maximum Core Maximum          Dome        Vessel    Steam Line   Average Surface Paragraph    Figure                                                   Neutron Flux     Pressure    Pressure    Pressure    Heat Flux (% of                Frequency I.D.       I.D.                     Description                     (%NBR)           (psig)      (psig)       (psig)        Initial)       DCPRb,c,e   Category 15.1                   DECREASE IN REACTOR COOLANT TEMPERATURE COLUMBIA GENERATING STATION 15.1.1                 Loss of Feedwater Heating, Manual Flow                                                                                 0.11           (d)
Control 15.1.2       15.1-1    Feedwater Controller Failure, Max Demand        314            1183         1210                                       0.30k          (d) 15.1.3       15.1-2    Pressure Regulator Fail-Open                    131            1151         1172        1151         100               <0.01 15.1.4                 Inadvertent Opening of Safety or Relief Valve   104            1020         1061        1012         100               <0.01          (d) 15.1.6                 RHR Shutdown Cooling Malfunction                See text                                                                              (d)
Decreasing Temperature 15.0-17 FINAL SAFETY ANALYSIS REPORT 15.2                   INCREASE IN REACTOR PRESSURE 15.2.1                 Pressure Regulator Fail-Closed                  163            1188         1220        1187         106               n/a            (d) 15.2.2       15.2-1    Generator, Load Rejection, Bypass-Onf           See text                                                                              (d) k 15.2.2       15.2-2    Generator Load Rejection, Bypass-Off            330            1244         1270                                       0.32           (d) 15.2.3       15.2-3    Turbine Trip, Bypass-Onf                        See text                                                                              (d) 15.2.3       15.2-4    Turbine Trip, Bypass-Off                        278            1238         1260        1235         111               0.30           (d) 15.2.4       15.2-5    Inadvertent MSIV Closure                        206            1200         1234        1198         100               0.022          (d) 15.2.5       15.2-6    Loss of Condenser Vacuum                        256            1173         1199        1166         111               0.12           (d) 15.2.6       15.2-7    Loss of Auxiliary Power Transformers            106h           1169         1185        1166         100               <0.01          (d) 15.2.6       15.2-8    Loss of All Grid Connections                    196            1173         1196        1166         106               0.079          (d) 15.2.7       15.2-9    Loss of all Feedwater Flow                      106h           1142         1152        1142         100               <0.01          (d) 15.2.8                 Feedwater Piping Break                          See Section 15.6.6 15.2.9                 Failure of RHR Shutdown Cooling                 See text Amendment 63 December 2015

LDCN-15-011 Table 15.0-1 Results Summary of Transient Events Applicable to Columbia Generating Stationa (Continued)
Maximum         Maximum          Maximum       Maximum Core Maximum           Dome            Vessel          Steam Line    Average Surface Paragraph    Figure                                                 Neutron Flux      Pressure        Pressure          Pressure     Heat Flux (% of                 Frequency I.D.       I.D.                      Description                  (%NBR)            (psig)          (psig)             (psig)         Initial)        DCPRb,c,e   Category 15.3                   DECREASE IN REACTOR COOLANT SYSTEM FLOW RATE 15.3.1       15.3-1    Trip of One Recirculation Pump Motor          106h            1020             1059              1012         100                <0.01           (d)
COLUMBIA GENERATING STATION 15.3.1       15.3-2    Trip of Both Recirculation Pump Motors        106h            1077             1088              1076         100                <0.01           (d) 15.3.2       15.3-3    Speed Decrease of One Main Recirc Motor       106h            1020             1059              1012         100                <0.01           (d) h 15.3.2       15.3-4    Speed Decrease of Two Main Recirc Motors      106             1061             1072              1061         100                <0.01           (d) 15.3.3       15.3-5    Seizure of One Recirculation Pump             106h            1099             1110              1098         100                <0.01            (i) 15.3.4                 Recirc Pump Shaft Break                       See 15.3.3 15.4                   REACTIVITY AND POWER DISTRIBUTION ANOMALIES 15.0-18 FINAL SAFETY ANALYSIS REPORT 15.4.1.1               RWE - Refueling                               See text                                                                                            (j) 15.4.1.2               RWE - Startup                                 See text                                                                                            (j) 15.4.2                 RWE - At Power                                See text                                                                                           (d) 15.4.3                 Control Rod Misoperation                      See Sections 15.4.1 and 15.4.2 15.4.4       15.4-1    Abnormal Startup of Idle Recirculation Loop   124c            1004             1026              998          190                0.53            (d) 15.4.5       15.4-2    Speed Increase of One Main Recirc Motor       136c            990              1009              986          127                0.15            (d) 15.4.5                 Speed Increase of Both Main Recirc Motors     153c            1006             1033              1001         149                0.27            (d) 15.4.7                 Misplaced Bundle Accident                     See text                                                                                            (j) 15.4.9                 Rod Drop Accident                                                                                                                                 (i) 15.5                   INCREASE IN REACTOR COOLANT INVENTORY 15.5.1       15.5-1    Inadvertent HPCS Pump Startf                  102h            1020             1052              1012         100                <0.01g          (d) 15.5.3                 BWR Transients                                See appropriate events in Sections 15.1 and 15.2 a                                                                                                                                                                                     Amendment 63 Results reflect GE14 fuel introduction, and updates from GNF2 introduction some of which are dependent on fuel design and core loading pattern.
December 2015 Compliance with the event acceptance criteria is demonstrated by cycle-dependent analysis of potentially limiting events just prior to the operation of that cycle. The results are reported in the Supplemental Reload Licensing Report (Reference 15.0-1).

LDCN-15-011 Table 15.0-1 Results Summary of Transient Events Applicable to Columbia Generating Stationa (Continued) b MCPR operating limits are based on the delta-CPR (DCPR) results from the limiting transient event and the MCPR safety limit defined in the Technical Specifications.
c Option B DCPR results are reported.
d Moderate frequency.
COLUMBIA GENERATING STATION e
Unless otherwise noted, this value is only for GE14 fuel.
f Non-limiting event under power uprate conditions (event not reanalyzed).
g ODYN results without the adjustment factors delineated in the ODYN Report NEDO-24154, NEDC-24154P.
h No increase from initial value.
15.0-19 FINAL SAFETY ANALYSIS REPORT i
Limiting fault.
j Infrequent incident.
k This value is only for the more limiting GNF2 fuel and does not include plant specific TRACG bias and uncertainty.
Amendment 63 December 2015

COLUMBIA GENERATING STATION                  Amendment 63 FINAL SAFETY ANALYSIS REPORT                 December 2015 Table 15.0-1A Summary of Transient Peak Value Results Single-Loop Operation Maximum  Maximum Neutron  System Paragraph/                                             Flux   Pressure   Frequency Figure                    Description              (% NBR)    (psig)   Category Initial condition                          75      1020        N/A 15.1.2/      Feedwater flow controller failure          89      1118        (a) 15.1-3       (maximum demand) uprated power 15.2.2       Generator load rejection - uprated        131      1184        (a) power 15.3.3/      Seizure of active recirculation pump       75      1017        (b) 15.3-6 a
Moderate frequency incident.
b Limiting fault.
LDCN-15-011                                   15.0-20

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 Table 15.0-2 Input Parameters and Initial Conditions for Transients REDY (ASD Events)    REDYa            ODYN
: 1. Thermal power level, MWt Licensed value                               3486           3323           3486 Analysis value                               3702           3464           3629
: 2. Steam flow, lbs/hr analysis value                16.09 x 106    14.98 x 106    15.73 x 106
: 3. Core flow, lbs/hr                                108.5 x 106    108.36 x 106   95.5-115.0 x 106
: 4. FW flow rate, lb/sec analysis value              4471           4161           4362
: 5. Feedwater temperature, &deg;F                        426            424            426
: 6. Vessel dome pressure, psig                       1020           1020           1020
: 7. Vessel core pressure, psig                       1031           1031           1031
: 8. Turbine bypass capacity, %NBR                    22.7           25             22.7
: 9. Core coolant inlet enthalpy, Btu/lb              528.3          529.3          529.6
: 10. Turbine inlet pressure, psig                     992            975            997
: 11. Fuel lattice                                     8 x 8/9 x 9    8x8            Simulated 8x8/9x9
: 12. Core average fuel cladding gap conductance, Btu/sec-ft2-&deg;F                                   0.3608         0.1667         Fuel specific
: 13. Core leakage flow, %                             10.20          11.84          Cycle specific
: 14. Required MCPR operating limit                    (b)            1.24           (c)
: 15. MCPR safety limit                                (b)            1.06           (c)
: 16. Doppler coefficient (-)&#xa2;/&deg; Nominal EOC-1                                0.311          0.227          (d)
Analysis data ASD events
: 1. Increase power                            0.295          0.215
: 2. Decrease power                            0.327
: 17. Void coefficient (-)&#xa2;/% Rated Nominal EOC-1                                               7.48           (d)
Analysis data for power increase events      15.93          12.70          (d)
Analysis data for power decrease events      12.10          7.065          (d)
: 18. Core average rated void fraction,
    % (Steady state)                                 41.24          41.32          43.1
: 19. Scram reactivity, $k analysis data               Figure 15.0-1  Figure 15.0-1  (d)
: 20. Control rod drive speed, position versus time    Figure 15.0-1  Figure 15.0-1  Figure 15.0-1
: 21. Jet pump ratio, M                                2.36           2.41           2.39 15.0-21

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 Table 15.0-2 Input Parameters and Initial Conditions for Transients (Continued)
REDY (ASD Events)       REDYa         ODYN
: 22. Safety/relief valve capacity,% NBR safety valve capacity @ 1241 psig                 108.6             111.5         108.6 Relief valve capacity @ setpoint values in item 25 of this table                             @ 1121 psig 98.3  101.8          98.3
                                                         @ 1131 psig 99.1  102.8          99.1
                                                         @ 1141 psig 100.0 103.7         100
                                                         @ 1151 psig 100.9 104.6         100.9
                                                         @ 1161 psig 101.7 105.5         101.7 Manufacturer                                                        Crosby        Crosby Quantity installed                                                  18            18
: 23. Relief function delay, sec                        0.4               0.4           0.4
: 24. Relief function response, sec                     0.15              0.1           0.15
: 25. Setpoints for safety/relief valves Safety function, psig                        1200, 1210        1177, 1187,   1200, 1210 1221, 1231        1197, 1207,   1221, 1231 1241              1217          1241 Relief function, psig                        1121, 1131        1091, 1101,   1121, 1131 1141, 1151        1111, 1121,   1141, 1151 1161              1131          1161
: 26. Number of valve groupings simulated Safety function, number                                        5             5 Relief function, number                                        5             5
: 27. High flux trip analysis setpoint (123 x 1.041),% NBR                               128.0             126.20        128e
: 28. High pressure scram setpoint, psig                1086              1071          1086
: 29. Vessel level trips, inches with respect to dryer skirt bottom Level 8 - (L8), in.                          59.5              55.5          59.5 Level 4 - (L4), in.                                            31.5          30 Level 3 - (L3), in.                          7.5i              12.5i         (f)
Level 2 - (L2), in.                                            (-38)         (f)
: 30. APRM thermal trip analysis setpoint (117 x 1.041)% NBR @ 100% core flow               121.8             122.030       121.8e
: 31. Recirculation pump trip delay, sec                0.190             0.140         0.190
: 32. Recirculation pump trip inertia time constant for analysis, sec                                     6g                6g            6g
: 33. RPS response time delay                           (h)               (h)           (h)
LDCN-10-003                                         15.0-22

COLUMBIA GENERATING STATION                        Amendment 61 FINAL SAFETY ANALYSIS REPORT                       December 2011 Table 15.0-2 Input Parameters and Initial Conditions for Transients (Continued) a REDY values reflect the pre-uprate initial conditions. Only limiting events were analyzed for power uprate conditions with FCV.
b See COLR.
c Not applicable to reload 7/cycle 8 simulation.
d ODYN values are calculated within the code.
e The thermal multiplier (1.041 = 3629/3486) is used to give a conservative margin that is proportional to the core power.
f Parameter not used in the analysis.
g The inertia time constant is defined by the expression:
2  JO n t
g TO where t    = inertia time constant (sec)
Jo   = pump motor inertia (lb-ft2) n    = rated pump speed (rps) g    = gravitational constant (ft/sec2)
To   = pump shaft torque (lb-ft) h The maximum overall response time as addressed in the LCS is utilized for each scram encountered in the Chapter 15 events.
i The impact of steam flow induced error on the analytical limit does not impact event descriptions or conclusions (Reference 15.0-4).
LDCN-10-003                                   15.0-23

COLUMBIA GENERATING STATION                       Amendment 61 FINAL SAFETY ANALYSIS REPORT                     December 2011 Table 15.0-2A Input Parameters and Initial Conditions for Transients and Accidents for Single-Loop Operation Original Rated Power         Uprated Power
: 1. Thermal power analysis value (MWt)            2596.9             2615
: 2. Flow Steam (1b/hr)                            10.79 x 106        10.76 x 106 Core (lb/hr)                             59.0 x 106         61.85 x 106 Core bypass (lb/hr)                      5.88 x 106         6.22 x 106 Feedwater (lb/hr)                        10.79 x 106        10.76 x 106 Turbine bypass (lb/hr)                   5.88 x 106         N/A Turbine bypass (% rated)                 N/A                23%
: 3. Core Inlet Enthalpy (Btu/lb)                  510.8              513.7
: 4. Pressure Vessel dome (psia)                       1020               1008 Vessel core (psia)                       1029.7             1017.7 Turbine inlet (psia)a                    960.5              1000
: 5. Jet pump ratio (M)                            3.2                3.4
: 6. Safety/relief valve capacity
        % NBR @ 1,164 psig                       107.1              N/A Manufacturer                             Crosby             Crosby Quantity installed                       18                 18
        % NBR @ 1241 psig                        N/A                108.6
: 7. Relief function Delay (sec)                              0.4                0.4 Response (sec)                           0.1                0.15 15.0-24

COLUMBIA GENERATING STATION                        Amendment 61 FINAL SAFETY ANALYSIS REPORT                       December 2011 Table 15.0-2A Input Parameters and Initial Conditions for Transients and Accidents for Single-Loop Operation (Continued)
Original Rated Power           Uprated Power
: 8. Setpoints for safety/relief valves Safety function (psig)                   1177, 1187, 1197, 1200, 1210, 1221, 1207, 1217          1231, 1241 Relief function (psig)                   1106, 1116, 1126, 1121, 1131, 1141, 1136, 1146          1151, 1161
: 9. Number of valve groupings simulated Safety function (number)                 5                   5 Relief function (number)                 5                   5
: 10. Setpoints High flux trip analysis (1.21 x 1.043)   126.2               128
(% NBR)
High pressure scram (psig)               1071                1086 APRM thermal trip (% NBR @               122.03              121.8 100% core flow)
: 11. Vessel level trips (ft above instrument zero)
Level 8 - (L8) (ft)                      4.542 Level 4 - (L4) (ft)                      2.625 Level 3 - (L3) (ft)                      1.083b Level 2 - (L2) (ft)                      (-)4.167
: 12. RPT delay (sec)                               0.19                0.19 2
13a. RPT inertia for analysis (lb/ft )              24,500              N/A 13b. RPT inertia time constant (sec)                N/A                 6 a
Pressure specified at rated power condition. Off-rated power pressure drop is calculated by transient analysis code.
b The impact of steam flow induced error on the analytical limit does not impact event descriptions or conclusions (Reference 15.0-4).
LDCN-10-003                                   15.0-25

COLUMBIA GENERATING STATION                   Amendment 63 FINAL SAFETY ANALYSIS REPORT                 December 2015 Table 15.0-2B Input Parameters and Initial Conditions for ARTS/MELLLA and GNF Reload Transient Analyses Parameter                                  Value
: 1. Thermal power level, MWt                                             3486
: 2. Steam flow, lbs/hr analysis value                                 15.01 x 106
: 3. Core flow, lbs/hr                                             87.6 - 115.0 x 106
: 4. FW flow rate, lb/sec analysis value                                 4161.6
: 5. Feedwater temperature, &deg;F                                            421.2
: 6. Vessel dome pressure, psig                                           1020
: 7. Vessel core pressure, psig                                           1032
: 8. Turbine bypass capacity, %NBR                                        23.75
: 9. Core coolant inlet enthalpy, Btu/lb (rated flow)                     527.2
: 10. Turbine inlet pressure, psig                                          990
: 11. Fuel lattice                                                  10 x 10 mixed core
: 12. Required MCPR operating limit                                     See COLR
: 13. MCPR safety limit                                                 See COLR
: 14. Control rod drive speed, position versus timea
: 15. Jet pump ratio, M                                                    2.285
: 16. Safety/relief valve capacity, % NBR safety valve capacity      See Table 5.2-3 Manufacturer                                                 Crosby Quantity installed                                              18
: 17. Relief valve function delay, sec                                                      0.4 response, sec                                                  0.15
: 18. Safety valve function delay, sec                                                      0.0 response, sec                                                  0.3 LDCN-10-004                                15.0-26

COLUMBIA GENERATING STATION                        Amendment 61 FINAL SAFETY ANALYSIS REPORT                       December 2011 Table 15.0-2B Input Parameters and Initial Conditions for GNF Reload Transient (Continued)
Parameter                                         Value
: 19. Setpoints for safety/relief valves                               # in Group     Setpoint Safety function, psig                                          2b           1200 4b           1210 4            1221 4            1231 4            1241 Relief function, psig                                          2b           1156 4b           1166 4            1176 4            1186 4            1196
: 20. Number of valve groupings simulated Safety function, number (actual/credited)                           5/3 Relief function, number (actual/credited)                           5/3
: 21. High flux trip analysis setpoint,% NBR                                    123.0
: 22. High pressure scram setpoint, psig                                        1086
: 23. Vessel level trips, inches with respect to instrument zero Level 8 - (L8), in.                                                  59.5 Level 4 - (L4), in.                                                   30 Level 3 - (L3), in.                                                  2.5c Level 2 - (L2), in.                                            -90 LOCA
                                                                           -70 Non LOCA
: 24. APRM thermal trip analysis setpoint                                    Not credited
: 25. Recirculation pump trip delay, sec                                        0.200
: 26. RPS response time delay                                                 See LCS a
See Section 4.6.1.1.2.5.3.
b Valve group function not credited in safety analyses.
c This allows the correction due to steam flow induced error (Reference 15.0-4).
LDCN-10-003                                  15.0-27

COLUMBIA GENERATING STATION              Amendment 61 FINAL SAFETY ANALYSIS REPORT             December 2011 Table 15.0-3 Summary of Accidents Paragraph                                               Failed Fuel I.D.                            Title               Calculated Value 15.3.3    Seizure of one recirculation pump                None 15.3.4    Recirculation pump shaft break                   None 15.4.9    Rod drop accident                               850 rods 15.6.2    Instrument line break                            None 15.6.4    Steam system pipe break outside containment      None 15.6.5    Loss-of-coolant accident within RCPB             100%
15.6.6    Feedwater line break                             None 15.7.1    Main condenser gas treatment system failure       N/A 15.7.3    Liquid radwaste tank failure                      N/A 15.7.4    Fuel handling accident                          250 rods 15.8      Anticipated transients without scram             None 15.0-28

COLUMBIA GENERATING STATION                  Amendment 61 FINAL SAFETY ANALYSIS REPORT                 December 2011 Table 15.0-4
       /Q (s/m3) values for the EAB and LPZ Time Period     EAB /Q (s/m3)      LPZ /Q (s/m3) 0 - 2 hrs         1.81 E-4           4.95 E-5 2 - 8 hrs                            4.95 E-5 8 - 24 hrs                            3.69 E-5 1-4d                                1.95 E-5 4 - 30 d                             7.81 E-6 15.0-29

COLUMBIA GENERATING STATION                   Amendment 61 FINAL SAFETY ANALYSIS REPORT                 December 2011 Table 15.0-5 Control Room Atmospheric Dispersion Factors (sec/m3)
Hours         Turbine    Secondary   SGT System Building   Containment    Release Filtered Intake Release Path      0-2            8.81E-4     2.82E-4      1.43E-4 2-8            3.75E-4     2.17E-4      1.05E-4 8 - 24         1.93E-4     8.77E-5      4.14E-5 24 - 96        1.50E-4     7.42E-5      3.52E-5 96 - 720       1.44E-4     6.40E-5      3.03E-5 Unfiltered Intake Release Path    0-2            4.70E-3     7.02E-4      6.95E-4 2-8            2.00E-3     3.19E-4      3.36E-4 8 - 24         1.03E-3     1.30E-4      1.28E-4 24 - 96        8.01E-4     1.05E-4      9.72E-5 96 - 720       7.69E-4     9.00E-5      7.69E-5 15.0-30

Amendment 53 November 1998 1.0                                                                                              40
                                                                                                                 $40.21
                                                                                                                 $37.05 End of Cycle 1 Scram Curve 0.8 Control Fraction (Per Unit Insertion) 67B Scram Rod Drive                                                                    30 Scram Reactivity ($)
0.6 20 0.4 Scram Curve Used in Analysis                           10 0.2 0                                                                                               0 0        1         2         3         4            5          6          7            8 Time (sec) 67 Scram Analysis EOC 1 Scram Curve Revised Portion of Scram Speed Used in ODYN Analysis Scram Position and Reactivity Columbia Generating Station                                         Characteristics Final Safety Analysis Report Draw. No. 900547.61       Rev.       Figure   15.0-1 Form No. 960690

Amendment 58 December 2005 Core WC WA WI WC - Total Core Flow WA - Active Loop Flow W - Inactive Loop Flow Illustration of Single Recirculation Loop Columbia Generating Station                            Operation Flows Final Safety Analysis Report Draw. No. 910402.42        Rev.        Figure 15.0-2 Form No. 960690FH LDCN-05-019

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 15.1    DECREASE IN REACTOR COOLANT TEMPERATURE 15.1.1      LOSS OF FEEDWATER HEATING 15.1.1.1       Identification of Causes and Frequency Classification 15.1.1.1.1      Identification of Causes A feedwater heater can be lost in at least two ways:
: a.      Steam extraction line to heater is closed, and
: b.      Steam is bypassed around heater.
The first case produces a gradual cooling of the feedwater. In the second case, the steam bypasses the heater and no heating of that feedwater occurs. In either case, the reactor vessel receives cooler feedwater. The maximum number of feedwater heaters that can be tripped or bypassed by a single event represents the most severe transient for analysis considerations.
This event has been conservatively estimated to incur a loss of up to 100&deg;F of the feedwater heating capability of the plant and causes an increase in core inlet subcooling. This increases core power due to the negative void reactivity coefficient.
15.1.1.1.2      Frequency Classification This event is considered to be an incident of moderate frequency and is analyzed under worst case conditions of a 100&deg;F loss at full power.
15.1.1.2       Sequence of Events and Systems Operation The loss of feedwater heating leads to a gradual decrease in the temperature of the feedwater entering the reactor vessel. The decrease in feedwater temperature results in an increase in the core inlet subcooling which collapses voids, and increases the core average power. The gradual power change allows fuel thermal response to maintain pace with the increase in neutron flux. For this analysis, it was assumed that the initial feedwater temperature dropped 100&deg;F.
In establishing the expected sequence of events and simulating the plant performance, it was assumed that normal functioning occurred in the plant instrumentation and controls, plant protection, and reactor protection systems. Engineered safety feature (ESF) system initiation is not anticipated or required to prevent or mitigate the transient.
The Average Power Range Monitor (APRM) Simulated Thermal Power trip setpoint provides protection against transients such as the Loss of Feedwater Heating where thermal power increases slowly. While the sequence of events may produce sufficiently high LDCN-10-004                                   15.1-1

COLUMBIA GENERATING STATION                         Amendment 60 FINAL SAFETY ANALYSIS REPORT                        December 2009 flux levels to initiate an APRM reactor protection system trip, no credit is taken for a reactor trip in the analysis of the event. A description of the APRM system and operation is provided in Sections 7.2.1.1.1.2 and 7.6.1.4.3.
15.1.1.2.1      The Effect of Single Failures and Operator Errors The loss of feedwater heating generally leads to an increase in reactor power level. The APRM system is the mitigating system and is designed to be single failure proof. Therefore, single failures are not expected to result in a more severe event than analyzed.
15.1.1.3       Core and System Performance 15.1.1.3.1      Mathematical Model The analytical dynamic behavior has been determined using the steady state boiling water reactor (BWR) simulator code PANACEA (Reference 15.1-2). This code does not provide plots of the dynamic behavior of basic parameters as a function of time nor does it provide information for a sequence of events table. Therefore, no figures or tables are available.
Reference 15.1-6 approves the use of PANACEA for modeling the Loss of Feedwater Heating event.
The loss of feedwater heating (LFWH) event analysis supports an assumed 100&deg;F decrease in the feedwater temperature. The result is an increase in core inlet subcooling, which collapses voids, thereby, increasing the core power and shifting the axial power distribution toward the bottom of the core. As a result of the axial power shift and increased core power, voids begin to build up at the bottom of the core, acting as negative feedback to the void collapse process.
The negative feedback moderates the core power increase. The PANACEA code is used to determine the change in minimum critical power ratio (MCPR) during the event. Analyses were performed for a range of cycle exposures to ensure that appropriate limits are set.
Although there is a substantial increase in core thermal power during the event, the increase in steam flow is much less because a large part of the added power is used to overcome the increase in inlet subcooling. The increase in steam flow is accommodated by the pressure control system by the turbine control (governor) valves or the turbine bypass valves, so no pressurization occurs (Reference 15.1-3).
15.1.1.3.2      Input Parameters and Initial Conditions These analyses have been performed, unless otherwise noted, with plant conditions tabulated in Table 15.0-2B.
LDCN-08-035                                    15.1-2

COLUMBIA GENERATING STATION                          Amendment 60 FINAL SAFETY ANALYSIS REPORT                         December 2009 15.1.1.3.3       Results The LFWH transient is analyzed for each reload core to quantify the reduction in thermal margins. The results of the analysis are provided in the cycle specific Supplemental Reload Licensing Report (Reference 15.1-3).
15.1.1.3.4       Considerations of Uncertainties Factors such as exposure and magnitude of feedwater temperature change are assumed to be at the worst configuration so that any deviations seen in the actual plant operation reduce the severity of the event.
15.1.1.4       Barrier Performance The consequences of this event do not result in any temperature or pressure transient in excess of the criteria for which the fuel, pressure vessel, or containment are designed. Therefore, barrier integrity and function is maintained.
15.1.1.5       Radiological Consequences Since this event does not result in any additional fuel failures or any release of primary coolant to either the secondary containment or to the environment, there are no radiological consequences associated with this event.
15.1.2      FEEDWATER CONTROLLER FAILURE - MAXIMUM DEMAND 15.1.2.1       Identification of Causes and Frequency Classification 15.1.2.1.1       Identification of Causes This event is postulated on the basis of a single failure of a control device, specifically one that can directly cause an increase in coolant inventory by increasing the feedwater flow. The most severe applicable event is a feedwater controller failure (FWCF) during maximum flow demand. The feedwater controller is forced to its upper limit at the beginning of the event.
The event is evaluated for both single and two reactor recirculation loop operations. Because the two-loop operation event is bounding, the core performance analysis is limited to the feedwater controller failure during two-loop operation. However, the MCPR operating limit for single loop operation (SLO) is obtained by adding the CPR from two-loop operation to the MCPR safety limit (SLMCPR) for SLO.
15.1.2.1.2       Frequency Classification This event is considered to be an incident of moderate frequency.
LDCN-08-035                                    15.1-3

COLUMBIA GENERATING STATION                            Amendment 59 FINAL SAFETY ANALYSIS REPORT                           December 2007 15.1.2.2        Sequence of Events and Systems Operation The increase in feedwater flow, due to a failure of the feedwater control system to maximum demand, results in an increase in the water level and a decrease in the coolant temperature at the core inlet. The increase in core inlet subcooling causes an increase in core power. As the feedwater flow continues at maximum demand, the water level continues to rise and eventually reaches the high water level trip setpoint. The initial water level is conservatively assumed to be at the low level normal operating range of 30 inches above instrument zero to delay the high-level trip and maximize the core inlet subcooling that results from the FWCF. The high water level trip causes the turbine throttle (stop) valves to close in order to prevent damage to the turbine from excessive liquid inventory in the steam line. The valve closures create a compression wave that travels to the core causing a void collapse and subsequent rapid power excursion. In addition to the turbine throttle valve closure, the turbine governor valves also close in the fast closure mode. The closure of the governor (control) turbine valves initiates a reactor scram and a recirculation pump trip. Because of the partially opened initial position of the governor valves, they will close faster than the throttle valves and initiate the pressurization portion of the event. The turbine bypass valves are assumed operable and provide some pressure relief. The core power excursion is mitigated in part by the pressure relief, but the primary mechanisms for termination of the event are reactor scram and revoiding of the core.
The high-pressure core spray (HPCS) system and reactor core isolation cooling (RCIC) system initiate on a low reactor water level (L2) to maintain long-term water level control following tripping of feedwater pumps. The analysis of this event assumes normal functioning of plant instrumentation and controls, plant protection and reactor protection systems.
Table 15.1-1 lists the sequence of events for Figure 15.1-1. The figure shows the changes in variables during this transient.
15.1.2.2.1       Sequence of Events and Systems Operation - Single Loop Operation The simulated feedwater controller transient is shown in Figure 15.1-3 for the case of 75% power, 57% core flow. The high-water level turbine trip and feedwater pump trip are initiated at approximately 8.4 sec. A scram occurs simultaneously with the turbine trip and limits the neutron flux peak and fuel thermal transient so no fuel damage occurs.
Table 15.1-1A lists the sequence of events for Figure 15.1-3. The figures show the changes in important variables during this transient.
Identification of Operator Actions
: a.      Observe high feedwater pump trip has terminated the failure event, 15.1-4

COLUMBIA GENERATING STATION                            Amendment 63 FINAL SAFETY ANALYSIS REPORT                           December 2015
: b.       Switch the feedwater controller from auto to manual control to try to regain a correct output signal, and
: c.       Conduct follow-up assessment.
15.1.2.2.2      The Effect of Single Failures and Operator Errors The first sensed event to initiate corrective action to the transient is the vessel high water level (L8) trip. Multiple level sensors are used to sense and detect when the water level reaches the L8 setpoint. At this point in the logic, a single failure will not initiate or prevent a turbine trip signal. Turbine trip signal transmission, however, is not built to single failure criterion. The result of a failure at this point would have the effect of delaying, but not impacting, the pressurization signature.
Scram trip signals from the turbine are designed such that a single failure will neither initiate nor impede a reactor scram trip initiation.
15.1.2.3        Core and System Performance 15.1.2.3.1       Mathematical Model The predicted dynamic behavior has been determined using a computer simulated, analytical model of a direct-cycle BWR. This model is described in detail in Reference 15.1-3. Results from the two-loop operation bound the SLO event. Therefore, the discussion of core and system performance is limited to the description of the analysis for two-loop operation.
The nonlinear computer simulated analytical model is designed to predict associated transient behavior of the reactor. Some of the significant features of the model are the following:
: a.       An integrated three-dimensional neutron kinetics core model is assumed which includes a detailed description of hydraulic feedback effects, axial power shape changes, and reactivity feedbacks;
: b.       The fuel is represented by a separate channel grouping scheme based on the distinct characteristics of the fuel bundles in the core;
: c.       The four physical steam lines are modeled as two steam lines, one a single steam line and the other as three lumped steam lines. The modeled steam lines are connected with a tee component and another tee connected downstream which is connected to a valve component modeling the Turbine Bypass Valves (TBVs). Also associated with these steam lines are valve components modeling the inboard and outboard main steam isolation valves, the Safety/Relief valves, and the Turbine Control Valves. Pressure boundary condition components are LDCN-15-011                                       15.1-5

COLUMBIA GENERATING STATION                            Amendment 63 FINAL SAFETY ANALYSIS REPORT                           December 2015 connected to the downstream sides of the S/RVs, and the TBVs. A flow boundary condition component represents the steam mass flow rate through the TCVs. This mass flow rate is calculated by the TRACG control system logic.
The open area fraction of the S/RVs and TBVs is determined by the TRACG control system logic. TRACG control systems are used extensively in modeling plant component and system behavior.;
: d. The code is based on a multidimensional twofluid model for the reactor thermal hydraulics. The basic twophase, twofluid model consists of the volume and time averaged conservation equations for mass, momentum, and energy for each phase. Thus, the model does not assume thermal or mechanical equilibrium between the phases;
: e. A control system model capable of simulating major BWR controls systems, such as feedwater flow, recirculation flow, reactor water level, pressure, and load demand; and
: f. The ability to simulate necessary reactor protection system functions is provided.
15.1.2.3.2     Input Parameters and Initial Conditions These analyses have been performed with the plant conditions in Table 15.0-2B.
All rods out scram characteristics are assumed. The safety/relief valve (SRV) action is conservatively assumed to occur with higher than nominal setpoints. The transient is simulated by programming an upper limit failure in the feedwater system such that 139% feedwater flow occurs at the nominal reactor operating pressure of 1035 psia.
An increase in feedwater flow will cause a corresponding drop in feedwater temperature.
However, the relatively large time constant of the feedwater heaters (order of minutes) plus the flow transport time (10 sec from heaters to vessel and 3 sec from sparger to core) would preclude any effect of temperature reduction on the transient since the transient is essentially over in about 20 sec. Therefore, feedwater temperature is assumed to remain constant.
15.1.2.3.3     Results The simulated feedwater controller transient is shown in Figure 15.1-1. The high water level turbine trip and feedwater pump trip are initiated as stated in Table 15.1-1. Results reflect GNF2 fuel introduction, some of which are dependent on fuel design and core loading pattern.
Compliance with the event acceptance criteria is demonstrated by cycle-dependent analysis of potentially limiting events just prior to the operation of that cycle. The results are reported in the Supplemental Reload Licensing Report (Reference 15.1-3).
LDCN-15-011                                    15.1-6

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 Because the total change in feedwater flow is greatest from reduced power conditions, the feedwater controller failure (FWCF) transient was analyzed for several reduced power states.
The power dependent MCPR limits are established to protect the fuel during the FWCF event.
15.1.2.3.4       Consideration of Uncertainties All systems used for protection in this event were assumed to have the most conservative response characteristics. Therefore, actual plant behavior is expected to lead to a less severe transient.
15.1.2.4        Barrier Performance The consequences of this event do not result in any temperature or pressure transient in excess of the criteria for which the fuel, pressure vessel, or containment are designed. Therefore, barrier integrity and function is maintained.
15.1.2.5        Radiological Consequences The consequence of this event does not result in fuel failure. It does result in the discharge of normal coolant activity to the suppression pool by means of SRV operation, which is contained in the primary containment. This event does not result in an uncontrolled release to the environment, so the plant operator can choose to hold the activity in containment or discharge it when conditions permit. If purging of the containment is chosen, the release would be in accordance with established requirements.
15.1.3       PRESSURE REGULATOR FAILURE - OPEN 15.1.3.1        Identification of Causes and Frequency Classification 15.1.3.1.1       Identification of Causes The total steam flow rate to the main turbine resulting from a pressure regulator malfunction in the Digital Electro-Hydraulic (DEH) control system is limited by a maximum flow limiter imposed at the turbine controls. This limiter is set to limit maximum steam flow demand to approximately 130% NBR.
If the triple redundant DEH control system fails such that the turbine control (governor) valves fully open and the turbine bypass valves partially open, the maximum steam flow is established.
15.1.3.1.2       Frequency Classification This event is categorized as an incident of moderate frequency.
15.1-7

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 15.1.3.2       Sequence of Events and Systems Operation 15.1.3.2.1      Sequence of Events Table 15.1-2 lists the sequence of events for Figure 15.1-2. Figure 15.1-2 depicts how the high water level turbine trip and isolation valve closure stops vessel depressurization and produces a normal shutdown of the reactor.
15.1.3.2.2      Systems Operation Depressurization results in formation of voids in the reactor coolant and causes a decrease in reactor power almost immediately. In this simulation, the depressurization rate is large enough such that water level swells to the sensed level trip setpoint (L8), initiating main turbine and feedwater turbine trips. Position switches on the turbine stop (throttle) valves initiate a reactor scram and RPT and shut down the reactor. After the turbine trip, the failed DEH control system signals the bypass to open to full bypass flow of 25% NBR steam flow. After the pressurization resulting from the turbine stop (throttle) valve closure, the pressure increase opens the relief valves and pressure drops and continues to drop until turbine inlet pressure is below the low turbine pressure isolation setpoint when main steam line isolation limits the duration and severity of the depressurization.
In order to properly simulate the expected sequence of events, the analysis of this event assumed normal functioning of plant instrumentation and controls, plant protection, and reactor protection systems except as otherwise noted.
Initiation of HPCS and RCIC system functions will occur when the vessel water level reaches the L2 setpoint although this is not included in the analysis. Normal startup and actuation can take up to 30 sec before effects are realized. If these events occur, they will follow some time after the primary concerns of fuel thermal margin and overpressure effects have occurred and are expected to be less severe than those already experienced by the system.
15.1.3.2.3      The Effect of Single Failures and Operator Errors This transient leads to a loss of pressure control such that the increased steam flow demand causes a depressurization. Instrumentation for pressure sensing of the turbine inlet pressure is designed to be single failure proof for initiation of MSIV closure.
Reactor scram sensing, originating from limit switches on the MSIVs, is designed to be single failure proof. It is, therefore, concluded that the basic phenomenon of pressure decay is adequately terminated.
15.1-8

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 15.1.3.3       Core and System Performance 15.1.3.3.1      Mathematical Model The point-kinetics REDY model described in Section 15.0.3.3.1 is used to simulate this event.
15.1.3.3.2      Input Parameters and Initial Conditions This transient is simulated by setting the DEH control system demand signal to a high value, which causes the turbine control (governor) valves to open fully and the turbine bypass valves to open partially. A DEH control failure with 130% steam flow demand signal was simulated as a worst case since 130% is the normal maximum flow limit in order to conform with Table 15.1-2.
A 5-sec isolation valve closure is assumed when the turbine pressure decreases below the turbine inlet low pressure setpoint for main steam line isolation initiation.
Reactor scram is initiated when the isolation valves reach the 10% closed position. This is the maximum travel from the full open position allowed by specification.
This analysis has been performed, unless otherwise noted, with the plant conditions listed in Table 15.0-2.
15.1.3.3.3      Results Results are summarized in Table 15.0-1.
No significant reductions of fuel thermal margins occur. No significant thermal stresses are imposed on the reactor coolant pressure boundary (RCPB).
15.1.3.3.4      Consideration of Uncertainties If the maximum flow limiter were set higher or lower than normal, a faster or slower loss in nuclear steam pressure would result. The rate of depressurization may be limited by the bypass capacity, but it is unlikely. For example, the turbine valves will open to the valves-wide-open state admitting slightly more than the rated steam flow, and with the limiter in this analysis set to fail at 130%, it is expected that less than 25% would be bypassed. This is, therefore, not a limiting factor for the plant. If the rate of depressurization does change, it will be terminated by the low turbine inlet pressure trip setpoint.
Depressurization rate has a proportional effect upon the voiding action in the core and the flashing in the vessel bulk water regions. If the rate is low enough, the water level may not swell to the high water level trip setpoint and the isolation will occur earlier when pressure at 15.1-9

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 the turbine decreases below 850 psia. The reactor will scram as a result of the MSIV closure.
Since power is being depressed as the pressure decreases (due to additional voiding in the core), this transient is less severe when a slower depressurization rate is assumed. Therefore, the assumed L8 trip provides the most restrictive margins on MCPR and peak vessel pressure.
15.1.3.4       Barrier Performance Barrier performance analyses were not required since the consequences of this event do not result in any temperature or pressure transient in excess of the criteria for which fuel, pressure vessel, or containment are designed. Peak pressure in the bottom of the vessel is below the ASME code upset limit for the RCPB.
15.1.3.5       Radiological Consequences The consequence of this event does not result in fuel failure. It does result in the discharge of normal coolant activity to the suppression pool by means of SRV operation, which is contained in the primary containment. This event does not result in an uncontrolled release to the environment, so the plant operator can choose to hold the activity in containment or discharge it when conditions permit. If purging of the containment is chosen, the release would be in accordance with established requirements.
15.1.4      INADVERTENT SAFETY/RELIEF VALVE OPENING The event is defined as the inadvertent opening of an SRV which stays in the open position.
It was determined that this event is not limiting from a core performance standpoint.
15.1.4.1       Identification of Causes and Frequency Classification 15.1.4.1.1      Identification of Causes Cause of inadvertent opening is attributed to malfunction of the valve or an operator initiated opening. Opening and closing circuitry at the individual valve level (as opposed to groups of valves) is subject to a single failure impact. It is therefore simply postulated that a failure occurs and the event is analyzed accordingly. Detailed discussion of the valve is provided in Section 5.2.2.
15.1.4.1.2      Frequency Classification This event is categorized as an incident of moderate frequency.
15.1-10

COLUMBIA GENERATING STATION                         Amendment 61 FINAL SAFETY ANALYSIS REPORT                        December 2011 15.1.4.2       Sequence of Events and Systems Operation 15.1.4.2.1      Sequence of Events Table 15.1-3 lists the sequence of events.
15.1.4.2.2      Systems Operation In this transient, the analysis assumes normal functioning of plant instrumentation and controls, specifically, the relief valve discharge line temperature sensors and the suppression pool temperature sensors and reactor pressure vessel level control systems. The opening of an SRV allows steam to be discharged into the suppression pool. The sudden increase in the rate of steam flow leaving the reactor vessel causes a mild depressurization transient. The pressure regulator senses the nuclear system pressure decrease and within a few seconds closes the turbine control (governor) valve far enough to stabilize reactor vessel pressure at a slightly lower value and reactor power settles at nearly the initial power level. Additionally, although not credited in the analysis to mitigate the consequences of this transient, minimum reactor and plant protection systems, emergency core cooling system flow, and RHR suppression pool cooling, are available.
15.1.4.2.3      The Effect of Single Failures and Operator Errors From a core performance standpoint, a single failure or operator error would simply activate the reactor protection system resulting in a plant shutdown. A single failure or operator error cannot increase the severity of this event.
The instrumentation which detects and audibly alarms the resulting suppression pool temperature rise, and the RHR containment heat removal system are designed to meet the single failure criteria. The operator must manually initiate suppression pool cooling.
15.1.4.3       Core and System Performance 15.1.4.3.1      Mathematical Model The one-dimensional ODYN model described in Section 15.0.3.3.1 is used to simulate this event.
15.1.4.3.2      Input Parameters and Initial Conditions These analyses have been performed, unless otherwise noted, with plant conditions tabulated in Table 15.0-2, the ODYN column. A discussion of the SRV is provided in Section 5.2.2.
15.1-11

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.1.4.3.3      Results Thermal margins decrease only slightly through the transient, and no fuel damage results from the transient. The MCPR is essentially unchanged and, therefore, the safety limit margin is unaffected.
15.1.4.4       Barrier Performance The transient resulting from a stuck open relief valve is a mild depressurization which is within the range of normal load following. Therefore, there is no significant effect on RCPB and containment design pressure limits.
Since quenchers are used as steam discharge devices on the steam relief lines, no unstable condensation oscillations are expected which could damage the containment vessel. This is discussed in Appendix 3A.
Therefore, barrier integrity and function is maintained.
15.1.4.5       Radiological Consequences While the consequence of this event does not result in fuel failure, it does result in the discharge of normal coolant activity to the suppression pool by means of SRV operation.
Since this activity is contained in the primary containment there will be no exposures to operating personnel. Since this event does not result in an uncontrolled release to the environment the plant operator can choose to hold the activity in containment or discharge it to the environment when conditions permit. If purging of the containment is chosen, the release would be in accordance with established requirements.
15.1.5      SPECTRUM OF STEAM PIPING FAILURES INSIDE AND OUTSIDE OF CONTAINMENT IN A PRESSURIZED WATER REACTOR This event is not applicable to BWR plants.
15.1.6      INADVERTENT RESIDUAL HEAT REMOVAL SHUTDOWN COOLING OPERATION This transient is classified as a nonlimiting event for both original and uprated power conditions. Therefore, no further analysis has been performed.
15.1-12

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.1.6.1        Identification of Causes and Frequency Classification 15.1.6.1.1       Identification of Causes At design power conditions no conceivable malfunction in the shutdown cooling system could cause temperature reduction.
In startup or cooldown operation, where the reactor is at or near critical, a very slow increase in reactor power could result. A shutdown cooling malfunction leading to a moderator temperature decrease could result from misoperation of the cooling water controls for the RHR heat exchangers. The resulting temperature decrease would cause a slow insertion of positive reactivity into the core. If the operator did not act to control the power level, a high neutron flux reactor scram would terminate the transient without violating fuel thermal limits and without any measurable increase in nuclear system pressure.
15.1.6.1.2       Frequency Classification This event is categorized as an incident of moderate frequency.
15.1.6.2        Sequence of Events and Systems Operation 15.1.6.2.1       Sequence of Events A shutdown cooling malfunction leading to a moderator temperature decrease could result from misoperation of the cooling water controls for RHR heat exchangers. The resulting temperature decrease causes a slow insertion of positive reactivity into the core. Scram will occur before any thermal limits are reached if the operator does not take action. The sequence of events for this event is shown in Table 15.1-4.
15.1.6.2.2       System Operation A shutdown cooling malfunction causing a moderator temperature decrease must be considered in all operating states. However, this event is not considered while at power operation since pressure is too high to permit operation of RHR shutdown cooling.
No unique safety actions are required to avoid unacceptable safety results for transients as a result of a reactor coolant temperature decrease induced by misoperation of the shutdown cooling heat exchangers. In startup or cooldown operation, where the reactor is at or near critical, the slow power increase resulting from the cooler moderator temperature would be controlled by the operator in the same manner normally used to control power in the source or intermediate power ranges.
15.1-13

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.1.6.2.3       Effect of Single Failures and Operator Action No single failures can cause this event to be more severe.
If the operator takes action, the slow power rise will be controlled in the normal manner. If no operator action is taken, a scram will terminate the power increase before thermal limits are reached.
15.1.6.3       Core and System Performance The increased subcooling caused by misoperation of the RHR shutdown cooling mode could result in a slow power increase due to the reactivity insertion. This power rise would be terminated by a flux scram before fuel thermal limits are approached. Therefore, only a qualitative description is provided here.
15.1.6.4       Barrier Performance The consequences of this event do not result in any temperature or pressure transient in excess of the criteria for which the fuel, pressure vessel, or containment are designed. Therefore, barrier integrity and function is maintained.
15.1.6.5       Radiological Consequences Since this event does not result in any fuel failures, no analysis of radiological consequences is required for this event.
15.

==1.7      REFERENCES==

15.1-1           For Power Uprate: GE Nuclear Energy, WNP-2 Power Uprate Transient Analysis Task Report, GE-NE-208-08-0393, September 1993 (Proprietary).
15.1-2           NEDE-30130-P-A, Steady State Nuclear Methods, April 1985.
15.1-3           Supplemental Reload Licensing Report for Columbia (most recent version referenced in COLR).
15.1-4           NEDC-24154-P-A, Qualification of the One-Dimensional Core Transient Model for Boiling Water Reactors, Volumes 1, 2, 3 and 4, February 2000.
15.1-5           GE Nuclear Energy, WNP-2 Power Uprate Project NSSS Engineering Report, GE-NE-208-17-0993, Revision 1, December 1994.
15.1-14

COLUMBIA GENERATING STATION                       Amendment 63 FINAL SAFETY ANALYSIS REPORT                      December 2015 15.1-6      General Electric Standard Application for Reactor Fuel, NEDE-24011-P-A and Supplement for United States, NEDE-24011-P-A-US (most recent approved revision referenced in COLR).
15.1-7      NEDE-32906P-A, TRACG Application for Anticipated Operational Occurrences Transient Analyses, Revision 3, September 2006.
LDCN-15-011                             15.1-15

COLUMBIA GENERATING STATION                          Amendment 63 FINAL SAFETY ANALYSIS REPORT                         December 2015 Table 15.1-1 Typical Sequence of Events for Figure 15.1-1 Feedwater Controller Failure 100% Reactor Power / 106% Core Flow Time (sec)                                    Event 0         Initiate simulated failure of 139% upper limit on feedwater flow.
10.06     L8 vessel level setpoint trips main turbine and feedwater pumps. Turbine bypass operation initiated.
10.16     Turbine control (governor) or stop (throttle) valves fully closed.
10.08     Reactor scram trip actuated from main turbine control (governor) valve fast closure.
10.16     Turbine bypass valves start to open.
10.27     Recirculation pump motor circuit breakers open causing decrease in core flow to natural circulation.
LDCN-15-011                             15.1-17

COLUMBIA GENERATING STATION                         Amendment 61 FINAL SAFETY ANALYSIS REPORT                        December 2011 Table 15.1-1A Sequence of Events for Figure 15.1-3 Feedwater Controller Failure Single Loop Operation 75% Power / 57% Flow Time (sec)                                     Event 0         Initiate an upper limit failure of 146% of rated feedwater flow.
8.39      L8 vessel level setpoint trips main turbine and feedwater pumps.
8.39      Recirculation pump trip (RPT) actuated by stop valve position switches.
8.40      Reactor scram trip actuated from main turbine stop valve position switches.
8.49      Turbine stop valves closed and main turbine bypass valves start to open.
8.58      Recirculation pump motor circuit breakers open causing decrease in core flow to natural circulation.
15.1-18

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 Table 15.1-2 Sequence of Events for Figure 15.1-2 Pressure Regulator Failure - Open Uprated Power Time (sec)                                     Event 0          Simulate maximum limit on steam flow, (130%) to main turbine.
0.2        Main turbine bypass valves open.
3.31       Vessel water level (L8) trip initiates turbine and feedwater trips.
3.32       Main turbine stop valves reach 90% open position initiating a reactor scram.
3.50       Both recirculation pumps trip.
6.15       Feedwater recirculation valves trip.
6.95       Group 3 relief valves actuated.
7.40       Group 4 relief valves actuated.
10a          Pressure relief valves closed.
57.98a       Main steam line isolation valves closed on turbine inlet pressure (approximately 850 psia).
77           High-pressure core spray and RCIC system initiation on low level (L2).
a Estimated.
15.1-19

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 Table 15.1-3 Sequence of Events for Inadvertent Safety/Relief Valve Opening Uprated Power Time                                        Event 0         Initiate opening of one SRV which remains open throughout the event.
1a        Reactor dome pressure decreases.
3a        DEH turbine control system pressure regulator initiates closure of the turbine control (governor) valves to stabilize reactor vessel pressure.
8+        Reactor power settles near the initial power level.
a Approximately.
15.1-20

COLUMBIA GENERATING STATION                       Amendment 61 FINAL SAFETY ANALYSIS REPORT                      December 2011 Table 15.1-4 Sequence of Events for Inadvertent Residual Heat Removal Shutdown Cooling Operation Original Rated Power Timea                                        Event 0                 Residual heat removal shutdown cooling inadvertently activated.
0-10 minutes      Slow rise in reactor power.
  +10 minutes       Operator may take action to limit power rise. Flux scram will occur if no action is taken.
a Approximately.
15.1-21

Amendment 63 December 2015 Feedwater Controller Failure, Maximum Demand Columbia Generating Station                      System Response Final Safety Analysis Report                 100% Power, 106% Flow Draw. No. 910402.34      Rev. 1  Figure 15.1-1.1 Form No. 960690 LDCN-15-011

Amendment 53 November 1998 Pressure Regulator Failure - Open at 106.2%
Columbia Generating Station                 Uprated Power, 100%Flow Final Safety Analysis Report Draw. No. 020361.57      Rev. Figure 15.1-2.1

Amendment 53 November 1998 Pressure Regulator Failure - Open at 106.2%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.58     Rev. Figure 15.1-2.2

Amendment 53 November 1993 Pressure Regulator Failure Open at 106.2%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.59     Rev. Figure 15.1-2.3

Amendment 53 November 1998 Pressure Regulator Failure - Open at 106.2%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.60     Rev. Figure 15.1-2.4

Amendment 53 November 1998 Pressure Regulator Failure Open at 106.2%
Columbia Generating Station                Uprated Power, 100%Flow Final Safety Analysis Report Draw. No. 020361.61     Rev. Figure 15.1-2.5

Amendment 53 November 1998 Pressure Regulator Failure Open at 106.2%
Columbia Generating Station                Uprated Power, 100%Flow Final Safety Analysis Report Draw. No. 020361.62     Rev. Figure 15.1-2.6

Amendment 53 November 1998 Pressure Regulator Failure - Open at 106.2%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.63     Rev. Figure 15.1-2.7

Amendment 53 November 1998 Pressure Regulator Failure - Open at 106.2%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.64     Rev. Figure 15.1-2.8

Amendment 53 November 1998 Pressure Regulator Failure - Open at 106.2%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.65     Rev. Figure 15.1-2.9

Amendment 53 November 1998 Pressure Regulator Failure - Open at 106.2%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.66     Rev. Figure 15.1-2.10

Amendment 53 November 1998 Pressure Regulator Failure - Open at 106.2%
Columbia Generating Station                Uprated Power, 100%Flow Final Safety Analysis Report Draw. No. 020361.67     Rev.      Figure 15.1-2.11

Amendment 57 December 2003 Ave Surface Heat Flux Neutron Flux                           Core Inlet Flow 20 15 Time (Sec) 10 5
0 150         100                           50                       0 (Percent of Rated)
Feedwater Controller Failure, Maximum Demand, Columbia Generating Station                                     EOC RPT OOS, Single Loop Operation and 75%
Final Safety Analysis Report                                               Uprated Power, 57% Flow Draw. No. 910402.41        Rev. Figure   15.1-3.1 Form No. 960690 LDCN-03-003

Amendment 57 December 2003 Level (Inch Ref SIP Skirt)
Vessel Steamflow   Turbine Steamflow   Feedwater Flow 20 15 Time (Sec) 10 5
0 200   100 0
                                                                                                                                                         -100 Feedwater Controller Failure, Maximum Demand, Columbia Generating Station                                         EOC RPT OOS, Single Loop Operation and 75%
Final Safety Analysis Report                                                   Uprated Power, 57% Flow Draw. No. 910402.40   Rev. Figure   15.1-3.2 Form No. 960690 LDCN-03-003

Amendment 57 December 2003 Vessel Pres Rise (PSI)                                           Bypass Valve Flow Safety Valve Flow   Relief Valve Flow 20 15 Time (Sec) 10 5
0 300   200                           100 0
Feedwater Controller Failure, Maximum Demand, Columbia Generating Station                                                 EOC RPT OOS, Single Loop Operation and 75%
Final Safety Analysis Report                                                           Uprated Power, 57% Flow Draw. No. 910402.39         Rev. Figure   15.1-3.3 Form No. 960690 LDCN-03-003

Amendment 57 December 2003 Void Reactivity   Doppler Reactivity   Scram Reactivity   Total Reactivity 20 15 Time (Sec) 10 5
0 1           0                           -1                     -2 Reactivity Components Feedwater Controller Failure, Maximum Demand, Columbia Generating Station                                                      EOC RPT OOS, Single Loop Operation and 75%
Final Safety Analysis Report                                                                Uprated Power, 57% Flow Draw. No. 910402.38    Rev. Figure   15.1-3.4 Form No. 960690 LDCN-03-003

COLUMBIA GENERATING STATION                           Amendment 59 FINAL SAFETY ANALYSIS REPORT                          December 2007 15.2     INCREASE IN REACTOR PRESSURE 15.2.1       PRESSURE REGULATOR FAILURE - CLOSED This transient is classified as a nonlimiting event for both original and uprated power conditions. Therefore, cycle specific analyses are not performed for this event. The analysis results presented in the section are based on uprated power conditions and a representative reload core (Cycle 8) as documented in Reference 15.2-5.
15.2.1.1         Identification of Causes and Frequency Classification 15.2.1.1.1        Identification of Causes A triple redundant control system is provided to maintain primary system pressure control.
The pressure upstream of the main turbine stop (throttle) valves is sensed by three redundant throttle pressure transmitters and the control system uses a median select logic to determine which pressure transmitter is used to control throttle pressure. The pressure control system compares the detected throttle pressure to a pressure setpoint to control the position of the main turbine control (governor) valves in order to control pressure.
It is assumed for purposes of this transient analysis that a single failure occurs on the controlling pressure transmitter which erroneously causes the DEH control system to close the turbine control (governor) valves and thereby increases reactor pressure. If this occurs, the self diagnostics ability and triple redundant control system is available.
15.2.1.1.2        Frequency Classification This event is categorized as an incident of moderate frequency.
15.2.1.2         Sequence of Events and Systems Operation 15.2.1.2.1        Sequence of Events A failure of a DEH control system component that causes the turbine control (governor) valves or turbine bypass valves to move towards the closed position will momentarily result in an initial pressure increase because the reactor is still generating the initial steam flow. The DEH control system is self diagnostic. It will detect the faulty component and disable it. The control system is redundant and will continue to perform its functions, and will restore steady state operation.
For a failure that causes the DEH turbine control pressure regulator to initiate a demand signal to close the turbine control (governor) valves (requires multiple component failures), there will be an increase in system pressure and reactor power. A scram will be initiated when the high LDCN-06-057, 07-011                             15.2-1

COLUMBIA GENERATING STATION                              Amendment 59 FINAL SAFETY ANALYSIS REPORT                             December 2007 neutron flux scram setpoint is reached. The pressure rises to the pressure relief setpoint, part of the relief valves open, discharging steam to the suppression pool. The plant response is given in Table 15.2-1.
15.2.1.2.2        Systems Operation Normal plant instrumentation and control is assumed to function except for the pressure regulator failure. The event is analyzed from 104.1% uprated power and 106% of rated core flow. The event results in a high flux trip initiated by the reactor protection system.
15.2.1.2.3        The Effect of Single Failures and Operator Errors The first assumed failure produces a slight pressure increase in the reactor until the DEH control system adjusts to the single failure and gains control. No other action is significant in restoring normal operation. If subsequent failures occur such that the DEH control system further closes the turbine control (governor) valves the reactor pressure could rise to the point where a flux or pressure scram trip would be initiated to shutdown the reactor. This event is less severe than the turbine trip for the following reasons:
: a.        For the DEH control system failure-closure event the reactor scrams on high neutron flux or pressure but the recirculation pumps do not trip. As a result, core flow remains at 100% or greater throughout the critical portion of the transient with respect to the critical power ratio (CPR). This provides improved heat transfer capability in relation to the turbine trip transient; and
: b.        Since the turbine control (governor) valves close in response to a pressure error signal, their closure rate is not as fast as the turbine stop (throttle) or control (governor) valve response to a trip signal. This produces a slower pressurization rate for the DEH control system failure relative to the turbine trip event. This in turn results in a lower peak neutron flux and therefore a lower peak surface heat flux than the turbine trip event.
15.2.1.3         Core and System Performance 15.2.1.3.1        Mathematical Model The one-dimensional ODYN model described in Section 15.0.3.3.1 is used to simulate this event.
LDCN-06-057, 07-011                               15.2-2

COLUMBIA GENERATING STATION                           Amendment 59 FINAL SAFETY ANALYSIS REPORT                          December 2007 15.2.1.3.2       Input Parameters and Initial Conditions The analyses have been performed with plant conditions at 104.1% of uprated power and 106% of rated core flow. The input parameters are given in detail in Table 15.0-2 under the ODYN column.
15.2.1.3.3       Results The closure of the turbine governor (control) valves results in a rise in reactor pressure, collapsing the coolant voids which in turn increases the neutron flux. One sec after the initiation of the event the neutron flux increases to the high flux setpoint signal and initiates a reactor scram. Two sec into the event the pressure in the reactor reaches the ATWS high pressure trip setpoint, initiating a recirculation pump trip signal. As the pressure in the reactor system continues to rise, the relief valves begin to open starting with Group 3. The maximum pressure is reached at 3.25 sec and is calculated to be 1220 psig at the bottom of the reactor vessel. Table 15.2-1 provides the sequence of events and Figure 15.2-1 depicts the plant parameters responses. Key transient peak values are presented in Table 15.0-1. This event is nonlimiting in that the pressurization event is less severe than the Generator Load Rejection with Bypass Failure and Turbine Trip with Bypass Failure events.
15.2.1.3.4       Consideration of Uncertainties The uncertainties included in the initial power and flow considerations maximize the consequences of the plant response. The independent pressure regulators normally respond such that failure of one would be compensated by the other regulator with plant not experiencing a trip.
15.2.1.4        Barrier Performance The consequences of this event do not result in any temperature or pressure transient (see Table 15.0-1) in excess of the criteria for which the fuel, pressure vessel, or containment are designed. Therefore, barrier integrity and function is maintained.
15.2.1.5        Radiological Consequences Since this event does not result in any fuel failures or any release of primary coolant to either the secondary containment or to the environment, there are no radiological consequences associated with this event.
LDCN-07-011                                      15.2-3

COLUMBIA GENERATING STATION                           Amendment 59 FINAL SAFETY ANALYSIS REPORT                          December 2007 15.2.2      GENERATOR LOAD REJECTION 15.2.2.1       Identification of Causes and Frequency Classification 15.2.2.1.1      Identification of Causes Fast closure of the turbine control (governor) valves (TCVs) is initiated whenever electrical grid disturbances occur which result in significant loss of electrical load on the generator. The TCVs are required to close as rapidly as possible to prevent excessive overspeed of the turbine-generator rotor. Closure of the main TCVs will cause a sudden reduction in steam flow which results in an increase in system pressure, which may cause a reactor shutdown due to a high flux or high steam pressure condition.
15.2.2.1.2      Frequency Classification 15.2.2.1.2.1 Generator Load Rejection. This event is categorized as an incident of moderate frequency.
15.2.2.1.2.2 Generator Load Rejection with Bypass Failure. This event is categorized as a moderate frequency event.
15.2.2.2       Sequence of Events and System Operation The generator load rejection with bypass failure event is the most limiting (with respect to thermal margin) of the class of transients characterized by rapid vessel pressurization, including load rejection with the bypass valves operating. The generator load rejection causes a TCV (governor valve) fast closure, which initiates a reactor scram and a recirculation pump trip (RPT). The compression wave produced by the TCV fast closure travels through the steam lines into the vessel and pressurizes the reactor vessel and core. Bypass flow to the condenser, which would mitigate the pressurization effect, is conservatively not allowed. The excursion of core power due to void collapse is primarily terminated by reactor scram and void growth due to RPT. The recirculation pump speed remains constant until tripped by the RPT system.
Events caused by low water level trips, including closure of main steam line isolation valves (MSIVs), and initiation of high-pressure core spray (HPCS) and reactor core isolation cooling (RCIC) are not included in the simulation. Should these events occur, they will follow after the primary concerns of fuel thermal margin and overpressure effects have occurred, and are expected to be less severe than those already experienced by the system.
LDCN-07-011                                   15.2-4

COLUMBIA GENERATING STATION                             Amendment 59 FINAL SAFETY ANALYSIS REPORT                            December 2007 15.2.2.2.1       Sequence of Events 15.2.2.2.1.1 Generator Load Rejection - Turbine Control Valve Fast Closure. This transient is classified as a nonlimiting event for both original and uprated power conditions. Therefore, the original rated power (3323 MWt) analysis has not been updated.
A loss of generator electrical load from high power conditions produces the sequence of events listed in Table 15.2-2.
15.2.2.2.1.2 Generator Load Rejection with Failure of Bypass. A loss of generator electrical load at 3486 MWt with bypass failure produces the sequence of events listed in Table 15.2-3.
15.2.2.2.2       System Operation 15.2.2.2.2.1 Generator Load Rejection with Bypass. To properly simulate the expected sequence of events, the analysis of this event assumes normal functioning of plant instrumentation and controls, plant protection, reactor pressure vessel (RPV) safety/relief valves (SRV), and reactor protection systems (RPS) unless stated otherwise. The bypass valve opening characteristics reflect the specified delay together with the specified opening characteristic required for bypass system operation.
Turbine control valve fast closure initiates a scram trip signal for power levels greater than 30% nuclear boiler rated (NBR). In addition, recirculation pump trip (RPT) is initiated. Both of these trip signals satisfy single failure criterion and credit is taken for these protection features.
The pressure relief system, which operates the SRVs independently when system pressure exceeds relief valve instrumentation setpoints is assumed to function normally during the time period analyzed.
15.2.2.2.2.2 Generator Load Rejection with Failure of Bypass. Same as Section 15.2.2.2.2.1 except that failure of the main turbine bypass valves is assumed for the entire transient. In addition, the pressure relief system, which operates the SRVs independently when system pressure exceeds relief valve instrumentation setpoints, fails to operate. Pressure relief is provided by the safety function of the SRVs.
15.2.2.2.3       The Effect of Single Failures and Operator Errors Mitigation of pressure increase, the basic nature of this transient, is accomplished by the RPS functions. Turbine control valve trip scram and RPT are designed to satisfy the single failure criterion. An evaluation of the most limiting single failure (i.e., failure of the bypass system) was considered in this event.
LDCN-07-011                                      15.2-5

COLUMBIA GENERATING STATION                            Amendment 63 FINAL SAFETY ANALYSIS REPORT                           December 2015 15.2.2.3       Core and System Performance 15.2.2.3.1      Mathematical Model 15.2.2.3.1.1 Generator Load Rejection with Bypass. The predicted dynamic behavior for the generator load reject with bypass valves operable has been determined using a computer simulated, analytical model of a generic direct-cycle BWR. This model is described in detail in Reference 15.2-4.
The nonlinear computer simulated analytical model is designed to predict associated transient behavior of the reactor. Some of the significant features of the model are the following:
: a.      A point kinetic model is assumed with reactivity feedbacks from control rods (absorption), voids (moderation), and Doppler (capture) effects.
: b.      The fuel is represented by three four-node cylindrical elements, each enclosed in a cladding node. One of the cylindrical elements is used to represent core average power and fuel temperature conditions, providing the source of Doppler feedback. The other two are used to represent hot spots in the core, to simulate peak fuel center temperature and cladding temperature.
: c.      Four primary system pressure nodes are simulated. The nodes represent the core exit pressure, vessel dome pressure, steam line pressure (at a point representative of the safety/relief valve location), and turbine inlet pressure.
: d.      The active core void fraction is calculated from a relationship between core exit quality, inlet subcooling, and pressure. This relationship is generated from multimode core steady-state calculations. A second-order void dynamic model, with the void boiling sweep time calculated as a function of core flow and void conditions, is also utilized.
: e.      Principal controller functions such as feedwater flow, recirculation flow, reactor water level, pressure and load demand are represented together with their dominant nonlinear characteristics.
: f.      The ability to simulate necessary reactor protection system functions is provided.
15.2.2.3.1.2 Generator Load Rejection with Bypass Failure. The predicted dynamic behavior for the load rejection with bypass inoperable has been determined using a computer simulated, analytical model of a direct-cycle BWR that is discussed in Section 15.1.2.3.1. This model is described in detail in Reference 15.2-10.
LDCN-15-011                                    15.2-6

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 15.2.2.3.2      Input Parameters and Initial Conditions These analyses have been performed, unless otherwise noted, with the plant conditions tabulated in Table 15.0-2 for the load rejection with bypass and in Table 15.0-2B for load rejection with bypass failure.
The turbine digital electrohydraulic control system power/load imbalance device detects load rejection before a measurable speed change takes place.
The closure characteristics of the TCVs are assumed such that the valves operate in the full arc (FA) mode and have a full stroke closure time, from fully open to fully closed, of 0.15 sec.
In FA mode, at 100% power, the TCVs are not fully open, so the analysis assumes a closure time that is a fraction of the full stroke time proportional to the TCV initial position.
15.2.2.3.3      Results Analyses were performed to analyze combinations of RPT operable/inoperable and Option A and Option B scram speeds (Reference 15.2-3). The excursion of core power due to void collapse is primarily terminated by reactor scram and void growth due to RPT.
15.2.2.3.3.1 Generator Load Rejection with Bypass. Figure 15.2-2.1 shows the results of the generator trip from original rated power. Peak neutron flux rises 156.8% above NBR conditions.
The average surface heat flux peaks at 102.9% of the initial value and minimum critical power ratio (MCPR) does not significantly decrease below its initial value.
15.2.2.3.3.2 Generator Load Rejection with Failure of Bypass. Figure 15.2-2.2 shows that, for the case of bypass failure, peak neutron flux reaches about 330% power. Results reflect GNF2 fuel introduction, some of which are dependent on fuel design and core loading pattern.
Compliance with the event acceptance criteria is demonstrated by cycle-dependent analysis of potentially limiting events just prior to the operation of that cycle. The results are reported in the Supplemental Reload Licensing Report (Reference 15.2-3). As discussed in Section 15.0.2.1, when this event is initiated during single loop operation, the consequences are less severe than the consequences analyzed for the two loop operation.
15.2.2.3.4      Consideration of Uncertainties The full stroke closure time of the TCV of 0.15 sec is conservative. Typically, the actual closure time is closer to 0.2 sec. The less time it takes to close, the more severe the pressurization effect.
LDCN-15-011                                     15.2-7

COLUMBIA GENERATING STATION                          Amendment 63 FINAL SAFETY ANALYSIS REPORT                         December 2015 All systems used for protection in this event were assumed to have the poorest allowable response. Expected plant behavior is, therefore, expected to reduce the actual severity of the transient.
15.2.2.4       Barrier Performance 15.2.2.4.1      Generator Load Rejection Peak pressure remains within normal operating range and no threat to the barrier exists.
15.2.2.4.2      Generator Load Rejection with Failure of Bypass The peak dome pressure reaches 1244 psig. The peak reactor coolant pressure boundary (RCPB) pressure reaches 1270 psig. The peak pressure remains well below the nuclear barrier transient pressure limit of 1375 psig.
15.2.2.5       Radiological Consequences While the consequences of this event do not result in fuel failures, the result includes the discharge of normal coolant activity to the suppression pool by means of safety/relief valve (SRV) operation. Since this activity is contained in the primary containment, there will be no exposure to the public. Since this event does not result in an uncontrolled release to the environment, the plant operator can choose to hold the activity in containment or filter the discharge prior to release to the environment when conditions permit in accordance with established requirements.
15.2.3      TURBINE TRIP 15.2.3.1       Identification of Causes and Frequency Classification 15.2.3.1.1      Identification of Causes A variety of turbine or nuclear system malfunctions will initiate a turbine trip. Some examples are moisture separator high levels, operator lockout, loss of control fluid pressure, low condenser vacuum, and reactor high water level.
15.2.3.1.2      Frequency Classification 15.2.3.1.2.1 Turbine Trip. This event is categorized as an incident of moderate frequency.
In defining the frequency of this event, turbine trips which occur as a by-product of other transients such as loss of condenser vacuum or reactor high level trip events are not included.
However, spurious low vacuum or high level trip signals which cause an unnecessary turbine trip are included in defining the frequency.
LDCN-15-011                                   15.2-8

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 15.2.3.1.2.2 Turbine Trip with Failure of Bypass. This transient disturbance is categorized as a moderate frequency incident.
15.2.3.2       Sequence of Events and Systems Operation 15.2.3.2.1      Sequence of Events 15.2.3.2.1.1 Turbine Trip. This transient is classified as a nonlimiting event for both original and uprated power conditions. Therefore, the original rated power (3323 MWt) analysis has not been updated. Turbine trip at high power produces the sequence of events listed in Table 15.2-4.
15.2.3.2.1.2 Turbine Trip with Failure of Bypass. Turbine trip at high power with bypass failure produces the sequence of events listed in Table 15.2-5.
15.2.3.2.2      Systems Operation 15.2.3.2.2.1 Turbine Trip. All plant control systems maintain normal operation unless specifically designated to the contrary.
Turbine stop (throttle) valve closure initiates a reactor scram trip by means of valve position signals to the protection system.
Turbine stop valve closure initiates RPT thereby terminating the jet pump drive flow.
The pressure relief system, which operates the relief valves independently when system pressure exceeds relief valve instrumentation setpoints, is assumed to function normally during the time period analyzed.
The severity of turbine trips from lower initial power levels decreases to the point where a scram can be avoided if auxiliary power is available from an external source and the power level is within the bypass capability.
15.2.3.2.2.2 Turbine Trip with Failure of Bypass. Same as Section 15.2.3.2.2.1 except that failure of the main turbine bypass system is assumed for the entire transient time period analyzed. During the transient the SRVs open and close sequentially as the stored energy is dissipated until the pressure falls below the valve setpoints.
15.2.3.2.2.3 Turbine Trip at Low Power with Failure of Bypass. Same as Section 15.2.3.2.2.1 except that failure of the main turbine bypass system is assumed.
LDCN-10-029                                    15.2-9

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 Below 30% NBR power level, a main stop valve scram trip inhibit signal derived from the first stage pressure of the turbine is activated. This is done to eliminate the stop valve scram trip signal from scramming the reactor provided the bypass system functions properly. In other words, the bypass would be sufficient at this low power to accommodate a turbine trip without the necessity of shutting down the reactor. All other protection system functions remain functional as before and credit is taken for those protection system trips.
15.2.3.2.3      The Effect of Single Failures and Operator Errors 15.2.3.2.3.1 Turbine Trips at Power Levels Greater Than 30% Nuclear Boiler Rated.
Mitigation of pressure increase, the basic nature of this transient, is accomplished by the RPS functions. Main stop valve closure scram trip and RPT are designed to satisfy single failure criterion.
15.2.3.2.3.2 Turbine Trips at Power Levels Less Than 30% Nuclear Boiler Rated. Same as Section 15.2.3.2.3.1 except RPT and stop valve closure scram trip is normally inoperative.
Since protection is still provided by high flux, high pressure, etc., these will continue to function and scram the reactor should a single failure occur.
15.2.3.3      Core and System Performance 15.2.3.3.1      Mathematical Model 15.2.3.3.1.1 Turbine Trip with Bypass. The predicted dynamic behavior for the turbine trip has been determined using a computer simulated, analytical model of a generic direct-cycle BWR, as discussed in Section 15.2.2.3.1. This model is described in detail in Reference 15.2-4.
15.2.3.3.1.2 Turbine Trip with Bypass Failure. The three-dimensional TRACG model described in Section 15.0.3.3.1 is used to simulate this event.
15.2.3.3.2      Input Parameters and Initial Conditions These analyses have been performed, unless otherwise noted, with plant conditions tabulated in Table 15.0-2 for the turbine trip with bypass and Table 15.0-2B for the turbine trip with bypass failure.
The turbine trip analysis was performed at the 105% of the original rated steam flow. The turbine trip with bypass failure was analyzed at an initial condition of 100% rated power (3486 MWt) and 106% rated core flow.
Turbine stop (throttle) valves full stroke closure time is 0.1 sec.
LDCN-15-011                                   15.2-10

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 A reactor scram is initiated by position switches on the stop valves when the valves are 90%
open or less. This stop valve scram trip signal is automatically bypassed when the reactor is below 30% NBR power level.
Reduction in core recirculation flow is initiated by position switches on the main stop valves, which actuate trip circuitry which trips the recirculation pumps.
15.2.3.3.3      Results 15.2.3.3.3.1 Turbine Trip. The results of a turbine trip with the bypass system operating normally are shown in Figure 15.2-3.
Neutron flux increases rapidly because of the void reduction caused by the pressure increase.
However, the flux increase is limited to 147.5% of rated by the stop valve scram and the RPT system. Peak fuel surface heat flux does not exceed 101.7% of its initial value.
15.2.3.3.3.2 Turbine Trip with Failure of Bypass. The results of a turbine trip with failure of the bypass system are shown in Figure 15.2-4.
The peak neutron flux reaches 278% of its rated value, and peak surface heat flux reaches 111% of its initial value.
Results reflect GE14 fuel introduction, some of which are dependent on fuel design and core loading pattern. The event was analyzed for GNF2 introduction, however the results were not reported because the event was not limiting. Compliance with the event acceptance criteria is demonstrated by cycle-dependent analysis of potentially limiting events just prior to the operation of that cycle. The results are reported in the Supplemental Reload Licensing Report (Reference 15.2-3) if the event is limiting.
15.2.3.3.3.3 Turbine Trip with Bypass Valve Failure, Low Power. This transient is less severe than a similar one at high power. Below 30% of rated power, the turbine stop valve closure and TCV (governor valve) closure scrams are automatically bypassed. At these lower power levels, turbine first stage pressure is used to initiate the scram logic bypass. The scram which terminates the transient is initiated by high vessel pressure. The bypass valves are assumed to fail; therefore, system pressure will increase until the pressure relief setpoints are reached. At this time, because of the relatively low power of this transient event, relatively few relief valves will open to limit reactor pressure. Peak pressures are not expected to greatly exceed the pressure relief valve setpoints and will be significantly below the reactor coolant pressure boundary (RCPB) transient limit of 1375 psig. Peak surface heat flux and peak fuel center temperature remain at relatively low values and MCPR remains well above the GETAB safety limit.
LDCN-15-011                                   15.2-11

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.3.3.4      Considerations of Uncertainties Uncertainties in these analyses involve protection system settings, system capacities, and system response characteristics. In all cases, the most conservative values are used in the analyses. For example:
: a.      Slowest allowable control rod scram motion is assumed,
: b.      Scram worth shape for all-rod-out conditions is assumed,
: c.      Minimum specified valve capacities are utilized for overpressure protection, and
: d.      Setpoints of the SRVs include errors and uncertainties (high) for all valves.
15.2.3.4      Barrier Performance 15.2.3.4.1      Turbine Trip Peak pressure in the bottom of the vessel reaches 1163 psig, which is below the American Society of Mechanical Engineers (ASME) Code limit of 1375 psig for the RCPB. Vessel dome pressure does not exceed 1136 psig.
15.2.3.4.2      Turbine Trip with Failure of Bypass The peak steam line pressure reaches 1235 psig. The peak reactor coolant pressure boundary (RCPB) pressure reaches 1260 psig. The peak pressure remains well below the nuclear barrier transient pressure limit of 1375 psig.
15.2.3.4.2.1 Turbine Trip with Failure of Bypass at Low Power. Qualitative discussion is provided in Section 15.2.3.3.3.3.
15.2.3.5      Radiological Consequences The consequence of this event does not result in fuel failure. It does result in the discharge of normal coolant activity to the suppression pool by means of SRV operation, which is contained in the primary containment. This event does not result in an uncontrolled release to the environment, so the plant operator can choose to hold the activity in containment or discharge it when conditions permit. If purging of the containment is chosen, the release would be in accordance with established requirements.
15.2.4      MAIN STEAM LINE ISOLATION VALVE CLOSURES This transient is classified as a nonlimiting event for both original and uprated power conditions. Therefore, cycle specific analyses are not performed for this event. The analysis results presented in the section are based on uprated power conditions and a representative reload core (Cycle 8) as documented in Reference 15.2-5.
15.2-12

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.4.1      Identification of Causes and Frequency Classification 15.2.4.1.1      Identification of Causes Various steam line and nuclear system malfunctions, or operator actions, can initiate MSIV closure. Examples are low-steam line pressure, high-steam line flow, low-water level, or manual action.
15.2.4.1.2      Frequency Classification 15.2.4.1.2.1 Closure of All Main Steam Line Isolation Valves. This event is categorized as an incident of moderate frequency. To define the frequency of this event as an initiating event and not the byproduct of another transient, only the following contribute to the frequency:
Manual action (purposely or inadvertent); spurious signals such as low pressure, low reactor water level, and low condenser vacuum; and equipment malfunctions such as faulty valves or operating mechanisms. A closure of one MSIV may cause an immediate closure of all the other MSIVs depending on reactor conditions. If this occurs, it is also included in this category. During the MSIV closure, position switches on the valves provide a reactor scram when the valves in three or more main steam lines are less than 90% open (except for interlocks which permit proper plant startup). Protection system logic permits the test closure of one valve without initiating scram from the position switches.
15.2.4.1.2.2 Closure of One Main Steam Line Isolation Valve. This event is categorized as an incident of moderate frequency. One MSIV at a time may be manually closed for testing purposes. Operator error or equipment malfunction may cause a single MSIV to be closed inadvertently. If reactor power is greater than about 75% when this occurs, a high flux or high steam line flow condition may result in a scram. If all MSIVs close as a result of the single event, the event is considered as a closure of all MSIVs. The results presented for this event assume all MSIVs close as a result of an unspecified initiating event.
15.2.4.2      Sequence of Events and Systems Operation 15.2.4.2.1      Sequence of Events Table 15.2-6 lists the sequence of events for Figure 15.2-5. When the MSIVs reach their 85% open position, a reactor scram is initiated by the reactor protection system. The valve closure results in a system pressure increase which in turn results in a spike in reactor neutron flux. The reactor vessel pressure increase also results in an ATWS recirculation pump trip (RPT). As the pressure increases, the relief valves begin to open terminating the pressure increase.
15.2-13

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.4.2.2       Systems Operation 15.2.4.2.2.1 Closure of All Main Steam Line Isolation Valves. The MSIV closures initiate a reactor scram trip by means of position signals to the protection system. Credit is taken for successful operation of the protection system.
The pressure relief system which initiates opening of the relief valves when system pressure exceeds relief valve instrumentation setpoints is assumed to function normally during the time period analyzed.
All plant control systems maintain normal operation unless specifically designated to the contrary.
15.2.4.2.2.2 Closure of One Main Steam Line Isolation Valve. A closure of a single MSIV will not initiate a reactor scram by means of the position signal to the protection system. This is because the valve position scram trip logic is designed to accommodate single valve operation and testability during normal reactor operation at limited power levels. Credit is taken for the operation of the pressure and flux signals to initiate a reactor scram.
All plant control systems maintain normal operation unless specifically designated to the contrary.
15.2.4.2.3       The Effect of Single Failures and Operator Errors Mitigation of pressure increase is accomplished by initiation of the reactor scram by means of MSIV position switches and the protection system. Relief valves also operate to limit system pressure. All of these aspects are designed to single failure criterion and additional single failures would not alter the results of this analysis.
Failure of a single relief valve to open is not expected to have any significant effect. Such a failure is expected to result in less than a 5 psi increase in the maximum vessel pressure rise.
The peak pressure will still remain considerably below 1375 psig.
15.2.4.3        Core and System Performance 15.2.4.3.1       Mathematical Model The point-kinetics REDY model described in Section 15.0.3.3.1 is used to simulate these transient events.
15.2-14

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.4.3.2       Input Parameters and Initial Conditions It is assumed the closure of all MSIVs occurs with the plant operating at 106% of uprated power and 100% core flow. The input parameters are defined with the plant conditions tabulated in Table 15.0-2 for power uprate.
The MSIVs close in 3 to 5 sec. The worst case, the 3-sec closure time, is assumed in this analysis.
Position switches on the valves initiate a reactor scram when the valves are less than 90% open as described in Section 7.2 (85% is assumed in the analysis). Closure of these valves inhibits steam flow to the feedwater turbines terminating feedwater flow.
Valve closure indirectly causes a trip of the main turbine and generator.
Because of the loss of feedwater flow, water level within the vessel decreases sufficiently to initiate trip of the recirculation pump and to initiate the HPCS and RCIC systems.
15.2.4.3.3       Results 15.2.4.3.3.1 Closure of All Main Steam Line Isolation Valves. The reactor scram is initiated at 0.45 sec when the MSIVs reach 85% open position. The nuclear system relief valves begin to open at 3.08 sec after the start of isolation. The valves close sequentially as the stored heat is dissipated but continue to discharge the decay heat intermittently. Table 15.2-6 provides the sequence of events and Figure 15.2-5 depicts the plant parameters responses. Key transient peak values are presented in Table 15.0-1. This event is non-limiting in that the pressurization event and change in CPR margin is less severe than the Generator Load Rejection with Bypass Failure and Turbine Trip with Bypass Failure events.
15.2.4.3.3.2 Closure of One Main Steam Line Isolation Valve. Only one isolation valve is permitted to be closed at a time for testing purposes to prevent scram. Normal test procedure requires an initial power reduction to approximately 65% to 70% of design conditions to avoid high-flux scram, high-pressure scram, or full isolation from a high-steam flow condition in the open steam lines. With a 3-sec closure of one MSIV during 105% of original rated power conditions, the steam flow disturbance raises vessel pressure and reactor power enough to initiate a high neutron flux scram. This transient is considerably milder than closure of all MSIVs at full power. No quantitative analysis is furnished for this event. No significant change in thermal margins is experienced and no fuel damage occurs. Peak pressure remains below SRV setpoints.
Inadvertent closure of one or all of the isolation valves while the reactor is shut down will produce no significant transient. Closures during plant heatup will be less severe than the maximum power cases (maximum stored and decay heat).
15.2-15

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.4.3.4      Considerations of Uncertainties Uncertainties in these analyses involve protection system settings, system capacities, and system response characteristics. In all cases, the most conservative values are used in the analyses. For example:
: a.      Slowest allowable control rod scram motion is assumed,
: b.      Scram worth shape for all-rod-out conditions is assumed,
: c.      Minimum specified valve capacities are used for overpressure protection, and
: d.      Setpoints of the SRVs are assumed to be 15 psi higher than the valves nominal setpoint.
15.2.4.4       Barrier Performance 15.2.4.4.1      Closure of All Main Steam Line Isolation Valves The nuclear system relief valves begin to open at approximately 3.1 sec after the start of isolation. The valves close sequentially as the stored heat is dissipated but continue to discharge the decay heat intermittently. Peak pressure at the vessel bottom reaches 1234 psig, clearly below the pressure limits of the RCPB. Peak pressure in the main steam line is 1198 psig.
15.2.4.4.2      Closure of One Main Steam Line Isolation Valve No significant effect is imposed on the RCPB, since if closure of the valve occurs at a high operating power level a flux or pressure scram will result. The main turbine bypass system will continue to regulate system pressure by means of the other three steam lines.
15.2.4.5       Radiological Consequences While the consequence of this event does not result in fuel failure, it does result in the discharge of normal coolant activity to the suppression pool via SRV operation. Since this activity is contained in the primary containment, there will be no exposure to the public. Since this event does not result in an uncontrolled release to the environment, the plant operator can choose to hold the activity in containment or discharge it to the environment when conditions permit. If purging of the containment is chosen, the release would be in accordance with established requirements.
15.2-16

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.5       LOSS-OF-CONDENSER VACUUM This transient is classified as a nonlimiting event for both original and uprated power conditions. Therefore, cycle specific analyses are not performed for this event. The analysis results presented in the section are based on uprated power conditions and a representative reload core (Cycle 8) as documented in Reference 15.2-5.
15.2.5.1       Identification of Causes and Frequency Classification 15.2.5.1.1      Identification of Causes Various malfunctions can cause a loss-of-condenser vacuum. The causes and estimated vacuum decay rates include failure or isolation of steam jet air ejectors (<1 in. Hg/mm), loss of sealing steam shaft gland seals (1 to 2 in. Hg/minute), opening of vacuum breaker valves (2 to 12 in. Hg/minute), and loss of one or more circulating water pumps (4 to 24 in. Hg/minute).
15.2.5.1.2      Frequency Classification This event is categorized as an incident of moderate frequency.
15.2.5.2       Sequence of Events and Systems Operation 15.2.5.2.1      Sequence of Events Table 15.2-7 lists the sequence of events for Figure 15.2-6.
15.2.5.2.2      Systems Operation It is conservatively assumed that condenser vacuum is lost at a rate of 2 inches of Hg per second. The bypass system is signaled to close approximately 10 inches of Hg less than the stop (throttle) valve closure vacuum setpoint level which means the bypass is available for approximately 5 sec before the turbine stop (throttle) valves close. The loss of vacuum initiates a main turbine trip and feedwater turbine trip. Upon reaching 90% close, the turbine throttle (stop) valves closure results in a reactor scram. As the reactor pressure increases, the relief valves will open. Subsequently, this results in the main steam line isolation valves to close. However, the effect of the MSIV closure is minimal since the turbine stop (throttle) valve and bypass valve closure have already terminated main steam line flow.
Tripping functions incurred by sensing main turbine condenser vacuum are designated in Table 15.2-8.
15.2-17

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.5.2.3      The Effect of Single Failures and Operator Errors Single failure will not effect the vacuum monitoring and turbine trip devices which are redundant. The protective sequences of the anticipated operational transient are shown to be single failure proof.
15.2.5.3       Core and System Performance 15.2.5.3.1      Mathematical Model The one-dimensional ODYN model described in Section 15.0.3.3.1 was used to simulate this transient event.
15.2.5.3.2      Input Parameters and Initial Conditions This analysis was performed with plant conditions tabulated in Table 15.0-2 and at 104.1% of uprated power and 100% core flow. Turbine stop (throttle) valves full stroke closure time used in this analysis is 0.1 second and a reactor scram is initiated by position switches on the stop valves when the valves are less than 90% open. The 2 inches of Hg per second assumed in the analysis is conservative with respect to normal loss of vacuum and no operator actions are assumed.
Thus, the bypass system is available for several seconds since the bypass is signaled to close at a vacuum level of about 10 in. Hg less than the stop valve closure.
15.2.5.3.3      Results The loss of condenser vacuum initiates a main turbine trip, which then initiates turbine bypass operation. The bypass is available for approximately 5 sec until both the turbine bypass valves and the main steam line isolation valves receive a signal to close on low condenser vacuum.
The effect of MSIV closure tends to be minimal since the closure of main turbine stop valves and subsequently the bypass valves have already shut off the main steam line flow.
Figure 15.2-6 shows the transient expected for this event. It is assumed that the plant is initially operating at 105% of uprated NBR steam flow conditions. Peak neutron flux reaches 256% of NBR power while average fuel surface heat flux reaches 111% of rated value. The SRVs open to limit the pressure rise then sequentially reclose as the stored energy is dissipated.
15.2.5.3.4      Consideration of Uncertainties The reduction or loss of vacuum in the main turbine condenser will sequentially trip the main and feedwater turbines and close the MSIVs and turbine bypass valves. While these are the major events occurring, other resultant actions will include scram (from stop valve closure) 15.2-18

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                        December 2011 and bypass opening with the main turbine trip. Because the protective actions are actuated at various levels of condenser vacuum, the severity of the resulting transient is dependent upon the rate at which the vacuum is lost. Normal loss of vacuum due to loss-of-cooling water pumps or steam jet air ejector problem produces a very slow rate of loss of vacuum (minutes, not seconds). If corrective actions by the reactor operators are not successful, then simultaneous trips of the main and feedwater turbines, and ultimately complete isolation by closing the bypass valves (opened with the main turbine trip) and the MSIVs, will occur.
A faster rate of loss of the condenser vacuum would reduce the anticipatory action of the scram and the overall effectiveness of the bypass valves since they would be closed more quickly.
Other uncertainties in these analyses involve protection system settings, system capacities, and system response characteristics. In all cases, the most conservative values are used in the analyses. For example:
: a.       Slowest allowable control rod scram motion is assumed,
: b.       Scram worth shape for all-rod-out conditions is assumed,
: c.       Minimum specified valve capacities are utilized for overpressure protection, and
: d.       Setpoints of the SRVs are assumed to be 15 psi higher than the valves nominal setpoint.
15.2.5.4        Barrier Performance The maximum calculated pressure for this event as presented in Table 15.0-1 is below the ASME Code limit of 1375 psig for the RCPB and the ASME Service Level C of 1500 psig.
The consequences of this event do not result in any temperature or pressure transient in excess of the criteria for which the fuel, pressure vessel, or containment are designed. Therefore, barrier integrity and function is maintained.
15.2.5.5        Radiological Consequences While the consequence of this event does not result in fuel failures, it does result in the discharge of normal coolant activity to the suppression pool by means of SRV operation. Since this activity is contained in the primary containment, there will be no exposure to the public.
Since this event does not result in an uncontrolled release to the environment, the plant operator can choose to hold the activity in containment or discharge it to the environment when conditions permit. If purging of the containment is chosen, the release would be in accordance with established requirements.
15.2-19

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.6      LOSS OF ALTERNATING CURRENT POWER This transient considers the loss of AC power to the plant from both an onsite cause (loss of auxiliary power transformer) and an offsite cause (loss of all grid connections).
This transient is classified as a nonlimiting event for both original and uprated power conditions. Therefore, cycle specific analyses are not performed for this event. The analysis results presented in the section are based on uprated power conditions and a representative reload core (Cycle 8) as documented in Reference 15.2-5.
15.2.6.1       Identification of Causes and Frequency Classification 15.2.6.1.1      Identification of Causes 15.2.6.1.1.1 Loss of Auxiliary Power Transformers. Causes for interruption or loss of the auxiliary power transformers can arise from normal operation or malfunctioning of transformer protection circuitry. These can include high transformer oil temperature, reverse of high current operation, and operator error which trips the transformer breakers.
15.2.6.1.1.2 Loss of All Grid Connections. Loss of all grid connections can result from major shifts in electrical loads, loss of loads, lightning, storms, wind, etc., which contribute to electrical grid instabilities. These instabilities will cause equipment damage if unchecked.
Protective relay schemes automatically disconnect electrical sources and loads to mitigate damage and regain electrical grid stability.
15.2.6.1.2      Frequency Classification 15.2.6.1.2.1 Loss of Auxiliary Power Transformers. This event is categorized as an incident of moderate frequency.
15.2.6.1.2.2 Loss of All Grid Connections. This event is categorized as an incident of moderate frequency.
15.2.6.2       Sequence of Events and Systems Operation 15.2.6.2.1      Sequence of Events 15.2.6.2.1.1 Loss of Auxiliary Power Transformers. Table 15.2-9 lists the sequence of events for Figure 15.2-7.
15.2.6.2.1.2 Loss of All Grid Connections. Table 15.2-10 lists the sequence of events for Figure 15.2-8.
15.2-20

COLUMBIA GENERATING STATION                         Amendment 61 FINAL SAFETY ANALYSIS REPORT                        December 2011 15.2.6.2.2      Systems Operation 15.2.6.2.2.1 Loss of Auxiliary Power Transformers. This event, unless otherwise stated, assumes and takes credit for normal functioning of plant instrumentation and controls, plant protection, and reactor protection systems.
The reactor is subjected to a complex sequence of events when the plant loses all auxiliary power. Estimates of the responses of the various reactor systems (assuming loss of the auxiliary transformers) provide the following simulation sequence:
: a.      Recirculation pumps and condenser circulatory water pumps trip off at time = 0. A 4 sec recirculation pump trip inertia time constant is assumed for this analysis;
: b.      Reactor scram and MSIV closure is initiated at 2 sec due to loss of power to the scram and MSIV relay solenoids; and
: c.      Feedwater turbines trip off at 4 sec due to MSIV closure at 2 sec.
Operation of the HPCS and RCIC are not simulated in this analysis. Their operation occurs at a time beyond the primary concerns of fuel thermal margin and overpressure effects of this analysis.
15.2.6.2.2.2 Loss of All Grid Connections. Same as Section 15.2.6.2.2.1 with the following additional concern.
The loss of all grid connections would add a generator load rejection to the above sequence at time, t=0. The load rejection immediately causes the TCVs (governor valves) to close, causes a scram, and initiates RPT [already tripped at reference time t = 0].
15.2.6.2.3      The Effect of Single Failures and Operator Errors Loss of the auxiliary power transformers in general leads to a reduction in power level due to rapid pump coastdown with pressurization effects due to MSIV closure resulting from loss of power to the solenoids. Additional failures of the other systems assumed to protect the reactor would not result in an effect different from those reported. Failures of the protection systems have been considered and satisfy single failure criteria and, as such, no change in analyzed consequences is expected.
15.2-21

COLUMBIA GENERATING STATION                        Amendment 61 FINAL SAFETY ANALYSIS REPORT                       December 2011 15.2.6.3      Core and System Performance 15.2.6.3.1     Mathematical Model The point-kinetics REDY model described in Section 15.0.3.3.1 was used to simulate this event.
15.2.6.3.2     Input Parameters and Initial Conditions 15.2.6.3.2.1 Loss of Auxiliary Power Transformers. It is assumed the loss of the auxiliary power transformer occurs with the plant operating at 106% of uprated power and 100% core flow. The input parameters are defined with the plant conditions tabulated in Table 15.0-2 except as noted below.
: a.      The recirculation pump trip inertia time constant is 4 sec.
: b.      The relay-type Reactor Trip System (RTS) circuitry generates a reactor scram and Main Steam Isolation Valves (MSIV) closure signal due to loss of power to the scram and MSIV solenoids. This occurs 2 sec after the loss of offsite power.
: c.      The feedwater pumps trip due to MSIV closure 2 sec after the MSIV begin to close as a result of the loss of power to the MSIV solenoids.
15.2.6.3.2.2 Loss of All Grid Connections. It is assumed the loss of all grid connections occurs with the plant operating at 104% of uprated power and 100% core flow. The input parameters are defined with the plant conditions tabulated in Table 15.0-2 except as noted below.
: a.      The recirculation pump trip inertia time constant is 4 sec.
: b.      The relay-type Reactor Trip System (RTS) circuitry generates a Main Steam Isolation Valves (MSIV) closure signal due to loss of power to the MSIV solenoids. This occurs 2 sec after the loss of offsite power.
: c.      The feedwater pumps trip due to MSIV closure 2 sec after the MSIV begin to close as a result of the loss of power to the MSIV solenoids.
15.2.6.3.3     Results 15.2.6.3.3.1 Loss of Auxiliary Power Transformers. Initially the offsite power is cutoff causing both recirculation pumps to trip. The loss of power to the scram and MSIV solenoids causes a reactor scram, MSIV isolation and a feedwater pump trip 2 sec after the MSIV 15.2-22

COLUMBIA GENERATING STATION                            Amendment 61 FINAL SAFETY ANALYSIS REPORT                           December 2011 isolation. Subsequently, the feedwater recirculation valves trip and the relief valves begin to open due to the rising pressure caused by the main steam line isolation. Table 15.2-9 provides the sequence of events and Figure 15.2-7 depicts the plant parameters responses. Key transient peak values are presented in Table 15.0-1. This event is non-limiting in that the pressurization event and change in MCPR margin are less severe than the Generator Load Rejection with Bypass Failure and Turbine Trip with Bypass Failure events.
15.2.6.3.3.2 Loss of All Grid Connections. Loss of all grid connections is a more general form of loss of auxiliary power. It essentially takes on the characteristic response of the standard full load rejection discussed in Section 15.2.2. Initially the offsite power is cutoff to the grid causing the turbine-generator to detect a loss of electrical load, and a power-load unbalance. The turbine generator overspeed protection control (OPC) initiates a control (governor) valve fast closure, turbine bypass valves opening and a reactor scram. At the same time both recirculation pump motors trip. Subsequently, MSIV isolation occurs and both feedwater pumps trip. The rising pressure due to the isolation of the steam line causes the relief valves to open. Table 15.2-10 provides the sequence of events and Figure 15.2-8 depicts the plant parameter responses. Key transient peak values are presented in Table 15.0-1. This event is non-limiting in that the pressurization event and change in MCPR margin are less severe than the Generator Load Rejection with Bypass Failure and Turbine Trip with Bypass Failure events.
15.2.6.3.4      Consideration of Uncertainties The most conservative characteristics of protection features are assumed. Any actual deviations in plant performance are expected to make the results of this event less severe.
Operation of the HPCS and RCIC systems are not included in the simulation of the first 50 sec of this transient. Startup of the pumps occurs in the latter part of this time period but the system has no significant effect on the results of this transient.
Following main steam line isolation and prior to RHR initiation the reactor pressure is expected to increase until the SRV setpoints are reached. During this time the valves operate in a cyclic manner to discharge decay heat to the suppression pool.
15.2.6.4       Barrier Performance 15.2.6.4.1      Loss of Auxiliary Power Transformers Safety/relief valves open in the pressure relief mode of operation as the pressure increases beyond their setpoints. The pressure in the dome is limited to a maximum value of 1169 psig well below the vessel pressure limit of 1375 psig.
15.2-23

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.6.4.2      Loss of All Grid Connections Safety/relief valves open in the pressure relief mode of operation as the pressure increases beyond their setpoints. The pressure in the dome is limited to a maximum value of 1173 psig well below the vessel pressure limit of 1375 psig.
15.2.6.5       Radiological Consequences The consequence of this event does not result in fuel failure. It does result in the discharge of normal coolant activity to the suppression pool by means of SRV operation, which is contained in the primary containment. This event does not result in an uncontrolled release to the environment, so the plant operator can choose to hold the activity in containment or discharge it when conditions permit. If purging of the containment is chosen, the release would be in accordance with established requirements.
15.2.7      LOSS-OF-FEEDWATER FLOW This transient is classified as a nonlimiting event for both original and uprated power conditions. Therefore, cycle specific analyses are not performed for this event. The analysis results presented in the section are based on uprated power conditions and a representative reload core (Cycle 8) as documented in Reference 15.2-5. The analysis has not been updated for the change in MSIV isolation setpoint from Level 2 to Level 1 because the analysis is bounding and conclusions of the analysis are not affected (Reference 15.2-8).
15.2.7.1       Identification of Causes and Frequency Classification 15.2.7.1.1      Identification of Causes A loss of feedwater flow could occur from pump failures, feedwater controller failures, operator errors, or reactor system variables such as a high vessel water level (L8) trip signal.
15.2.7.1.2      Frequency Classification This event is categorized as an incident of moderate frequency.
15.2.7.2       Sequence of Events and Systems Operation 15.2.7.2.1      Sequence of Events Feedwater flow terminates at approximately 5 sec. Subcooling decreases causing a reduction in core power level and pressure. As power level is lowered, the turbine steam flow starts to drop off. Water level continues to drop until the vessel level (L3) scram trip setpoint is reached, whereupon the reactor is shut down.
LDCN-09-007                                    15.2-24

COLUMBIA GENERATING STATION                            Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 Main steam line isolation initiation occurs due to vessel water dropping to the L2 trip. Also at this time, the recirculation system is tripped and HPCS and RCIC operation is initiated.
Operation of the HPCS and RCIC systems is not included in the simulation of the first 50 seconds of this transient since startup of the pumps occurs in the latter part of this time period. Therefore, the system has no significant effects on the results of this transient.
Table 15.2-11 lists the sequence of events for Figure 15.2-9.
15.2.7.2.2      Systems Operation Loss of feedwater flow results in a proportional reduction of vessel inventory causing the vessel water level to drop. The first corrective action is the low level (L3) scram trip actuation. Reactor protection system responds after this trip to scram the reactor. The low level (L3) scram trip function meets single failure criterion.
Vessel water level (L2) trip initiates main steam line isolation, recirculation pump trip and HPCS/RCIC system operation (not simulated). The recirculation pump motor circuit breakers then open causing decrease in core flow to natural circulation.
15.2.7.2.3      The Effect of Single Failures and Operator Errors The nature of this event results in a lowering of vessel water level. Key corrective efforts to shut down the reactor are automatic and designed to satisfy single failure criterion. Therefore, any additional failure in these shutdown methods would not aggravate or change the simulated transient.
The potential exists for a single relief valve failing to close once it is opened. This would result in a complete depressurization of the reactor. Either the RCIC or the HPCS system is capable of maintaining adequate core coverage and will provide long-term inventory control.
For the complete loss of feedwater flow event, operation of RCIC or HPCS is sufficient to avoid initiation of ADS on low vessel level (L1).
15.2.7.3       Core and System Performance 15.2.7.3.1      Mathematical Model The point-kinetics REDY model described in Section 15.0.3.3.1 was used to simulate this event.
15.2-25

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 15.2.7.3.2      Input Parameters and Initial Conditions The simultaneous trip of both feedwater pumps is assumed to occur while the plant is operating at 106% uprated power and 100% core flow. These analyses have been performed, unless otherwise noted, with plant conditions tabulated in Table 15.0-2.
15.2.7.3.3      Results Table 15.2-11 provides the sequence of events and Figure 15.2-9 depicts the plant parameter responses. Key transient peak values are presented in Table 15.0-1. This event is non-limiting in that the pressurization event and change in MCPR are less severe than the Generator Load Rejection with Bypass Failure and Turbine Trip with Bypass Failure events.
15.2.7.3.4      Consideration of Uncertainties End-of-cycle scram characteristics are assumed.
This transient is most severe from high power conditions, because the rate of level decrease is greatest and the amount of stored decay heat to be dissipated is highest.
15.2.7.4       Barrier Performance Peak pressure in the bottom of the vessel reaches 1152 psig, which is below the ASME Code limit of 1375 psig for the RCPB. Vessel dome pressure does not exceed 1142 psig. The consequences of this event do not result in any temperature or pressure transient in excess of the criteria for which the fuel, pressure vessel, or containment are designed. Therefore, barrier integrity and function are maintained.
15.2.7.5       Radiological Consequences The consequence of this event does not result in fuel failure. It does result in the discharge of normal coolant activity to the suppression pool by means of SRV operation, which is contained in the primary containment. This event does not result in an uncontrolled release to the environment, so the plant operator can choose to hold the activity in containment or discharge it when conditions permit. If purging of the containment is chosen the release will be in accordance with established requirements.
15.2.8      FEEDWATER LINE BREAK See Section 15.6.6.
15.2-26

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.9       FAILURE OF RESIDUAL HEAT REMOVAL SHUTDOWN COOLING This transient is classified as a nonlimiting event for both original and uprated power conditions.
Normally, in evaluating component failures associated with the RHR shutdown cooling mode of operation, active pumps or instrumentation (all of which are redundant for the safety related portions of the RHR system) would be assumed to be the component failure. For purposes of a worst case analysis, a valve on the single recirculation suction line to the otherwise redundant RHR shutdown cooling loops is assumed to fail. Manual attempts to open the valve are assumed unsuccessful. Discovery is conservatively assumed to occur at 100 psig. This envelops discovery at normal RHR shutdown cooling operating limits (see Section 5.4.7).
This failure disables the shutdown cooling mode but does not affect the remaining RHR modes of operation. Reference 15.2-1 establishes additional assumptions.
15.2.9.1        Identification of Causes and Frequency Classification 15.2.9.1.1       Identification of Causes The plant is operating at 105% of original NBR steam flow when an event occurs, e.g., a long-term loss of offsite power, causing a plant shutdown. Reactor vessel depressurization is initiated to bring the reactor pressure to approximately 100 psig. Concurrent with the loss of offsite power a failure of a valve in the shutdown cooling suction line occurs which prevents the operator from establishing the normal shutdown cooling path through the RHR shutdown cooling lines. An additional failure is assumed which completely disables the RHR equipment in one division. The operator then establishes a shutdown cooling path for the vessel through the SRV valves.
15.2.9.1.2       Frequency Classification This event is categorized as an incident of moderate frequency.
15.2.9.2        Sequence of Events and Systems Operation 15.2.9.2.1       Sequence of Events The sequence of events for this event is shown in Table 15.2-12.
15.2-27

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.9.2.1.1 Identification of Operator Actions. For the early part of the transient, the operator actions are to restore and maintain reactor water level. The operator should reestablish reactor cooling by one or more of the following:
: a.      Maintain reactor water inventory with the RCIC (when single failure is not assumed to be a loss of Division 1 dc power) and HPCS systems,
: b.      At approximately 10 minutes into the transient, initiate suppression pool cooling, it is assumed that only one RHR heat exchanger is available,
: c.      Initiate RPV shutdown depressurization by manual actuation of the SRVs,
: d.      Attempts to open one of the two RHR shutdown cooling suction valves are assumed unsuccessful (reactor pressure is approximately 100 psig), and
: e.      Continue RPV depressurization by opening SRVs and establish a reactor cooling path as described in the notes for Figure 15.2-10.
Time required to initiate the necessary steps to maintain reactor pressure and level control is approximately 10 minutes.
15.2.9.2.2      Systems Operation Plant instrumentation and control is assumed to be functioning normally except as noted. In this evaluation credit is taken for the plant and reactor protection systems and/or the ESF used.
15.2.9.2.3      The Effect of Single Failures and Operator Errors The worst case single failure (loss of division power) has already been analyzed in this event.
Therefore, no single failure or operator error can increase the consequences of this event.
15.2.9.3       Core and System Performance The earliest time the shutdown cooling system can be actuated is 2 to 3 hr after shutdown is initiated. During this time MCPR remains high and nucleate boiling heat transfer is not exceeded at any time. Therefore, the core thermal safety margin remains essentially unchanged. The 10-minute time period approximated for operator action is an estimate of how long it would take the operator to initiate the necessary actions. It is not a time by which action must be initiated.
The transient behavior of the core during this event has been evaluated in Section 15.2.6.
15.2-28

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 15.2.9.4       Results For most single failures that could result in loss of shutdown cooling, no unique safety actions are required. In these cases, shutdown cooling is simply reestablished using the redundant shutdown cooling loop. In cases where the RHR shutdown cooling suction line valves cannot be opened, alternate paths are available to accomplish the shutdown cooling function (Figure 15.2-11). An evaluation has been performed assuming a failure that disables the RHR shutdown cooling suction line valves.
This evaluation demonstrates the capability to safely transfer fission product decay heat and other residual heat from the reactor core at a rate such that specified acceptable fuel design limits and the design conditions of the RCPB are not exceeded.
The alternate cooldown path chosen to accomplish the shutdown cooling function uses the RHR and ADS or normal relief valve systems (see Reference 15.2-1 and Figure 15.2-10).
The alternate shutdown systems are capable of performing the function of transferring heat from the reactor to the environment using only safety systems. The systems are capable of bringing the reactor to a cold shutdown in approximately 36 hr or less after the transient occurs.
The systems have suitable redundancy in components such that even for onsite electrical power operation (offsite power is not available), the safety function of the systems can be accomplished assuming an additional single failure. The systems can be fully operated from the main control room.
The design evaluation is divided into two phases: (a) full power operation to approximately 100 psig vessel pressure, and (b) approximately 100 psig vessel pressure to cold shutdown (14.7 psia 200&deg;F) conditions.
15.2.9.4.1      Full Power to Approximately 100 psig Independent of the event that initiated plant shutdown (whether it be a normal plant shutdown or a forced plant shutdown), the reactor is normally brought to approximately 100 psig using either the main condenser or, in the case where the main condenser is unavailable, the HPCS and RCIC systems together with the nuclear boiler pressure relief system and the RHR heat exchanger in the suppression pool cooling mode.
For evaluation purposes, however, it is assumed that plant shutdown is initiated by a transient event (loss of offsite power) which results in relief valve actuation and subsequent suppression pool heatup. For this postulated condition, the reactor is shut down and the reactor vessel pressure is reduced to approximately 100 psig. Manual operation of the SRVs is used to depressurize the reactor vessel. Reactor vessel makeup water is automatically provided by means of the RCIC (until reduced vessel pressure is reached) and HPCS systems. While in 15.2-29

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 this condition, the RHR system (suppression pool cooling mode) is used to maintain the suppression pool temperature within shutdown limits.
These systems are designed to routinely perform their functions for both normal and forced plant shutdown. Since the HPCS and RHR systems are divisionally separated and the HPCS and RCIC systems are divisionally separated, no single failure together with the loss of offsite power, is capable of preventing reaching the 100 psig level.
15.2.9.4.2       Approximately 100 psig to Cold Shutdown The following assumptions are used for the analyses of the procedures for attaining cold shutdown from a pressure of approximately 100 psig:
: a.      The vessel is at 100 psig and saturated conditions,
: b.      A worst-case single failure is assumed to occur (i.e., loss of a division of emergency power), and
: c.      There is no offsite power available.
In the event that the RHRs shutdown suction line is not available because of single failure, the first action to be taken will be to control reactor pressure. If a single electrical failure caused the suction line to fail in the closed position, a hand wheel is provided on the valve to allow manual operation. If for some reason the normal shutdown cooling suction line cannot be restored to service, the capabilities described below will satisfy the normal shutdown cooling requirements and thus fully comply with GDC 34.
The RHR shutdown cooling line valves are in two divisions (Division 1 - the outboard valve, and Division 2 - the inboard valve) to satisfy containment isolation criteria. For evaluation purposes, the worst-case failure is assumed to be the loss of a division of emergency power, since this also prevents electrical actuation of one shutdown cooling line valve. Engineered safety features equipment and safe shutdown RCIC equipment (until reduced reactor pressure is reached) available for accomplishing the shutdown cooling function include (for the selected path):
ADS (dc Division 1 and dc Division 2)
RHR Loop A (Division 1)
HPCS (Division 3) 15.2-30

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 RCIC (dc Division 1)
LPCS (Division 1)
Since availability or failure of Division 3 equipment does not affect the normal shutdown mode, normal shutdown cooling is easily available through equipment powered from only Divisions 1 and 2. It should be noted that, HPCS is always available for coolant injection if either of the other two divisions fails. For failure of Division 1 or 2, the following systems are assumed functional:
: a.      Division 1 Fails, Division 2 and 3 Functional Failed Systems         Functional Systems RHR Loop A             HPCS LPCS                   ADS RCIC                   RHR Loops B and C Assuming the single failure is a failure of Division 1 emergency power, the safety function is accomplished by establishing one of the cooling loops described in Activity C1 of Figure 15.2-10.
: b.      Division 2 Fails, Division 1 and 3 Functional Failed Systems         Functional Systems RHR Loop B and C HPCS ADS RHR Loop A LPCS RCIC (until reduced reactor pressure is reached)
Assuming the single failure is the failure of Division 2, the safety function is accomplished by establishing one of the cooling loops described in Activity C2 of Figure 15.2-10.
Figures 15.2-12 through 15.2-15 show RHR loops A, B, and/or C (simplified).
15.2.9.4.3      Temperature Response - 3462 MWt The reactor vessel temperature and pressure response versus time for the core conditions defined in Table 15.2-13 (105% of original rated steam flow, 3462 MWt rated power) are presented in Figures 15.2-16 and 15.2-17. Figure 5.2-16 presents the results for 15.2-31

COLUMBIA GENERATING STATION                            Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 Activity C1.b.1 or C2 described in Figure 15.2-10. Figure 5.2-17 presents the results for Activity C1.b.2. The bulk suppression pool temperature responses from the same analysis are presented in Figures 15.2-18 and 15.2-19. Figure 5.2-18 presents the results for Activity C1.b.1 or C2 and Figure 5.2-19 presents the results for Activity C1.b.2.
15.2.9.4.4      Temperature Response - 3702 MWt Reference 15.2-7 analyzed the same two scenarios (Activities C2 and C1.b.2) for 106.2% of power uprate conditions (3702 MWt) to determine the peak bulk suppression pool temperature and the time required to cool the reactor vessel to cold shutdown (14.7 psia and 200&deg;F). The analysis at power uprate conditions calculated a relative 4&deg;F increase in the peak bulk pool temperature due to the power uprate. However, the peak temperature calculated was lower than the temperatures presented in this section due to the use of more realistic assumptions.
These assumptions include a more realistic decay heat model, lower initial suppression pool temperature (90&deg;F), and more realistic treatment of pump heat addition.
15.2.9.5       Barrier Performance As noted above, the consequences of this event do not result in any temperature or pressure transient in excess of the criteria for which the fuel, pressure vessel, or containment are designed. Release of coolant to the containment occurs by means of SRV actuation.
15.2.9.6       Radiological Consequences The consequence of this event does not result in fuel failure. It does result in the discharge of normal coolant activity to the suppression pool by means of SRV operation, which is contained in the primary containment. This event does not result in an uncontrolled release to the environment, so the plant operator can choose to hold the activity in containment or discharge it when conditions permit. If purging of the containment is chosen, the release would be in accordance with established requirements.
15.2.10     REFERENCES 15.2-1          Letter - R. S. Boyd to I. F. Stuart; dated November 12, 1975. 

==Subject:==

Requirements delineated for RHRS - Shutdown Cooling System - Single Failure Analysis.
15.2-2          NEDC-24154-P-A, Qualification of the One-Dimensional Core Transient Model for Boiling Water Reactors, Volumes 1, 2, 3 and 4, February 2000.
15.2-3          Supplemental Reload Licensing Report for Columbia (most recent version referenced in COLR).
15.2-32

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                       December 2015 15.2-4      R. B. Linford, Analytical Methods of Plant Transient Evaluations for the General Electric Boiling Water Reactor, NEDO 10802, April 1973.
15.2-5      For Power Uprate: GE Nuclear Energy, WNP-2 Power Uprate Transient Analysis Task Report, GE-NE-208-08-0393, September 1993 (Proprietary).
15.2-6      Deleted.
15.2-7      GE Nuclear Energy, WNP-2 Power Uprate Project NSSS Engineering Report, GE-NE-208-17-0993, Revision 1, December 1994 (Proprietary).
15.2-8      AREVA NP, Inc., Columbia Generating Station MSIV Closure Level Setpoint Change - Loss of Feedwater Flow Transient Analysis, 51-9084418-000, July 2008.
15.2-9      GE Hitachi Nuclear Energy, License Amendment Request for Proposed Changes to Columbia Technical Specifications: Changing Group 1 Isolation Valves Low Reactor Water Level Isolation Signal from the Current Level 2 to Level 1, 0000-0081-6730-R1, July 2008.
15.2-10     NEDE-32906P-A, TRACG Application for Anticipated Operational Occurrences Transient Analyses, Revision 3, September 2006.
LDCN-15-011                             15.2-33

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                        December 2011 Table 15.2-1 Sequence of Events for Figure 15.2-1 Pressure Regulator Failure - Closed 104.1% Uprated Power - 106% Flow Time (sec)                                Event 0        Failure of the pressure regulator causes closure of the turbine control valves.
1.0      Scram signal initiated at high neutron flux.
2.0      Recirculation pump motor circuit breakers open causing decrease in core flow to the natural circulation.
2.56     Group 3 relief valves actuated.
2.67     Group 4 relief valves actuated.
2.77     Group 5 relief valves actuated.
2.84     Turbine control valves close.
15.2-35

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                       December 2011 Table 15.2-2 Sequence of Events for Figure 15.2-2.1 Generator Load Rejection with Bypass On Original Rated Power Time (sec)                                    Event
(-)0.015a    Turbine generator detection of loss of electrical load.
0         Turbine generator overspeed protection control (OPC) devices trip to initiate turbine control (governor) valve fast closure.
0         Turbine generator OPC trip initiates main turbine bypass system operation.
0         Fast control valve closure initiates scram trip.
0         Fast control valve closure initiates an RPT.
0.07      Turbine control valves closed.
0.11      Turbine bypass valves start to open.
0.19      Recirculation pump motor circuit breakers open causing decrease in core flow to natural circulation.
1.70      Group 1 relief valves actuated.
1.86      Group 2 relief valves actuated.
2.01      Group 3 relief valves actuated.
2.27      Group 4 relief valves actuated.
a Approximately.
15.2-36

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                      December 2015 Table 15.2-3 Typical Sequence of Events for Figure 15.2-2.2 Generator Load Rejection with Bypass Failure 100% Power 106% Flow Time (sec)                                         Event
(-)0.003a          Turbine generator detection of loss of electrical load.
0               Turbine generator OPC devices trip to initiate turbine control (governor) valve fast closure.
0               Turbine bypass valves fail to operate.
0.03            Time of scram trip.
0.15            Turbine control valves fully closed.
0.20            Time of RPT trip.
0.28            Start of control blade motion.
(b)               Group 1 MSRVs actuated (safety function).
(b)               Group 2 MSRVs actuated (safety function).
2.83            Group 3 MSRVs actuated (safety function).
3.17            Group 4 MSRVs actuated (safety function).
a Approximately.
b Not used - out of service for this analysis.
LDCN-15-011                                    15.2-37

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                        December 2011 Table 15.2-4 Sequence of Events for Figure 15.2-3 Turbine Trip, Trip Scram - Bypass and RPT On Original Rated Power Time (sec)                                           Event 0                Turbine trip initiates closure of main stop (throttle) valves.
0                Turbine trip initiates bypass operation.
0.01             Main turbine stop valves reach 90% open position and initiate reactor scram trip.
0.01             Main turbine stop valves reach 90% open position and initiate an RPT.
0.10             Turbine stop valves closed.
0.10             Turbine bypass valves start to open to regulate pressure.
0.20             Recirculation pump motor circuit breakers open causing decrease in core flow to natural circulation.
1.63             Group 1 relief valves actuated.
1.78             Group 2 relief valves actuated.
1.94             Group 3 relief valves actuated.
2.14             Group 4 relief valves actuated.
2.50             Group 5 relief valves actuated.
4.67             Feedwater turbines trip on L8 high water level.
5.1a             Group 5 relief valves start to close.
7.2a             All relief groups closed.
31.0              Turbine bypass starts to close.
32.3a             Turbine bypass closed.
39.7              Turbine bypass reopens on pressure increase at turbine inlet.
45.3              Main steam line isolationb, HPCS system initiation, and RCIC system initiation on low level (L2) (not included in simulation).
50+               Group 1 relief valves cycle open and close on pressure.
a Estimated.
b The analysis has not been updated for the change in MSIV isolation setpoint from Level 2 to Level 1 because the analysis is bounding and conclusions of the analysis are not affected (Reference 15.2-9).
LDCN-09-007                                    15.2-38

COLUMBIA GENERATING STATION                            Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 Table 15.2-5 Sequence of Events for Figure 15.2-4 Turbine Trip with Bypass Failure at 100% Power/106% Core Flow Time (sec)                                           Event 0               Turbine trip initiates closure of main stop (throttle) valves.
0               Turbine bypass valves fail to operate.
0.01            Main turbine stop valves reach 90% open position and initiate reactor scram trip.
0.10            Turbine stop valves closed.
0.20            Recirculation pump motor circuit breakers open causing decrease in core flow to natural circulation.
(a)               Group 1 relief valves actuated.
(a)               Group 2 relief valves actuated.
2.83            Group 3 relief valves actuated.
3.18            Group 4 relief valves actuated.
a Not used - out of service for this analysis.
15.2-39

COLUMBIA GENERATING STATION                         Amendment 61 FINAL SAFETY ANALYSIS REPORT                       December 2011 Table 15.2-6 Sequence of Events for Figure 15.2-5 Main Steam Line Isolation Valve Closure 106.2% Uprated Power, 100% Rated Flow Time (sec)                                        Event
(-) 0.003 (approximately)    Turbine-Generator detection of loss of electrical load.
0               Initiate closure of all main steam line valves.
0.45              MSIVs reach 85% opening initiating a position valve scram.
2.0              Loss of feedwater begins as turbine loses steam supply.
2.53              Both recirculation pumps trip due to high pressure.
3.0              All MSIVs closed.
3.08              Groups 3 relief valves actuated.
3.16              Groups 4 relief valves actuated.
3.24              Groups 5 relief valves actuated.
11 (approx.)          All pressure relieve valves closed.
18.23              Groups 3 relief valves begin to cycle.
15.2-40

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                       December 2011 Table 15.2-7 Sequence of Events for Figure 15.2-6 Loss of Condenser Vacuum 104.1% Uprated Power, 100% Rated Flow Time (sec)                                        Event
(-)5.0 (approximately)    Initiate simulated loss of condenser vacuum at 2 in. of Hg per second.
0.00            Low condenser vacuum main turbine trip and feedwater turbine trips initiated.
0.00            Main turbine trip initiates turbine bypass operation.
0.01            Main turbine stop valves reach 90% open position and initiate reactor scram.
0.19            Both recirculation pumps trip.
2.15            Group 3 relief valves actuated.
2.28            Group 4 relief valves actuated.
2.42            Group 5 relief valves actuated.
2.91            Feedwater recirculation valve is tripped.
5.00            Low condenser vacuum initiates turbine bypass valve closure and MSIV closure.
5.6 (approx.)        All relief valves closed.
6.0 (approx.)        Main steam isolation valves closed.
7.90            Group 3 relief valves reactuated.
8.35            Group 4 relief valves reactuated.
24.01            Group 5 relief valves reactuated.
15.2-41

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                       December 2011 Table 15.2-8 Trip Signals Associated with Loss-of-Condenser Vacuum Vacuuma                                Protective Action Initiated 27 to 30          Normal vacuum range.
20 to 23          Main turbine trip and feedwater turbine trip (stop valve closures).
7 to 10          Main steam line isolation valve closure and bypass valve closure.
a Inches of Hg.
15.2-42

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                        December 2011 Table 15.2-9 Sequence of Events for Figure 15.2-7 Loss of Auxiliary Power Transformers 106.2% Uprated Power, 100% Rated Flow Time (sec)                                 Event 0.00     Loss of auxiliary power transformers occurs.
0.00     Recirculation system pump motors are tripped.
2.00     Reactor scram due to loss of power to the scram solenoid.
2.00     Main steam line isolation valves begin to close due to loss of power to MSIV solenoids.
4.00     Feedwater pumps are tripped due to MSIV closure.
5.98     Group 3 relief valves actuated.
6.15     Group 4 relief valves actuated.
6.34     Group 5 relief valves actuated.
15.2-43

COLUMBIA GENERATING STATION                            Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 Table 15.2-10 Sequence of Events for Figure 15.2-8 Loss of All Grid Connections 104.1% Uprated Power, 100% Rated Flow Time (sec)                                    Event 0.00    Loss of grid causes turbine-generator to detect a loss of electrical load.
0.00    Turbine-generator PLU devices trip to initiate TCV fast closure and turbine bypass system operation.
0.00    Recirculation pumps trip.
0.00    Fast control valve closure initiates reactor scram.
2.00    Main steam line isolation is initiated due to loss of power to the solenoids.
2.12    Group 3 relief valves actuated.
2.25    Group 4 relief valves actuated.
2.37    Group 5 relief valves actuated.
4.00    Feedwater pump tripped due to MSIV closure.
15.2-44

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                       December 2011 Table 15.2-11 Sequence of Events for Figure 15.2-9 Loss of All Feedwater Flow 106.2% Uprated Power, 100% Rated Flow Time (sec)                                          Event 0            Initiate trip of all feedwater pumps.
3.91         Recirculation runback initiated with narrow range sensed level less than L4 and feedwater pumps off.
7.38         Vessel water level (L3) trip initiates scram trip.
32.32          Vessel water level (L2) trip initiates main steam line isolationa, recirculation pump trip and HPCS/RCIC system operation (not simulated).
32.51          Recirculation pump motor circuit breakers open causing decrease in core flow to natural circulation.
a The analysis has not been updated for the change in MSIV isolation setpoint from Level 2 to Level 1 because the analysis is bounding and conclusions of the analysis are not affected (Reference 15.2-8).
LDCN-09-007                                   15.2-45

COLUMBIA GENERATING STATION                         Amendment 61 FINAL SAFETY ANALYSIS REPORT                      December 2011 Table 15.2-12 Sequence of Events for Failure of Residual Heat Removal Shutdown Cooling Original Rated Power Timea                                         Event 0                Reactor is operating at 105% NBR steam flow when LOP transient occurs initiating plant shutdown.
0                Concurrently loss of division power occurs (i.e., loss of one diesel generator).
0                Initial suppression pool temperature at 95&deg;F.
10 minutes       Suppression pool cooling initiated to prevent overheating from SRV actuation.
10 minutes       Controlled blowdown initiated.
2-3 hr           Blowdown to 100 psi completed.
2-3 hr           Personnel are sent in to open RHR shutdown cooling suction valve and fail.
2.5-3.5 hr       Complete blowdown to suppression pool by opening SRVs.
2.5-3.5 hr       Redirect RHR pump discharge from pool to vessel by means of the LPCI line. Alternate cooling path now established.
7 hr             Maximum suppression pool temperature attained.
a Approximately.
15.2-46

COLUMBIA GENERATING STATION                        Amendment 61 FINAL SAFETY ANALYSIS REPORT                     December 2011 Table 15.2-13 Evaluation of Failure of Residual Heat Removal Shutdown Cooling Parameter                                      Value Initial power corresponding                        105% original rated steam flow To suppression pool mass (lbm)                     8.52 E6 Residual heat removal (KHX value)                  289 (Btu/sec/&deg;F)
Initial vessel condition Pressure (psia)                                 1055 Temperature (&deg;F)                                550.7 Initial primary fluid inventory (lbm)              7.016 E5 Initial pool temperature (&deg;F)                      95 Service water temperature (&deg;F)                     87 Vessel heat capacity (Btu/lbm/&deg;F)                  0.123 High-pressure core spray on-off water level (ft)
HPCS ON                                         40.8 HPCS OFF                                        47 High-pressure core spray flow rate                 868 (lbm/sec)
Low-pressure coolant injection flow rate           982 (lbm/sec) 15.2-47

Amendment 59 December 2007 Pressure Regulator Failure - Down Scale Failure Columbia Generating Station         at 104.1% Uprated Power, 106% Flow Final Safety Analysis Report Draw. No. 060108.06   Rev. Figure 15.2-1 Form No. 960690 LDCN-07-011

Amendment 59 December 2007 Generator Load Rejection with Bypass On -
Columbia Generating Station                    Original Rated Power Final Safety Analysis Report Draw. No. 020361.68       Rev. Figure 15.2-2.1 Form No. 960690 LDCN-07-011

Amendment 53 November 1998 Turbine Trip, Trip Scram, Bypass and RPT - On Columbia Generating Station Final Safety Analysis Report Draw. No. 020361.70   Rev. Figure 15.2-3

Amendment 60 December 2009 300.0                                                                                                              275.0 Vessel Press Rise (psi)
Neutron Flux                                                                                            Safety Valve Flow Average Surface Heat Flux                                                                               Relief Valve Flow Bypass Valve Flow Core Inlet Flow                                                           225.0 250.0 Core Inlet Subcooling 200.0                                                                                                              175.0
    % Rated                                                                                               % Rated 150.0                                                                                                              125.0 100.0                                                                                                               75.0 50.0                                                                                                             25.0 0.0                                                                                                            -25.0 0.0      1.0     2.0     3.0         4.0      5.0       6.0      7.0                                             0.0      1.0    2.0          3.0       4.0       5.0          6.0        7.0 Time (sec)                                                                                                            Time (sec) 125.0                                                                                                          2.5 Level - Inch above Sep Skirt Vessel Steam Flow Turbine Steam Flow                                                      2.0 Feedwater Flow 100.0 1.5 Void Reactivity Doppler Reactivity 75.0 Scram Reactivity 1.0 Reactivity Components ($)
Total Reactivity 50.0                                                                                                         0.5
       % Rated 0.0 25.0
                                                                                                                                -0.5 0.0
                                                                                                                                -1.0
                  -25.0
                                                                                                                                -1.5
                  -50.0                                                                                                         -2.0 0.0      1.0     2.0    3.0         4.0      5.0         6.0    7.0                                          0.0      1.0     2.0          3.0       4.0        5.0          6.0        7.0 Time (sec)                                                                                                         Time (sec)
Turbine Trip with Bypass Failure Columbia Generating Station Final Safety Analysis Report Draw. No.                                020361.71                Rev.                Figure    15.2-4 Form No. 960690 LDCN-08-035

Amendment 59 December 2007 Main Steam Line Isolation Valve Closure Columbia Generating Station     at 106.2% Uprated Power, 100% Rated Flow Final Safety Analysis Report Draw. No. 020361.72  Rev.      Figure 15.2-5 Form No. 960690 LDCN-07-011

Amendment 59 December 2007 Loss of Condenser Vacuum Columbia Generating Station     at 104.1% Uprated Power, 100% Rated Flow Final Safety Analysis Report Draw. No. 020361.73      Rev. Figure 15.2-6 Form No. 960690 LDCN-07-011

Amendment 59 December 2007 Loss of Auxiliary Power Transformers -
Columbia Generating Station     at 106.2% Uprated Power, 100% Rated Flow Final Safety Analysis Report Draw. No. 020361.74     Rev. Figure 15.2-7 Form No. 960690 LDCN-07-011

Amendment 59 December 2007 Loss of All Grid Connections -
Columbia Generating Station      104.1% Uprated Power, 100% Rated Flow Final Safety Analysis Report Draw. No. 020361.75       Rev. Figure 15.2-8 Form No. 960690 LDCN-07-011

Amendment 59 December 2007 Loss of All Feedwater Flow -
Columbia Generating Station      106.2% Uprated Power, 100% Rated Flow Final Safety Analysis Report Draw. No. 020361.76       Rev. Figure 15.2-9 Form No. 960690 LDCN-07-011

Amendment 59 December 2007 100 psi, 330&deg;F to 1055 psia, 550&deg;F to 100 psi, 330&deg;F                                14.7 psi, 125&deg;F No Offsite Power C2 ADS Valve RHR Loop A (Division 1 and 3 Available)
A                                 B Depressurize             Division 2 Fails Normal Shutdown       Loss of                                Vessel Via Initiated                      Automated Offsite Power                             ADS/Relief P = 1055 psia                     Relief Valve Transient                            Valve Actuation T = 550&deg;F                       Actuation RHR Suppression             Division 1 Fails Pool Cooling C1 ADS Valve RHR Loops B and C (Division 2 and 3 Available)
Automatic Depressurization System/Residual Heat Columbia Generating Station                                    Removal Cooling Loops Final Safety Analysis Report Draw. No. 900547.63     Rev.          Figure 15.2-10.1 Form No. 960690 LDCN-07-011

Amendment 54 April 2000 NOTES ACTIVITY A Initial pressure        =1055 psia Initial temperature = 550&deg;F For purpose of this analysis, the following worst-case conditions are assumed to exist:
: a. The reactor is assumed to be operating at 105% of original NBR steam flow,
: b. A loss of power transient occurs,
: c. A simultaneous loss of onsite power (Division 1 or Division 2), and
: d. Operator unable to open one of the RHR shutdown cooling line suction valves.
ACTIVITY B Initial system pressure       =1055 psia Initial system temperature = 550&deg;F Operator Actions During approximately the first 30 minutes, reactor decay heat is passed to the suppression pool by the automatic operation of the reactor relief valves. Reactor water level will be returned to normal by the HPCS and RCIC systems automatic operation.
After approximately 10 minutes, the operator initiates depressurization of the reactor vessel to control vessel pressure.
Controlled depressurization procedure consists of controlling vessel pressure and water level by using the SRV or HPCS and/or RCIC systems. After approximately 15 minutes, it is assumed one RHR heat exchanger is placed in the suppression pool cooling mode to remove decay heat. At this time, the suppression pool will be 121&deg;F.
When the reactor pressure approaches 100 psig, the operator would normally prepare for operation of the RHR system in the shutdown cooling mode. At this time (121 minutes), the suppression pool will be 186&deg;F.
ACTIVITY C1 (Division 1 fails, Division 2 available)
System pressure          =100 psig System temperature = 330&deg;F Operation Actions The operator establishes a closed cooling path as follows:
: a. A minimum of two ADS valves (dc Division 2) are powered open.
: b. Either of the following cooling paths are established:
: 1. Using RHR loop B, water from the suppression pool is pumped through the RHR heat exchanger (where a portion of the decay heat is removed) into the reactor vessel. The cooled suppression pool water flows through the vessel (picking up a portion of the decay heat) out the ADS valves and back to the suppression pool. This alternate cooling path is shown in Figure 15.2-12.
: 2. Using RHR loops B and C together, water is taken from the suppression pool and pumped directly into the reactor vessel. The water passes through the vessel (picking up decay heat) and out the ADS valves returning to the suppression pool as shown in Figure 15.2-13. Suppression pool water is then cooled by operation of RHR loop B in the pool cooling mode (see Figure 15.2-14). In this alternate cooling path, RHR loop C is used for injection and RHR loop B for cooling. Cold shutdown is achieved approximately 36 hr after the transient occurs.
ACTIVITY C2 (Division 2 fails, Division 1 available) (Figure 15.2-15)
System pressure          =100 psig System temperature = 330&deg;F Operator Actions The operator establishes a closed cooling path as follows:
: a. A minimum of two ADS valves (dc Division 1) are powered open, and
: b. Using RHR loop A instead of loop B, an alternate cooling path is established as shown in Activity C1. Cold shutdown is reached in approximately 15 hr.
Automatic Depressurization System/Residual Heat Columbia Generating Station                                             Removal Cooling Loops Final Safety Analysis Report Draw. No. 990578.77         Rev.         Figure  15.2-10.2 Form No. 960690

Form No. 960690 1055 psia, 550&deg;F to 100 psi, 330&deg;F                                  100 psi, 330&deg;F to 14.7 psi, 125&deg;F Normal Shutdown Depressurize Columbia Generating Station Cooling (Offsite Vessel to Power)
Main Condenser                          o in g oeol il      ur C lve Final Safety Analysis Report Fa wn Va o                  ADS/Relief u  td ion             Valve Alternate Depressurize                                  h ct Condenser             Vessel Via                                f S Su                         Path Not Available        Manual Relief Valve Actuation +             er A                                                               RHR Suppression                                                           Normal Offsite Power Available D
Pool Cooling             e Pow                                         Shutdown Normal Shutdown                                                                                                                        Cooling (Onsite       Cold l
Draw. No.
Initiated                                                                                                         se                  Power)           Shutdown P = 1055 psia                                                                                                    Di e                                     Achieved III oss of T = 550&deg;F Offsit                                                      (Vessel Head Di v                            ADS/Relief        Removed) 900547.64                                                                                                                                                  L                   of                             Valve Alternate III Loss of Offsite ur e                                  Path il                   ion Fa               ivis Power Transient                             Depressurize                           e o fD l e
ilur Dies Rev.
Vessel Via                     Fa Automated            Manual Relief                                                           ADS/Relief Failure of Relief Valve        Valve Actuation +                                                      Valve Alternate Division I Diesel Summary of Paths Available to Achieve Cold Actuation          RHR Suppression                                                             Path Pool Cooling Figure 15.2-11                                  Shutdown                                                                                                                                                                                         Amendment 53 November 1998

Amendment 53 November 1998 S/R Valve MSL Reactor Vessel Suppression Area Service Water                                               Service Discharge                                                  Water System Heat Exchanger Activity C1 Alternate Shutdown Cooling Path Columbia Generating Station                     Utilizing Residual Heat Removal Loop B Final Safety Analysis Report Draw. No. 900547.65       Rev. Figure 15.2-12 Form No. 960690

Amendment 53 November 1998 S/R Valve MSL B
Reactor Vessel Suppression Area Residual Heat Removal Loop C Columbia Generating Station Final Safety Analysis Report Draw. No. 900547.66      Rev. Figure 15.2-13 Form No. 960690

Amendment 53 November 1998 Service Service Water Water Discharge System Heat Exchanger Residual Heat Removal Loop A(B) (Suppression Columbia Generating Station       Pool Cooling/ Rated Pump Flow Test Mode)
Final Safety Analysis Report Draw. No. 900547.67    Rev. Figure 15.2-14 Form No. 960690

Amendment 53 November 1998 S/R Valve MSL Drywell Reactor Vessel Suppression Area RHR A Heat Exchanger Service                                  Service Water Water                                    Discharge System Activity C2 Alternate Shutdown Cooling Path Columbia Generating Station         Utilizing Residual Heat Removal Loop A Final Safety Analysis Report Draw. No. 900547.68      Rev. Figure 15.2-15 Form No. 960690

Amendment 53 November 1998 Alternate Shutdown Mode Depressurization @ 100&deg;F/hr 87&deg;F Service Water 95&deg;F Initial Pool Temperature LPCI Operates Through 1 Heat Exchanger 1000                                                                         1000 Reactor Vessel Pressure (psia)                                                                                          Reactor Vessel Temperature (&deg;F)
Temperature 100                                                                             100 Pressure 10                                                                              10 0.1                 1                           10                100 Time (hr)
Vessel Temperature and Pressure Versus Time Columbia Generating Station                           (Activity C1.b.1 or C2)
Final Safety Analysis Report Draw. No. 900547.69    Rev. Figure   15.2-16 Form No. 960690

Amendment 53 November 1998 Alternate Shutdown Mode Depressurization @ 100&deg;F/hr 87&deg;F Service Water 95&deg;F Initial Pool Temperature LPCI Direct to the Vessel 1000                                                                        1000 Reactor Vessel Pressure (psia)                                                                                         Reactor Vessel Temperature (&deg;F)
Temperature 100                                                                            100 Pressure 10                                                                             10 0.1                1                            10                100 Time (hr)
Vessel Temperature and Pressure Versus Time Columbia Generating Station                             (Activity C1.b.2)
Final Safety Analysis Report Draw. No. 900547.70   Rev. Figure   15.2-17 Form No. 960690

Amendment 53 November 1998 240 200 Suppression Pool Temperature (&deg;F) 160 120 80                       Alternate Shutdown Mode Depressurization @ 100&deg;F/hr 87&deg;F Service Water 95&deg;F Initial Pool Temperature 40                       LPCI Operates Through 1 Heat Exchanger 0.1                 1                    10                   100                 1000 Time (hr)
Suppression Pool Temperature Versus Time Columbia Generating Station                    (with 87&deg;F Service Water Temperature)
Final Safety Analysis Report                           (Activity C1.b.1 or C2)
Draw. No. 900547.71    Rev. Figure   15.2-18 Form No. 960690

Amendment 53 November 1998 240 200 Suppression Pool Temperature (&deg;F) 160 120 Alternate Shutdown Mode 80                       Depressurization @ 100&deg;F/hr 87&deg;F Service Water 95&deg;F Initial Pool Temperature LPCI Direct to the Vessel 40 0.1                 1                       10                   100                 1000 Time (hr)
Suppression Pool Temperature Versus Time (with Columbia Generating Station                87&deg;F Service Water Temperature) (Activity C1.b.2)
Final Safety Analysis Report Draw. No. 900547.72    Rev. Figure   15.2-19 Form No. 960690

COLUMBIA GENERATING STATION                          Amendment 59 FINAL SAFETY ANALYSIS REPORT                         December 2007 15.3    DECREASE IN REACTOR COOLANT SYSTEM FLOW RATE 15.3.1      RECIRCULATION PUMP TRIP The events for two-recirculation pump operation are not limiting, therefore, the analyses have not been updated since the reactor power uprate analyses.
15.3.1.1      Identification of Causes and Frequency Classification 15.3.1.1.1     Identification of Causes Recirculation pump motor operation can be tripped by design and by random operational failures. Design tripping will occur in response to:
: a. Reactor vessel water level L2 setpoint trip,
: b. Turbine control (governor) valve fast closure or stop (throttle) valve closure,
: c. Failure to scram high pressure setpoint trip,
: d. Motor branch circuit over-current protection,
: e. Motor overload protection, and
: f. Suction block valve not fully open.
Random tripping will occur in response to:
: a. Operator error,
: b. Loss of electrical power source to the pumps, and
: c. Equipment or sensor failures and malfunctions which initiate the above intended trip response.
15.3.1.1.2     Frequency Classification 15.3.1.1.2.1 Trip of One Recirculation Pump. This event is categorized as an incident of moderate frequency.
15.3.1.1.2.2 Trip of Two Recirculation Pumps. This event is categorized as an incident of moderate frequency.
LDCN-07-011                                  15.3-1

COLUMBIA GENERATING STATION                             Amendment 59 FINAL SAFETY ANALYSIS REPORT                            December 2007 15.3.1.2        Sequence of Events and Systems Operation 15.3.1.2.1       Sequence of Events 15.3.1.2.1.1 Trip of One Recirculation Pump. Table 15.3-1 lists the sequence of events for Figure 15.3-1.
15.3.1.2.1.2 Trip of Two Recirculation Pumps. Table 15.3-2 lists the sequence of events for Figure 15.3-2.
15.3.1.2.2       Systems Operation 15.3.1.2.2.1 Trip of One Recirculation Pump. Tripping a single recirculation pump requires no protection system or safeguard system operation. This analysis assumes normal functioning of plant instrumentation and controls.
15.3.1.2.2.2 Trip of Two Recirculation Pumps. Analysis of this event assumes normal functioning of plant instrumentation and controls and plant and reactor protection systems.
Specifically, this transient takes credit for vessel level (L8) instrumentation to trip the turbine.
Reactor shutdown relies on scram trips from the turbine stop (throttle) valves. High system pressure is limited by the pressure relief valve system operation.
15.3.1.2.3       The Effect of Single Failures and Operator Errors 15.3.1.2.3.1 Trip of One Recirculation Pump. None 15.3.1.2.3.2 Trip of Two Recirculation Pumps. Table 15.3-2 lists the vessel level (L8) trip event as the first response to initiate corrective action in this transient and it is intended to prohibit moisture carryover to the main turbine. Multiple level sensors are used to sense and detect when the water level reaches the L8 setpoint. At this point, a single failure will neither initiate nor impede a turbine trip signal. Turbine trip signal transmission circuitry, however, is not built to single failure criterion. At this point the transient event is functionally over.
Scram trip signals from the turbine are designed such that a single failure will neither initiate nor impede a reactor scram trip initiation.
15.3.1.3        Core and System Performance 15.3.1.3.1       Mathematical Model The point-kinetics REDY model described in Section 15.0.3.3.1 is used to simulate this event.
LDCN-07-011                                     15.3-2

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 15.3.1.3.2      Input Parameters and Initial Conditions These analyses have been performed, unless otherwise noted, with plant conditions in Table 15.0-2.
Pump motors and pump rotors are simulated with minimum specified rotating inertias.
15.3.1.3.3      Results 15.3.1.3.3.1 Trip of One Recirculation Pump. Figure 15.3-1 shows the response of the reactor system following the trip of one recirculation pump motor. Initially a recirculation pump is tripped in one loop, causing the core inlet flow to decrease, while the other recirculation loop flow increases. Subsequently jet pump diffuser flow reverses in the tripped recirculation loop. At approximately 45 sec the reactor reaches a new equilibrium operating point, at approximately 75% power and 57% core flow. During the transient, level swell is not sufficient to cause turbine trip.
15.3.1.3.3.2 Trip of Two Recirculation Pumps. Figure 15.3-2 shows the response of the reactor system following the trip of both recirculation pump motors. Initially both recirculation pumps are tripped, causing the core inlet flow to decrease, while vessel level rises until both main and feedwater turbines trip on high level (L8). A reactor scram is subsequently initiated at 90% turbine stop valve position. Shortly after the scram is initiated the stop valves close and the bypass valves open to regulate pressure. At this point the transient event is functionally over.
15.3.1.3.4      Consideration of Uncertainties Initial conditions chosen for these analyses are conservative and tend to force analytical results to be more severe than expected under actual plant conditions.
Actual pump and pump-motor drive line rotating inertias are expected to be somewhat greater than the minimum design values assumed in this simulation. Actual plant deviations regarding inertia are expected to lessen the severity as analyzed. Minimum design inertias were used as well as the least negative void coefficient since these maximize the flow reduction.
15.3.1.4       Barrier Performance 15.3.1.4.1      Trip of One Recirculation Pump Figure 15.3-1 results indicate a basic reduction in system pressures from the initial conditions.
Therefore, the reactor coolant pressure boundary (RCPB) barrier is not impacted.
15.3-3

COLUMBIA GENERATING STATION                           Amendment 59 FINAL SAFETY ANALYSIS REPORT                          December 2007 15.3.1.4.2     Trip of Two Recirculation Pumps The results shown in Figure 15.3-2 indicate peak pressures stay well below the limit allowed by the applicable American Society of Mechanical Engineers (ASME) code. Therefore, the RCPB barrier is not impacted.
15.3.1.5      Radiological Consequences The consequence of this event does not result in fuel failure. It does result in the discharge of normal coolant activity to the suppression pool by means of safety/relief valve (SRV) operation, which is contained in the primary containment. This event does not result in an uncontrolled release to the environment, so the plant operator can choose to hold the activity in containment or discharge it when conditions permit. If purging of the containment is chosen, the release will be in accordance with established requirements.
15.3.2      RECIRCULATION FLOW CONTROL FAILURE - DECREASING FLOW 15.3.2.1      Identification of Causes and Frequency Classification 15.3.2.1.1     Identification of Causes A postulated failure of the input demand signal, which is used in both loops, can decrease core flow at the maximum ramp demand rate established by the adjustable speed drive (ASD) control. Failure within either loop controller can result in a maximum ramp demand rate as limited by the ASD control.
15.3.2.1.2     Frequency Classification This event is categorized as an incident of moderate frequency.
15.3.2.2      Sequence of Events and Systems Operation 15.3.2.2.1     Sequence of Events 15.3.2.2.1.1 Speed Decrease of One Recirculation Pump. Table 15.3-3 lists the sequence of events for Figure 15.3-3.
15.3.2.2.1.2 Speed Decrease of Two Recirculation Pumps. Table 15.3-4 lists the sequence of events for Figure 15.3-4.
LDCN-07-011                                   15.3-4

COLUMBIA GENERATING STATION                           Amendment 59 FINAL SAFETY ANALYSIS REPORT                         December 2007 15.3.2.2.2      Systems Operation 15.3.2.2.2.1 Speed Decrease of One Recirculation Pump. The most severe control system disturbance is a failure that causes the ASD internal controller to move at its maximum rate.
Such transients may be obtained by instantaneous failure of a controller output into its upper or lower limits. Originally the recirculation flow was controlled by valve motion. For the current analysis the recirculation flow control valves have been locked at the full open position, and ASD units have been implemented to provide the necessary flow control.
15.3.2.2.2.2 Speed Decrease of Two Recirculation Pumps. The most severe control system disturbance is a failure that causes the ASD internal controller to move at its maximum rate.
Such transients may be obtained by instantaneous failure of a controller output into its upper or lower limits. The independent and simultaneous failure of each individual loop controller would be highly improbable.
Thus, for the two loop controller failure event, the ASD internal controller is assumed to move at its maximum rate in both recirculation loops. Originally the recirculation flow was controlled by valve motion. For the current analysis the recirculation flow control valves have been locked at the full open position, and ASD units have been implemented to provide the necessary flow control.
15.3.2.2.3      The Effect of Single Failures and Operator Errors The single failure and operator considerations for this event are essentially the same as in Section 15.3.1.2.3.2. The speed decrease of two instead of one recirculation pump would be the envelope case for the additional single component failure or operator error.
15.3.2.3       Core and System Performance 15.3.2.3.1      Mathematical Model The point-kinetics REDY model described in Section 15.0.3.3.1 is used to simulate these transient events.
15.3.2.3.2      Input Parameters and Initial Conditions These analyses have been performed, unless otherwise noted, with plant conditions listed in Table 15.0-2.
15.3.2.3.2.1 Speed Decrease of One Recirculation Pump. For the simulation of this event, a controller malfunction causes a zero demand signal to be sent to one of the recirculation ASD units, while the plant is operating at 106% uprated power and 100% core flow. A control demand error (low) signal causes the ASD to adjust the recirculation pump speed demand rate LDCN-07-011                                   15.3-5

COLUMBIA GENERATING STATION                           Amendment 59 FINAL SAFETY ANALYSIS REPORT                          December 2007 limit downward at an assumed rate of 25%/sec for one loop failure. The ensuing transient is similar to a recirculation pump trip.
15.3.2.3.2.2 Speed Decrease of Two Recirculation Pumps. For the simulation of this event, a controller malfunction causes a zero demand signal to be sent to both of the recirculation ASD units, while the plant is operating at 106% uprated power and 100% core flow.
A control demand error (low) can cause the ASD units to adjust the recirculation pump speed downward in both loops at the 5%/sec pump speed rate limit.
15.3.2.3.3      Results 15.3.2.3.3.1 Speed Decrease of One Recirculation Pump. Figure 15.3-3 shows the response of the plant for this transient. Initially a negative recirculation pump speed demand is sent to the ASD due to a postulated controller failure. The negative pump speed demand causes the diffuser flow to decrease, and eventually reverse, in the failed loop. At the same time the active loop increases flow to compensate for the failed recirculation loop. At approximately 45 sec the reactor reaches a new equilibrium operating point, at approximately 74% power and 57% core flow. During the transient, level swell is not sufficient to cause turbine trip which would result in a reactor scram.
15.3.2.3.3.2 Speed Decrease of Two Recirculation Pumps. Figure 15.3-4 shows the response of the plant to this transient using the 5%/sec pump speed demand rate limit. Initially, a negative recirculation pump speed demand is sent to both ASD units due to a postulated controller failure. The negative pump speed demand causes the diffuser flows to decrease in the failed loops. During the transient, level swell is not sufficient to cause turbine trip which would result in a reactor scram.
15.3.2.3.4      Consideration of Uncertainties Initial conditions chosen for these analyses are conservative and tend to force analytical results to be more severe than expected under actual plant conditions.
These analyses are unaffected by deviations in pump/pump motor and driveline inertias since it is the ASD controller that causes rapid recirculation decreases.
15.3.2.4       Barrier Performance 15.3.2.4.1      Speed Decrease of One Recirculation Pump The pressure in the vessel dome is well below the vessel pressure limit. The event does not result in a temperature or pressure transient in excess of the criteria for which the fuel, pressure vessel, or containment are designed. Therefore, barrier integrity and function is maintained.
LDCN-07-011                                     15.3-6

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 15.3.2.4.2      Speed Decrease of Two Recirculation Pumps The pressure in the vessel dome is well below the vessel pressure limit. The event does not result in a temperature or pressure transient in excess of the criteria for which the fuel, pressure vessel, or containment are designed and these barriers maintain their integrity and function as designed.
15.3.2.5       Radiological Consequences Since this event does not result in any fuel failures or any release of primary coolant to either the secondary containment or to the environment there are no radiological consequences associated with this event.
15.3.3       RECIRCULATION PUMP SEIZURE The pump seizure accident for single loop operation (SLO) is analyzed for the introduction of GNF2 fuel into the Columbia reactor core.
15.3.3.1       Identification of Causes and Frequency Classification The case of recirculation pump seizure represents the extremely unlikely event of instantaneous stoppage of the pump motor shaft of one recirculation pump. This event produces a very rapid decrease of core flow as a result of the large hydraulic resistance introduced by the stopped rotor. The sudden decrease in core coolant flow while the reactor is at full power results in a degradation of core heat transfer which could result in fuel damage.
The event is categorized as an infrequent incident when operating with two recirculation pumps in service. For single loop operation, this event is considered to be a limiting fault, but is analyzed as an incident of moderate frequency for Global Nuclear Fuel reloads.
15.3.3.2       Sequence of Events and Systems Operation 15.3.3.2.1      Sequence of Events Table 15.3-5 lists the sequence of events for Figure 15.3-5, for two loop operation.
Table 15.3-6 lists the typical sequence of events for the recirculation pump seizure accident during SLO.
Identification of Operator Actions The operator must verify that the reactor scrams with the turbine trip resulting from reactor water level swell. The operator should regain control of reactor water level through RCIC LDCN-15-011                                    15.3-7

COLUMBIA GENERATING STATION                        Amendment 59 FINAL SAFETY ANALYSIS REPORT                       December 2007 operation or by restart of a feedwater pump, and must monitor reactor water level and pressure control after shutdown.
15.3.3.2.2        Systems Operation In order to properly simulate the expected sequence of events, the analysis of this event assumes normal functioning of plant instrumentation and controls, plant protection, and reactor protection systems.
Operation of safe shutdown features, including operation of the HPCS and RCIC systems though not included in this simulation, may be used to maintain adequate water level.
15.3.3.2.3        The Effect of Single Failures and Operator Errors Single failures in the scram logic originating by means of the high vessel level (L8) trip are similar to the considerations in Section 15.3.1.2.3.2.
15.3.3.3         Core and System Performance 15.3.3.3.1        Mathematical Model The point-kinetics REDY model described in Section 15.0.3.3.1 is used to simulate this event for two loop operation. The computer model described in Reference 15.3-2 was used to simulate this event for SLO.
15.3.3.3.2        Input Parameters and Initial Conditions This analysis has been performed for two loop operation, unless otherwise noted, with plant conditions tabulated in Table 15.0-2, column REDY (ASD Events). For the simulation of the event while in two loop operation, one recirculation pump was seized instantaneously (pump speed set to zero) while the plant is operating at 106% uprated power and 100% core flow.
For single loop operation, the analysis has been performed, unless otherwise noted, with plant conditions tabulated in Table 15.0-2A, column Original Rated Power. For the purpose of evaluating consequences to the fuel thermal limits, this transient event is assumed to occur as a consequence of an unspecified, instantaneous stoppage of the active recirculation pump shaft while the reactor is operating at 75% NBR power under SLO. Also, the reactor is assumed to be operating at thermally-limiting conditions. The void coefficient is adjusted to the most conservative value, that is, the least negative value in Table 15.0-2A.
LDCN-06-000, 07-011                             15.3-8

COLUMBIA GENERATING STATION                           Amendment 60 FINAL SAFETY ANALYSIS REPORT                          December 2009 15.3.3.3.3       Results Figure 15.3-5 presents the results of the accident for two loop operation. Table 15.3-5 shows the sequence of events for this transient. Initially a recirculation pump is seized in one loop causing the flow in the seized loop to reverse and the flow in the active loop to increase. As the flow in the seized loop decreases, the vessel level rises until a turbine trip is initiated on high level, L8. Once L8 is reached, both feedwater pumps trip. A reactor scram is subsequently initiated due to 90% turbine stop (throttle) valve position. Shortly after the turbine trip is initiated the stop valves close and the bypass valves open to regulate pressure.
Simultaneously the active recirculation loop trips due to the turbine trip. The MCPR does not decrease significantly before fuel surface heat flux begins dropping enough to restore greater thermal margins. After the time at which MCPR occurs, heat flux decreases more rapidly than the rate at which heat is removed by the coolant and the CPR is less than 0.01.
Figure 15.3-6 presents the results of the event in SLO. Core coolant flow drops rapidly, reaching a minimum value of 25% rated at about 2.0 sec.
The RRC pump seizure while in SLO is more limiting than the RRC pump seizure in two loop operation. See Table 15.0-1A.
15.3.3.3.3.1 Considerations of Uncertainties. Considerations of uncertainties are included in the analysis.
15.3.3.4       Barrier Performance The bypass valves open to limit the pressure well within the range allowed by the ASME vessel code. The RCPB is not impacted by overpressure. Therefore, barrier integrity and function is maintained.
15.3.3.5       Radiological Consequences Since this event does not result in any fuel failures or any release of primary coolant to either the secondary containment or to the environment there are no radiological consequences associated with this event.
15.3.4      RECIRCULATION PUMP SHAFT BREAK 15.3.4.1       Identification of Causes and Frequency Classification The breaking of the shaft of a recirculation pump is considered a design basis accident event.
It has been evaluated as a mild accident in relation to other design basis accidents such as the loss-of-coolant accident. The analysis has been conducted with consideration to a single or LDCN-08-035                                     15.3-9

COLUMBIA GENERATING STATION                            Amendment 60 FINAL SAFETY ANALYSIS REPORT                           December 2009 two loop operation. Two loop operation represents the worst case since single loop operation is limited to approximately 75% power.
This postulated event is bounded by the more limiting case of recirculation pump seizure.
15.3.4.1.1      Identification of Causes The case of recirculation pump shaft breakage represents the unlikely event of rapid stoppage of the pump operation of one recirculation pump. This event produces a rapid decrease of core flow.
15.3.4.1.2      Frequency Classification This event is categorized as an incident of infrequent frequency.
15.3.4.2       Sequence of Events and Systems Operation 15.3.4.2.1      Sequence of Events A postulated instantaneous break of the pump motor shaft of one recirculation pump as discussed in Section 15.3.4.1.1 will cause the core flow to decrease rapidly resulting in water level swell in the reactor vessel. When the vessel water level reaches the high water level setpoint (Level 8), a main turbine trip and feedwater pump trip will be initiated.
A reactor scram and the remaining recirculation pump trip will be initiated due to the turbine trip. Eventually the vessel water level will be controlled by HPCS and/or RCIC flow.
15.3.4.2.2      Systems Operation Normal operation of plant instrumentation and control is assumed. This event takes credit for vessel water level (Level 8) instrumentation to scram the reactor and trip the main turbine and feedwater pumps. High system pressure is limited by the pressure relief system operation.
Operation of HPCS and/or RCIC is expected in order to maintain adequate water level control.
15.3.4.2.3      The Effect of Single Failures and Operator Errors Effects of single failures in the high vessel level (L8) trip are similar to the considerations in Section 15.3.1.2.3.2.
Assumption of single component failure or operator error in other equipment has been examined and this has led to the conclusion that no other credible failure exists for this event.
Therefore, the bounding case has been considered.
15.3-10

COLUMBIA GENERATING STATION                           Amendment 60 FINAL SAFETY ANALYSIS REPORT                          December 2009 15.3.4.3       Core and System Performance The pump shaft break event is bounded by the pump seizure event. Since this event is less limiting than that event, only qualitative evaluation is provided. Therefore, no discussion of mathematical model, input parameters, and consideration of uncertainties, etc., is necessary.
15.3.4.3.1      Qualitative Results If this unlikely event occurs, core coolant flow will drop rapidly. The level swell produces a trip of the main and feedwater turbines. A scram is initiated due to turbine trip. Since heat flux decreases more rapidly than the rate at which heat is removed by the coolant, there is no impact on thermal limits. Additionally, the bypass valves and the potential for a momentary opening of some of the SRVs limit the pressure well within the range allowed by the ASME vessel code. Therefore, the RCPB is not impacted by overpressure.
The severity of this pump shaft break event is bounded by the pump seizure event. In either of these two events, the recirculation drive flow of the affected loop decreases rapidly.
In the case of the pump seizure event, the loop flow decreases faster than the normal flow coastdown as a result of the large hydraulic resistance introduced by the stopped rotor. For the pump shaft break event, the hydraulic resistance caused by the broken pump shaft is less than that of the stopped rotor for the pump seizure event. Therefore, the core flow decrease following a pump shaft break effect is slower than the pump seizure event. Thus, it can be concluded that the potential effects of the hypothetical pump shaft break accident are bounded by the effects of the pump seizure event.
15.3.4.4       Barrier Performance The bypass valves and momentary opening of some of the SRVs limit the pressure well within the range allowed by the ASME vessel code. Therefore, the RCPB is not impacted by overpressure.
15.3.4.5       Radiological Consequences Since this event does not result in any fuel failures or any release of primary coolant to either the secondary containment or to the environment there are no radiological consequences associated with this event.
15.

==3.5       REFERENCES==

15.3-1          General Electric Company, WNP-2 Power Uprate Transient Analysis Task Report, GE-NE-208-08-0393, September 1993.
15.3-11

COLUMBIA GENERATING STATION                       Amendment 60 FINAL SAFETY ANALYSIS REPORT                      December 2009 15.3-2      NEDC-24154-P-A, Qualification of the One-Dimensional Core Transient Model for Boiling Water Reactors, Volumes 1, 2, 3 and 4, February 2000.
15.3-3      Advanced Nuclear Fuels Corporation, WNP-2 Single Loop Operation Analysis, ANF-87-119, September 1987.
LDCN-08-035                            15.3-12

COLUMBIA GENERATING STATION                        Amendment 53 FINAL SAFETY ANALYSIS REPORT                       November 1998 Table 15.3-1 Sequence of Events for Figure 15.3-1 Trip of One Recirculation Pump Motor Uprated Power Time (sec)                                   Event 0          Trip of one recirculation pump initiated.
9          Jet pump diffuser flow reverses in the tripped loop.
45a        Core flow and power level stabilize at new equilibrium conditions.
a Approximately.
15.3-13

COLUMBIA GENERATING STATION                         Amendment 59 FINAL SAFETY ANALYSIS REPORT                       December 2007 Table 15.3-2 Sequence of Events for Figure 15.3-2 Trip of Both Recirculation Pump Motors Uprated Power Time (sec)                                  Event 0       Trip of both recirculation pumps initiated.
5.66    Vessel water level (L8) trip initiates turbine trip.
5.66    Feedwater pumps are tripped off.
5.67    Main turbine stop (throttle) valves reach 90% open position and initiate reactor scram trip.
5.76    Turbine bypass valves open.
LDCN-07-011                          15.3-14

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                       November 1998 Table 15.3-3 Sequence of Events for Figure 15.3-3 Recirculation Flow Control Failure Decreasing Flow in One Loop Uprated Power Time (sec)                                     Event 0          Initiate fast down scale of recirculation pump speed in one loop.
4a         Jet pump diffuser flow reverses in the affected loop.
45a        Core flow and power level stabilize at new equilibrium conditions.
a Approximately.
15.3-15

COLUMBIA GENERATING STATION                        Amendment 53 FINAL SAFETY ANALYSIS REPORT                      November 1998 Table 15.3-4 Sequence of Events for Figure 15.3-4 Recirculation Flow Control Failure Decreasing Flow in Both Loops (5%/sec)
Uprated Power Time (sec)                                Event 0         Initiate 5%/sec down scale of recirculation pump speed in both loops.
85a       Core flow and power level stabilize at new equilibrium conditions.
15.3-16

COLUMBIA GENERATING STATION                          Amendment 59 FINAL SAFETY ANALYSIS REPORT                         December 2007 Table 15.3-5 Sequence of Events for Figure 15.3-5 One Recirculation Pump Seizure Uprated Power Time (sec)                                    Event 0           Seizure of one recirculation pump initiated.
1a          Jet pump diffuser flow reverses in the seized loop.
4.40        Vessel water high level (L8) trip initiates a turbine trip.
4.40        Feedwater pumps are tripped off.
4.41        Main turbine stop (throttle) valves reach 90% open position and initiate reactor scram.
4.59        Active recirculation loop trips due to previous turbine trip.
a Approximately.
LDCN-07-011                              15.3-17

COLUMBIA GENERATING STATION                  Amendment 60 FINAL SAFETY ANALYSIS REPORT                 December 2009 Table 15.3-6 Sequence of Events for Pump Seizure (for Single Loop Operation)
Time (sec)                                    Event 0.0     Recirculation pump motor trip off complete Single pump seizure was initiated; core flow decreases
   ~1.9      Reverse flow ceases in the idle loop
   ~6.0      Power and flow stabilize LDCN-08-035                             15.3-18

Amendment 53 November 1998 One Recirculation Pump Trip at 106.2%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.78     Rev. Figure 15.3-1.2

Amendment 53 November 1998 One Recirculation Pump Trip at 106.2%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.79     Rev. Figure 15.3-1.3

Amendment 53 November 1998 One Recirculation Pump Trip at 106.2%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.80     Rev. Figure 15.3-1.4

Amendment 53 November 1998 One Recirculation Pump Trip at 106.2%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.81     Rev. Figure 15.3-1.5

Amendment 53 November 1998 Two Recirculation Pump Trip at 106.2%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.82     Rev. Figure 15.3-2.1

Amendment 53 November 1998 Two Recirculation Pump Trip at 106.2%
Columbia Generating Station                Uprated Power, 100%Flow Final Safety Analysis Report Draw. No. 020361.83     Rev. Figure 15.3-2.2

Amendment 53 November 1998 Two Recirculation Pump Trip at 106.2%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.84     Rev. Figure 15.3-2.3

Amendment 53 November 1998 Two Recirculation Pump Trip at 106.2%
Columbia Generating Station                 Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.85     Rev. Figure 15.3-2.4

Amendment 53 November 1998 Two Recirculation Pump Trip at 106.2%
Columbia Generating Station                Uprated Power, 100%Flow Final Safety Analysis Report Draw. No. 020361.86     Rev. Figure 15.3-2.5

Amendment 53 November 1998 Recirculation Flow Control Failure - Decreasing Columbia Generating Station     Flow in One Loop at 106.2%Uprated Power, Final Safety Analysis Report                     100%Flow Draw. No. 020361.87   Rev.       Figure 15.3-3.1

Amendment 53 November 1998 Recirculation Flow Control Failure - Decreasing Columbia Generating Station      Flow in One Loop at 106.2% Uprated Power, Final Safety Analysis Report                     100% Flow Draw. No. 020361.88   Rev.      Figure 15.3-3.2

Amendment 53 November 1998 Recirculation Flow Control Failure Decreasing Columbia Generating Station     Flow in One Loop at 106.2% Uprated Power, Final Safety Analysis Report                     100% Flow Draw. No. 020361.89   Rev.       Figure  15.3-3.3

Amendment 53 November 1998 Recirculation Flow Control Failure Decreasing Columbia Generating Station     Flow in One Loop at 106.2%Uprated Power, Final Safety Analysis Report                     100%Flow Draw. No. 020361.90   Rev.       Figure  15.3-3.4

Amendment 53 November 1998 Recirculation Flow Control Failure - Decreasing Columbia Generating Station      Flow in One Loop at 106.2% Uprated Power, Final Safety Analysis Report                     100% Flow Draw. No. 020361.91   Rev.      Figure 15.3-3.5

Amendment 53 November 1998 Recirculation Flow Control Failure - Decreasing Columbia Generating Station     Flow in Two Loops, (5%/Sec Ramp) at 106.2%
Final Safety Analysis Report               Uprated Power, 100% Flow Draw. No. 020361.92     Rev. Figure 15.3-4.1

Amendment 53 November 1998 Recirculation Flow Control Failure Decreasing Columbia Generating Station     Flow in Two Loops, (5%/Sec Ramp) at 106.2%
Final Safety Analysis Report               Uprated Power. 100% Flow Draw. No. 020361.93     Rev. Figure  15.3-4.2

Amendment 53 November 1998 Recirculation Flow Control Failure - Decreasing Columbia Generating Station     Flow in Two Loops, (5%/Sec Ramp) at 106.2%
Final Safety Analysis Report               Uprated Power, 100% Flow Draw. No. 020361.94     Rev. Figure 15.3-4.3

Amendment 53 November 1998 Recirculation Flow Control Failure Decreasing Columbia Generating Station     Flow in Two Loops, (5%/Sec Ramp) at 106.2%
Final Safety Analysis Report               Uprated Power, 100% Flow Draw. No. 020361.95     Rev. Figure  15.3-4.4

Amendment 53 November 1998 Recirculation Flow Control Failure - Decreasing Columbia Generating Station     Flow in Two Loops, (5%/Sec Ramp) at 106.2%
Final Safety Analysis Report               Uprated Power, 100% Flow Draw. No. 020361.96     Rev. Figure 15.3-4.5

Amendment 53 November 1998 Recirculation Pump Seizure at 106%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.97      Rev. Figure 15.3-5.1

Amendment 53 November 1998 Recirculation Pump Seizure at 106%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.98      Rev. Figure 15.3-5.2

Amendment 53 November 1998 Recirculation Pump Seizure at 106%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.99      Rev. Figure 15.3-5.3

Amendment 53 November 1998 Recirculation Pump Seizure at 106%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020002.01      Rev. Figure 15.3-5.4

Amendment 53 November 1998 Recirculation Pump Seizure at 106%
Columbia Generating Station                Uprated Power, 100%Flow Final Safety Analysis Report Draw. No. 020002.02      Rev. Figure 15.3-5.5

Amendment 63 December 2015 SLO Recirculation Pump Seizure Results Columbia Generating Station Final Safety Analysis Report Draw. No. 910402.37     Rev. 1   Figure 15.3-6 Form No. 960690 LDCN-15-011

COLUMBIA GENERATING STATION                            Amendment 59 FINAL SAFETY ANALYSIS REPORT                           December 2007 15.4    REACTIVITY AND POWER DISTRIBUTION ANOMALIES 15.4.1      ROD WITHDRAWAL ERROR - LOW POWER This transient is classified as a nonlimiting event for both original and uprated power conditions. Furthermore, the low power Rod Withdrawal Error (RWE) is not affected by power uprate and therefore, the following qualitative analysis is valid for power uprate.
15.4.1.1       Control Rod Removal Error During Refueling 15.4.1.1.1      Identification of Causes and Frequency Classification The event considered is inadvertent criticality due to the complete withdrawal or removal of the most reactive rod during refueling. The probability of the initial causes alone is considered low enough to warrant its being categorized as an infrequent incident since there is no postulated set of circumstances which results in an inadvertent control rod withdrawal error (RWE) while in the refuel mode.
15.4.1.1.2      Sequence of Events and Systems Operation 15.4.1.1.2.1 Initial Control Rod Removal. During refueling operations, safety system interlocks provide assurance that inadvertent criticality does not occur because a control rod was removed or is withdrawn in coincidence with another control rod.
15.4.1.1.2.2 Fuel Insertion With Control Rod Removed. To minimize the possibility of loading fuel into a cell containing no control rod, it is required that all control rods are fully inserted when fuel is being loaded into the core. This requirement is backed up by refueling interlocks on rod withdrawal and movement of the refueling platform. When the mode switch is in the REFUEL position, the interlocks prevent the platform from being moved over the core if a control rod is withdrawn and fuel is on the hoist. Likewise, if the refueling platform is over the core and fuel is on the hoist, control rod motion is blocked by the interlocks.
15.4.1.1.2.3 Second Control Rod Removal. When the platform is not over the core (or fuel is not on the hoist) and the mode switch is in the REFUEL position, only one control rod can be withdrawn. Any attempt to withdraw a second rod results in a rod block by the refueling interlocks.
Since the core is designed to meet shutdown requirements with the highest worth rod withdrawn, the core remains subcritical even with one rod withdrawn.
15.4.1.1.2.4 Control Rod Removal Without Fuel Removal. The design of the control rod, incorporating the velocity limiter, does not physically permit the upward removal of the control LDCN-07-011                                    15.4-1

COLUMBIA GENERATING STATION                           Amendment 59 FINAL SAFETY ANALYSIS REPORT                          December 2007 rod without the simultaneous or prior removal of the four adjacent fuel bundles. This precludes any hazardous condition.
15.4.1.1.2.5 Effect of Single Failure and Operator Errors. If any one of the operations involved in initial failure or error is followed by any other single equipment failure or single operator error, the necessary safety actions are taken (e.g., rod block or scram) automatically prior to violation of any limits.
15.4.1.1.3      Core and System Performances Since the probability of inadvertent criticality during refueling is precluded, the core and system performances were not analyzed. The withdrawal of the highest worth control rod during refueling will not result in criticality. This is verified experimentally by performing shutdown margin checks. Additional reactivity insertion is precluded by interlocks. As a result, no radioactive material is released from the fuel, making it unnecessary to assess any radiological consequences.
No mathematic models are involved in this event. The need for input parameters or initial conditions is not required as there are no results to report. Consideration of uncertainties is not appropriate.
15.4.1.1.4      Barrier Performance An evaluation of the barrier performance was not made for this event since it is a highly localized event and does not result in any change in the core pressure or temperature.
15.4.1.1.5      Radiological Consequences An evaluation of the radiological consequences was not made for this event since no radioactive material is released from the fuel.
15.4.1.2       Continuous Rod Withdrawal During Reactor Startup 15.4.1.2.1      Identification of Causes and Frequency Classification This event is categorized as an infrequent incident. The probability of further development of this event is low because it is contingent upon the failure of the rod worth minimizer (RWM) system or failure of a second licensed operator (or technically qualified member of the technical staff) observing the out-of-sequence rod selection concurrent with a high worth rod, out-of-sequence rod selection contrary to procedures, and operator disregard of continuous alarm annunciations prior to safety system actuation.
15.4-2

COLUMBIA GENERATING STATION                         Amendment 55 FINAL SAFETY ANALYSIS REPORT                        May 2001 15.4.1.2.2      Sequence of Events and Systems Operation 15.4.1.2.2.1 Sequence of Events. Control RWEs are not considered credible in the startup and low power ranges. The RWM or second licensed operator (or other technically qualified member of the technical staff) prevents the operator from selecting and withdrawing an out-of-sequence control rod.
Continuous control RWEs during reactor startup are precluded by the RWM or second qualified person. The RWM or second qualified person prevents the withdrawal of an out-of-sequence control rod from 100% control rod density to 10% of rated thermal power.
15.4.1.2.2.2 Effects of Single Failure and Operator Errors. If any one of the operations involved in the initial failure or error is followed by another single component failure or single operator error, the necessary safety actions are automatically taken to preclude violation of any limits.
15.4.1.2.3      Core and System Performance The performance of the RWM or second licensed operator (or technically qualified member of the technical staff) prevents erroneous selection and withdrawal of an out-of-sequence control rod. Thus, core and system performance is not affected by such a single operator error.
No mathematical models are involved in this event. The need for input parameters or initial conditions is not required as there are no results to report. Consideration of uncertainties is not applicable.
15.4.1.2.4      Barrier Performance An evaluation of the barrier performance was not performed for this event since there is no postulated set of circumstances for which this error could occur.
15.4.1.2.5      Radiological Consequences An evaluation of the radiological consequences is not required for this event since no radioactive material is released.
LDCN-00-034                                      15.4-3

COLUMBIA GENERATING STATION                           Amendment 58 FINAL SAFETY ANALYSIS REPORT                          December 2005 15.4.2      ROD WITHDRAWAL ERROR - AT POWER 15.4.2.1       Identification of Causes and Frequency Classifications 15.4.2.1.1      Identification of Causes While operating in the power range in a normal mode of operation, the reactor operator makes a procedural error and withdraws the maximum worth control rod until the rod block monitor (RBM) system inhibits further withdrawal.
15.4.2.1.2      Frequency Classification The probability of this event is considered low enough to warrant its being categorized as an infrequent incident. However, because of the lack of sufficient frequency database, this event is considered an incident of moderate frequency.
15.4.2.2       Sequence of Events and Systems Operation 15.4.2.2.1      Sequence of Events The sequence of events for this transient is presented in Table 15.4-1.
15.4.2.2.2      Systems Operation The focal point of this event is localized to a small portion of the core; therefore, although reactor control and instrumentation is assumed to function normally, credit is taken only for the RBM system.
While operating in the power range in a normal operational mode, the reactor operator makes a procedural error and withdraws the maximum worth control rod until the RBM system inhibits further withdrawal.
Under normal operating conditions the nearest local power range monitor (LPRM) would detect the peak linear power exceeding design limits and alarm. The operator would acknowledge the alarm and take appropriate action.
If the RWE is severe, the RBM system would alarm, at which time the operator would acknowledge the alarm and take corrective action. Even for conditions such as highly abnormal control rod patterns, operator disregard of all alarms and warnings, and continuous control rod withdrawal, the RBM system will block further withdrawal of the control rod before the fuel reaches the point of boiling transition or the 1% plastic strain limit imposed on the clad.
LDCN-05-019                                    15.4-4

COLUMBIA GENERATING STATION                           Amendment 60 FINAL SAFETY ANALYSIS REPORT                          December 2009 15.4.2.2.3      Effect of Single Failure and Operator Errors Operator errors do not impact the consequences of this event due to the single failure proof design of the RBM system.
15.4.2.3       Core and System Performance 15.4.2.3.1      Mathematical Model The control RWE transient is classified as a slow transient. A slow transient is a power increase transient that is sufficiently slow so that the assumption that steady-state conditions are achieved at each time step is either realistic or conservative. Using this assumption, this transient is calculated using a steady state, three dimensional, coupled nuclear thermal hydraulics computer program PANACEA. All spatial effects are included in the calculation.
A detailed discussion of the code is presented in Reference 15.4-4.
The control RWE analysis has been performed to estimate the minimum critical power ratio (MCPR) and maximum linear heat generation rate (LHGR) in such a transient. A starting control rod pattern is established for the typical BWR reactor and a central control rod is withdrawn from the fully inserted position. Rod withdrawal results in an increase of the LHGR and decrease of the critical power ratio (CPR). The computed maximum LHGR and minimum CPR are compared to values of other transients to establish operating limits for the reactor. The analysis determines the transient MCPR as a function of the rod block monitor setpoint.
15.4.2.3.2      Input Parameters and Initial Conditions The number of possible RWE transients is large due to the number of control rods and the wide range of exposures and power levels. In order to encompass all of the possible RWEs which could conceivably occur, a limiting analysis is defined such that a conservative assessment of the consequences is provided. These conditions bound the effects of the RWE at lower power or flow conditions, including operation with only one reactor recirculation pump.
: a.      The assumed error is a continuous withdrawal of the maximum worth rod at its maximum drive speed;
: b.      The core is assumed to be operating at rated conditions;
: c.      The reactor is presumed to be in its most reactive state and devoid of all xenon.
This ensures that the amount of reactivity is a maximum;
: d.      It is assumed that the operator has fully inserted the maximum worth rod prior to its removal and selected the remaining control rod pattern in such a way as to LDCN-08-035                                     15.4-5

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 approach thermal limits in the fuel bundles in the vicinity of the rod to be withdrawn (this control rod configuration would only be achieved by deliberate operator action or by numerous operator errors);
: e.      The operator is assumed to ignore all warnings during the transient;
: f.      Each RBM channel is analyzed and within each channel, LPRM failures are considered such that the worst case LPRM failures (a minimum of 4 LPRMs are required for the channel to be operable) for the least responsive RBM channel is considered when calculating the CPR for each RBM setpoint. The channel with the greatest response is assumed to be bypassed.
15.4.2.3.2.1 Rod Block Monitor System Operation. The RBM system minimizes the consequences of a RWE by blocking motion of the control rod before the safety limits are exceeded.
When the operator selects a control rod, the RBM signals (associated LPRM input) are calibrated to a fixed (constant) reference signal. The upscale trip levels are set at a fixed level above the reference and will vary as step functions of APRM simulated thermal power. The analytical limits are specified in NEDC-33507P (Reference 15.4-17). This will allow longer withdrawals at low powers where thermal margins are high and allow only short withdrawals at high power. Once tripped, recalibration is allowed only by deselecting the rod, typically accomplished by selecting another rod, and reselecting the rod. Reselection will result in recalibration to the reference signal. The operator verifies adequate thermal margin before continuing rod withdrawal following an RBM upscale trip.
15.4.2.3.3      Results At certain core exposures and power/flow conditions, this limiting transient may be a control RWE. The fuel thermal-mechanical limit (i.e., 1% plastic strain) criterion is met. Results reflect GE14 fuel introduction, some of which are dependent on fuel design and core loading pattern. Compliance with the event acceptance criteria is demonstrated by cycle-dependent analysis of potentially limiting events just prior to the operation of that cycle. The results are reported in the Supplemental Reload Licensing Report (Reference 15.4-16).
15.4.2.3.4      Considerations of Uncertainties The conservative assumptions which ensure that this event has been conservatively analyzed have been previously discussed in Section 15.4.2.3.2.
15.4.2.4        Barrier Performance An evaluation of the barrier performance was not made for this event since this is a localized event with very little change in the gross core characteristics. Typically, an increase in total core power is less than 6% and the changes in pressure are negligible.
LDCN-10-004                                    15.4-6

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                         December 2015 15.4.2.5      Radiological Consequences An evaluation of the radiological consequences is not required for this event since no radioactive material is released from the fuel.
15.4.3      CONTROL ROD MALOPERATION (SYSTEM MALFUNCTION OR OPERATOR ERROR)
This event is covered with the evaluation cited in Sections 15.4.1 and 15.4.2.
15.4.4      STARTUP OF IDLE RECIRCULATION PUMP 15.4.4.1      Identification of Causes and Frequency Classification This event is not analyzed for reload cores. This event is bounded by the off-rated power and flow dependent limits. The slow flow runout analysis of two recirculation loops and the associated limits bounds this event because the heat flux change associated with two pumps increasing flow to the maximum bounds the heat flux change associated with a single pump startup. For the application of ARTS, the analysis basis is that there is an initial 50&deg;F T between the idle and operating loops. This is an appropriate assumption for the thermal limits calculations and it is consistent with Technical Specification requirements. The analysis basis is not expanded into the MELLLA domain because single loop operation is not expanded beyond the ELLLA domain. (Reference 15.4-17) 15.4.4.1.1     Identification of Causes This action results directly from the operators manual action to initiate pump operation. It assumes that the remaining loop is already operating.
15.4.4.1.2     Frequency Classification 15.4.4.1.2.1 Normal Restart of Recirculation Pump at Power. This event is categorized as an incident of moderate frequency.
15.4.4.1.2.2 Abnormal Startup of Idle Recirculation Pump. This event is categorized as an incident of moderate frequency.
15.4.4.2      Sequence of Events and Systems Operation 15.4.4.2.1     Sequence of Events Table 15.4-2 lists the sequence of events for Figure 15.4-1.
LDCN-10-004                                   15.4-7

COLUMBIA GENERATING STATION                           Amendment 60 FINAL SAFETY ANALYSIS REPORT                          December 2009 15.4.4.2.2      Systems Operation This event assumes and takes credit for normal functioning of plant instrumentation and controls. No protection systems action is anticipated. No engineered safety feature (ESF) action occurs as a result of the event.
15.4.4.2.3      The Effect of Single Failures and Operator Errors Attempts by the operator to start the pump at higher power levels will result in a reactor scram on flux.
15.4.4.3       Core and System Performance 15.4.4.3.1      Mathematical Model The point-kinetics REDY model described in Section 15.0.3.3.1 is used to simulate this event.
15.4.4.3.2      Input Parameters and Initial Conditions This analysis has been performed while the plant is operating with a single recirculation loop, at 58% uprated power and 34% core flow. Conservatively, the water in the idle loop is assumed to have a minimum temperature of 100&deg;F. The average enthalpy is based on saturated water temperature at the suction inlet with a linear enthalpy gradient to the discharge outlet water temperature of 100&deg;F.
The active recirculation loop is operating with a pump speed that produces about 45% of normal rated jet pump diffuser flow in the active jet pumps. The inactive recirculation loop jet pumps are forward flowing at about 2% of normal jet pump diffuser flow because of natural circulation affects. The core is receiving about 34% of its normal rated flow.
The idle recirculation pump suction and discharge block valves are open. Normal procedure requires leaving an idle loop in this condition to maintain the loop temperature within the required limits for restart.
15.4.4.3.3      Results The transient response to the incorrect startup of a cold idle recirculation loop is shown in Figure 15.4-1. Shortly after the pump begins to move, the flow from the started jet pump diffusers causes the core inlet flow to increase. The pump startup demand is conservatively assumed to ramp at a rate of 3.3% until maximum pump speed is achieved. The diffuser flows on the started side of the reactor increase ultimately to about 144% of rated while the flow rate of the opposite loop diffusers decreases and eventually reverses to about -8% of 15.4-8

COLUMBIA GENERATING STATION                          Amendment 60 FINAL SAFETY ANALYSIS REPORT                         December 2009 rated. As the inactive loop pump increases speed the cold fluid is pumped out of the recirculation loop piping and is mixed with hot downcomer fluid and the mixture flows to the core with a resulting increase of the core inlet subcooling.
A moderate-duration neutron flux peak to just above 124% of NB rated (NBR = 3486 MWt) is produced as the colder, increasing core flow reduces the void volume. Surface heat flux follows the slower response of the fuel and peaks at 110% of rated before decreasing after the cold water is washed out of the loop at about 30 sec. No damage occurs to the fuel barrier as the MCPR remains substantially above the safety limit.
15.4.4.3.4      Consideration of Uncertainties This particular transient is analyzed for a maximum pump speed demand signal causing the ASD to adjust the recirculation pump speed upward at a nominal speed demand rate limit.
A conservative idle loop temperature is assumed and no other uncertainties were included.
15.4.4.4       Barrier Performance No evaluation of barrier performance is required for this event since no significant pressure increases are incurred during this transient. See Figure 15.4-1.
15.4.4.5       Radiological Consequences Since this event does not result in any fuel failures or any release of primary coolant to either the secondary containment or to the environment, there are no radiological consequences associated with this event.
15.4.5      RECIRCULATION FLOW CONTROL FAILURE WITH INCREASING FLOW 15.4.5.1    Identification of Causes and Frequency Classification 15.4.5.1.1      Identification of Causes An upscale failure of the master manual setpoint station can cause an increase in the core coolant flow rate. Upscale failure of an individual remote manual setpoint station or manual demand loop can also cause an increase in core coolant flow rate.
15.4.5.1.2      Frequency Classification This event is an incident of moderate frequency.
15.4-9

COLUMBIA GENERATING STATION                           Amendment 60 FINAL SAFETY ANALYSIS REPORT                         December 2009 15.4.5.2       Sequence of Events and Systems Operation The increase in recirculation flow results in an increase in core flow. The increase in core flow causes an increase in core power level and shifts the power toward the top of the core by reducing the void fraction in the top of the core.
The rate and magnitude of the power increase are dependent on the rate and magnitude of the flow increase. The operator would be expected to control a slow or small increase through normal operating procedures. However, a rapid or significant increase in neutron flux could exceed the high flux scram setpoint and initiate a scram.
This analysis assumes a relatively gradual flow increase that challenges the thermal limits but does not initiate plant protective systems prior to operator action to terminate the transient.
The turbine control (governor) valves and possibly the bypass valves open to control reactor pressure. Core power increases until a steady state power level is reached at the maximum recirculation flow. The operator then regains control of the flow control system and returns the plant to a normal operating condition.
The analysis of this event assumes and takes credit for normal functioning of plant instrumentation and controls, and the reactor protection system (RPS). Operation of ESF is not expected.
15.4.5.2.1      The Effect of Single Failures and Operator Errors The greatest challenge to the thermal limits is the gradual flow increase without actuation of the RPS. The transient is terminated by operator action but not until the maximum core flow of 108.5% rated flow is reached. No actions, either automatic or manual, occur to mitigate the transient prior to event termination at the maximum core flow.
15.4.5.3       Core and System Performance 15.4.5.3.1      Mathematical Model The core is assumed to be in a pseudo steady state condition in which all plant thermal hydraulics are in equilibrium. The feedwater inlet temperature is assumed to be at its equilibrium value at all power levels during the event. The flow control line used to define the power/flow points represents the steepest attainable during normal reactor operation. The core radial and axial peaking distributions are assumed not to change during the event. The MCPR hot channel analysis along the flow ascension path is calculated with ISCOR (References 15.4-4 and 15.4-14).
Only potentially MCPR limiting fuel is evaluated. Potentially limiting is defined as within 0.10 of the core MCPR for the nominal rated power rodded depletion (typically only fresh and LDCN-08-035                                   15.4-10

COLUMBIA GENERATING STATION                          Amendment 63 FINAL SAFETY ANALYSIS REPORT                         December 2015 once burnt fuel). ISCOR is run at the power/flow level corresponding to the plant/cycle specific maximum flow and iterations are performed on the potentially MCPR limiting fuel channel radial peaking factor(s) such that the hot channel MCPR is equal to the MCPR safety limit (SLMCPR) +/-0.005. ISCOR is then run along the specified flow control line at a range of core flows from 30% to 100% to obtain the potentially MCPR limiting fuel MCPR value(s) for each case. The results of this analysis determine the flow-dependent MCPR limits to assure that the MCPR will not fall below the SLMCPR for a flow increase event. These analyses bound final feedwater temperature reduction (FFWTR) as well as normal feedwater temperature conditions. The LHGR along the flow ascension path is calculated using PANACEA (References 15.4-4 and 15.4-14) to perform a power search at 10% flow increments from 30% up to the maximum runout flow at various core exposures. Only bundles which could exceed the steady state LHGR limits after the event are considered in the statistical sample. A statistically based overpower or a bounding overpower is used in confirming the LHGR reduction factors. LHGR reduction factors are determined to ensure that 1% plastic strain and fuel centerline melt limits are not exceeded (Reference 15.4-17).
15.4.5.3.2      Input Parameters and Initial Conditions The gradual increase in recirculation flow provides the greatest challenge to thermal limits.
The final point in the transient is a power below the high flux scram setpoint at maximum flow. Maximum flow is the maximum flow that can be attained by a credible controller failure initiated from a given low flow starting point. A spectrum of initial, low flow starting points is analyzed at various points throughout the cycle. The analysis assumes that the event is quasi-steady state and that a flow biased scram does not occur. Table 15.4-3 contains a listing of the important input parameters and initial conditions.
15.4.5.3.3      Results The reduced flow MCPR was calculated at discrete flow points. The reduced flow MCPR operating limit curve is shown in the cycle specific Core Operating Limits Report (COLR) for all cycle exposures, including FFWTR operation. The reduced flow LHGR was calculated at discrete flow points. The reduced flow LHGR operating limit is shown in the COLR.
15.4.5.3.4     Considerations of Uncertainties The conservative nature of the analysis approach bounds the uncertainties in void reactivity and power distribution characteristics expected for actual plant conditions.
15.4.5.4       Barrier Performance The reduced flow MCPR is established so that the event does not challenge the safety limit MCPR. Therefore, no fuel damage is predicted as a result of this event.
LDCN-10-004                                   15.4-11

COLUMBIA GENERATING STATION                          Amendment 63 FINAL SAFETY ANALYSIS REPORT                         December 2015 15.4.5.5       Radiological Consequences An evaluation of the radiological consequences is not required for this event since no radioactive material is released.
15.4.6      CHEMICAL AND VOLUME CONTROL SYSTEM MALFUNCTIONS This event is not applicable to boiling water reactor (BWR) plants.
15.4.7      MISPLACED BUNDLE ACCIDENT The fuel loading error considers the consequences of either of two possible events:
misorientation or mislocation of a fuel assembly. Further, the assumption is made that the error is not discovered during core verification. The purpose of the analysis is to determine the change in the minimum CPR and increase in LHGR between the correctly loaded core and the misloaded core. A combination of the misorientation and mislocation is not considered because of the very low probability of occurrence.
15.4.7.1       Identification of Causes and Frequency Classification 15.4.7.1.1      Identification of Causes The event discussed in this section is the improper loading of a fuel bundle and subsequent operation of the core. For the mislocation of a fuel bundle, three errors must occur during the initial core loading. First, a bundle must be misloaded into a wrong position in the core.
Second, the bundle that was supposed to be loaded where the mislocation occurred would have to be placed in an incorrect location. Third, the misplaced bundles would have to be overlooked during the core verification performed following core loading. For the misorientation of a fuel bundle, the bundle is loaded 180&deg; from the correct orientation and this error is overlooked during the core verification.
A fuel loading error would place a fuel assembly in an incorrect location in the core, potentially placing several highly reactive assemblies in close proximity. If a relatively high reactivity assembly is placed in a location not directly monitored by the LPRM/core monitoring system (i.e., unmonitored location), this incorrectly located assembly will operate at higher powers with reduced thermal margins relative to the symmetric monitored assembly.
The incorrectly located assembly may violate operating limits if the symmetric, monitored assembly is operated close to limits. If the incorrect location is a directly monitored cell, the change in the local power readings may not be sufficient to either alert the operators of the loading error or to completely account for the reduction in thermal margin. In this situation, the incorrectly located assembly may violate operating limits while being treated by the monitoring system as if it were correctly loaded.
15.4-12

COLUMBIA GENERATING STATION                          Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 15.4.7.1.2      Frequency of Occurrence This event is categorized as an infrequent incident but is analyzed for GNF reloads consistent with Section 15.3.3.1 as an incident of moderate frequency.
15.4.7.2       Sequence of Events and Systems Operation A fuel bundle is misloaded (incorrect location or orientation) into the core and the error is not identified during the core verification process. The core is operated through the cycle at the conditions assumed for the reference core (the specified core load) with the control rod sequence developed for the reference core. At some point during the cycle, the control rod sequence places the limiting assembly (being monitored by the core monitoring system as a correctly loaded assembly) at the MCPR operating limit. Potentially, this causes the misloaded assembly to be operated below the MCPR operating limit curve and above the design LHGR limit curve. Because the operator may be unable to detect the error, the core operation continues throughout the cycle.
Fuel loading errors, undetected by in-core instrumentation following fueling operations, may result in undetected reductions in thermal margins during power operations. No detection is assumed, and therefore, no corrective operator action or automatic protection system functioning occurs.
15.4.7.2.1      Effect of Single Failure and Operator Errors This analysis already represents the worst case (i.e., operation with a misplaced bundle requires multiple equipment failures or operator errors).
15.4.7.3       Core and System Performance 15.4.7.3.1      Mathematical Model A three-dimensional BWR simulator model is used to calculate the core performance resulting from this event. This model is described in detail in Reference 15.4-4 and Sections S.2.2.1.8 and S.2.2.1.9 of Reference 15.4-5.
15.4.7.3.2      Input Parameters and Initial Conditions Initial input parameters and conditions are cycle specific. Sections S.2.2.1.8 and S.2.2.1.9 of Reference 15.4-5 describe the input parameters and initial conditions applied to the mislocated and misoriented bundle events. For both the mislocated and misoriented bundle events, the fuel loading error is undetected throughout the cycle by the core monitoring system.
15.4.7.3.3      Results The results of the analyses for the fuel loading errors show that the resulting MCPR does not challenge the SLMCPR. No rods are expected to exceed the LHGR limits. Results reflect GE14 fuel introduction, some of which are dependent on fuel design and core loading pattern.
15.4-13

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 Compliance with the event acceptance criteria is demonstrated by cycle-dependent analysis of potentially limiting events just prior to the operation of that cycle. The results are reported in the Supplemental Reload Licensing Report (Reference 15.4-16).
15.4.7.3.4      Considerations of Uncertainties A sufficient number of mislocated assembly cases are considered to assure that the limiting case is evaluated. The mislocated assemblies are loaded into positions that could produce limiting results. For the misoriented assembly case, the gap sizes resulting from the rotation are selected to assure a conservative estimate of the impact on MCPR.
15.4.7.4       Barrier Performance An evaluation of the barrier performance was not made for this event since it is a mild and highly localized event. No perceptible change in the core pressure would be observed.
15.4.7.5       Radiological Consequences An evaluation of the radiological consequences is not required for this event since no radioactive material is released from the fuel.
15.4.8      SPECTRUM OF ROD EJECTION ASSEMBLIES This event is not applicable to BWR plants.
15.4.9      CONTROL ROD DROP ACCIDENT 15.4.9.1       Identification of Causes and Frequency Classification 15.4.9.1.1      Identification of Causes The control rod drop accident (CRDA) is the result of a high worth control rod decoupled from the drive mechanism, dropping out of the core. The subsequent insertion of positive reactivity causes a localized power excursion. This is not an anticipated event because of the system failures and personnel errors that would have to occur in combination to present the reactivity required at the same time that the coupling failed. The control rod patterns are controlled in accordance with the banked position withdraw sequence (BPWS) to preclude situations in which rod drops would have sufficient reactivity to cause the damage postulated by the power excursion.
Detailed discussions of the rod drop analysis and BPWS are given in Reference 15.4-3 and 15.4-7.
15.4-14

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.4.9.1.2      Frequency Classification The CRDA is categorized as a limiting fault because it is not expected to occur during the lifetime of the plant. However, postulated consequences include the potential for the release of radioactive material.
For reactivity anomalies, the CRDA is the limiting event.
15.4.9.2       Sequence of Events and Systems Operation The CRDA assumptions include:
: 1.      At some time, a fully inserted control rod becomes decoupled from its drive and sticks in the fully inserted position.
: 2.      During the start up sequence, the rod patterns employed are permitted by the constraints on rod movements by technical specifications and the rod sequence control hardware, including the maximum allowable number of bypassed rods.
At some time under critical reactor conditions, the rod pattern causes the decoupled rod to have the maximum worth from fully inserted to the position of its drive. The rod worth minimizer is not functioning. The rod drops at that time.
: 3.      The reactor goes on a positive period, and the fuel temperature reactivity feedback terminates the initial power burst.
: 4.      The reactor scrams on the APRM high flux scram signal.
: 5.      All withdrawn rods, except for the decoupled rod, scram at the technical specification rate.
: 6.      The scram terminates the accident.
: 7.      If the mechanical vacuum pump (MVP) is maintaining condenser vacuum (e.g.,
the plant was operating at 5% power or less) and the main steam line radiation (MSLR) monitors detected radiation levels above the setpoint, the MSLR monitors would trip the MVP to reduce the fission product release from the condenser.
Although other normal plant instrumentation and controls are assumed to function, no credit for their operation is taken in the analysis of this event. No operator actions are required to terminate this event. Subsequent to reactor scram which terminates the event, normal vessel inventory makeup systems will be used as available.
15.4-15

COLUMBIA GENERATING STATION                       Amendment 61 FINAL SAFETY ANALYSIS REPORT                      December 2011 15.4.9.2.1      Effect of Single Failures and Operator Errors As discussed, the event is terminated, and therefore mitigated, by the APRM high flux scram signal to RPS. The RPS design meets the single failure criteria. The event is further mitigated by an initial control rod configuration that complies with the BPWS. The withdrawal (or insertion) sequence is implemented by the operator and enforced by the RWM. An operator error in control rod movement will be detected and stopped by the RWM. If the RWM system is not operable, rod movement can only continue with a backup for the operator verifying compliance with the BPWS sequence. Failure of the RWM concurrent with an operator error of moving an out-of-sequence rod, contrary to procedures would be required to result in a potentially more limiting event. Therefore, sufficient redundancy exists such that termination of this transient within the limiting criteria is assured.
At low power levels, the MVP trip maintains the condenser leak rates within the analytical assumptions. The MSLR monitor design meets the single failure criteria and no active failure would prevent the trip signal (Section 11.5.2.1).
15.4.9.3       Core and System Performance 15.4.9.3.1      Mathematical Model The analytical methods, assumptions and conditions for evaluating the excursion aspects of the CRDA are described in detail in References 15.4-1, 15.4-3, 15.4-13. To limit the worth of the postulated dropped rod, the rod pattern control systems are programmed to follow the BPWS, which is generically defined in Reference 15.4-7.
15.4.9.3.2      Input Parameters and Initial Conditions The data presented in Reference 15.4-7 shows that BPWS reduces the control rod worths to the degree that the detailed analyses presented in References 15.4-1, 15.4-3, 15.4-13 or the bounding analyses presented in Reference 15.4-11 do not need to be performed each cycle.
15.4.9.3.3      Results Control rod drop accident results from BPWS plants have been statistically analyzed and documented in Reference 15.4-12. The results show that, in all cases, the peak fuel enthalpy in a CRDA would be much less than the 280 cal/gm design limit even with a maximum incremental rod worth corresponding to 95% probability at the 95% confidence level. Based on these results, it was proposed to the NRC, and subsequently found acceptable, to delete the CRDA from the standard GE BWR reload package for the BPWS plants.
15.4-16

COLUMBIA GENERATING STATION                            Amendment 60 FINAL SAFETY ANALYSIS REPORT                           December 2009 The US Supplement to Reference 15.4-5 reports the results of radiological analyses for initial cores that are orders of magnitude below those identified in 10 CFR 100. The radiological consequences of the CRDA, assuming a full core of more recent GE/GNF fuel designs, are discussed in Reference 15.4-5. With implementation of Alternative Source Term (AST), the radiological release acceptance criterion becomes 10 CFR 50.67. An evaluation of fuel damage was performed because the maximum deposited fuel rod enthalpy exceeded 170 cal/gm, which is the enthalpy limit assumed for eventual cladding perforation. The number of fuel rods predicted to fail (Reference 15.4-15) are bounded by the number assumed in the radiological consequences analysis for this event.
The total energy deposited and the associated increase in reactor system pressure during a rod drop event is not high relative to other events such as turbine trip without bypass or main steam line isolation valve closure, both of which are quantitatively analyzed. As such, the increase in reactor system pressure is not anticipated to result in penetration of the stress limits defined in Section III of the ASME boiler and pressure code.
15.4.9.4       Barrier Performance An evaluation of the barrier performance was not made for this accident since this is a localized event with no significant change in the gross core temperature or pressure.
15.4.9.5       Radiological Consequences The radiological analysis is based on the AST described in Reference 15.4-8. Specific models, assumptions, and the program used for computer evaluation are described in Reference 15.4-6.
Specific parametric values used in the evaluation are presented in Table 15.4-4. The radiological consequences remain bounding because cycle specific analyses have confirmed that the number of fuel rods with an enthalpy greater than the threshold for fuel failure are well below the number assumed in the analysis.
15.4.9.5.1      Fission Product Release from Fuel The failure of 1.8% of the core was assumed for this analysis. The mass fraction of the fuel in the damaged rods which reaches or exceeds the initiation temperature of fuel melting (taken as 2804&deg;C) is assumed to be 0.0077.
Fuel reaching melt condition is assumed to release 100% of the noble gas inventory and 50%
of the iodine inventory. The remaining fuel rods with clad damage only (no melting), will undergo a gap release which is assumed to release 10% of noble gases and 10% of iodine inventories.
LDCN-08-035                                  15.4-17

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                        December 2011 The core inventory of fission products is based on a plant-specific ORIGEN 2 run for pre-power uprate basis of 3489 MW with 1000 days of exposure, adjusted as follows:
A scale factor of 1.0528 to bound the dose impact of power level to 3556 MWt, A correction to increase by 25 percent short-lived krypton values (based on comparisons to other core inventory tables), and An increase by 60% in the activity of longer lived isotopes to bound longer plant operation at a higher burnup rate.
The assumed core power of 3556 MWt is the licensed power increased by 2% to account for power measurement uncertainties. These adjustments resulted in a conservative source term (in terms of activity available). A peaking factor of 1.7 is assumed and no delay time is considered between departure from that power condition and the initiation of the accident.
15.4.9.5.2      Fission Product Transport to the Environment The transport pathway consists of a release from the core to the coolant, carryover with steam to the turbine condenser and leakage from the condenser to the environment. The release fractions are given in Reference 15.4-6 and are consistent with Reference 15.4-8. No credit is taken for mixing in the turbine building or filtration by the CREF.
Of the activity reaching the condenser, 100% of the noble gases, and 10% of the iodine (due to partitioning and plate-out) and 1% of the particulates remain airborne and are available for release to the environment. The activity airborne in the condenser leaks to the environment as a ground level release at a rate of 1% of condenser volume per day. Release from the condenser is assumed to terminate 24 hours following the onset of the accident. Radioactive decay is accounted for during residence in the condenser; however, it is neglected after release to the environment. If the condenser is not isolated from the offgas system, the activity is processed through the offgas system. In this case, radioactive decay is accounted for during the residence in the offgas system. Response of the offgas system to elevated radiation levels is described in Section 11.3.2.4.5.
The activity airborne in the condenser is presented in Table 15.4-5. The cumulative release of activity to the environment is presented in Table 15.4-6.
15.4.9.5.3      Results The calculated exposures from the design basis analysis are presented in Table 15.4-7 and are within the limits of 10 CFR 50.67.
LDCN-11-000                                   15.4-18

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 15.4.10     REFERENCES 15.4-1        Stirn, R. C., Rod Drop Accident Analysis for Large Boiling Water Reactors, NEDO-10527, March 1972.
15.4-2        GE Nuclear Energy, WNP-2 Power Uprate Transient Analysis Task Report, GE-NE-208-08-0393, September 1993 (Proprietary).
15.4-3        Stirn, R. C., Rod Drop Accident Analysis for Large BWRs, Supplement 1, NEDO-10527, July 1972.
15.4-4        Steady -State Nuclear Methods, NEDE-30130-P-A, April 1985.
15.4-5        General Electric Standard Application for Reactor Fuel, NEDE-24011-P-A and Supplement for United States, NEDE-24011-P-A-US (most recent approved version referenced in COLR).
15.4-6        Energy Northwest, Columbia Generating Station Alternative Source Term, CGS-FTS-0168, Revision 2, June 2011.
15.4-7        Paone, C. J., Bank Position Withdrawal Sequence, NEDO-21231.
15.4-8        NRC Regulatory Guide 1.183, Alternative Source Term for Evaluating Design Basis Accidents at Nuclear Power Reactors, July 2000.
15.4-9        Deleted.
15.4-10       General Electric, Safety Evaluation for Eliminating the Boiling Water Reactor Main Steam Isolation Valve Closure Function and Scram Function of the Main Steam Line Radiation Monitor, NEDO-31400A, Class I, October 1992.
15.4-11       GE BWR Generic Reload Application for 8x8 Fuel, Supplement 3 to Revision 1, NEDO-20360.
15.4-12       Letter from R. E. Engel (GE) to D. M. Vassallo (NRC), Elimination of Control Rod Drop Accident Analysis for Banked Position Withdrawal Sequence Plants, February 24, 1982.
15.4-13       Stirn, R. C., Rod Drop Accident Analysis for Large Boiling Water Reactors Addendum No. 2 Exposed Cores, Supplement 2, NEDO-10527, January 1973.
LDCN-15-011                               15.4-19

COLUMBIA GENERATING STATION                       Amendment 63 FINAL SAFETY ANALYSIS REPORT                      December 2015 15.4-14     Letter from D. G. Eisenhut (NRC) to R. L. Gridley (GE), Safety Evaluation for the General Electric Topical Report, Generic Reload Fuel Application (NEDE-24011-P), May 12, 1978, MFN-212-78.
15.4-15     GE14 Compliance with Amendment 22 of NEDE-24011-P-A (GESTAR II),
NEDC-32868P, Revision 4, January 2012.
15.4-16     Supplemental Reload Licensing Report for Columbia (most recent version referenced in COLR).
15.4-17     Energy Northwest Columbia Generating Station APRM/RBM/Technical Sepcifications/Maximum Extended Load Line Limit Analysis (ARTS/MELLLA), NEDC-33507P, Revision 0, April 2010.
LDCN-10-004                              15.4-20

COLUMBIA GENERATING STATION                          Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 Table 15.4-1 Sequence of Events - Rod Withdrawal Error in Power Range Timea                                            Event (1)           Event begins; operator selects the maximum worth control rod, acknowledges any alarms and withdraws the rod at the maximum rod speed.
(2)           Core average power and local power increase causing LPRM alarm.
(3)           Event ends - rod block by RBM a
The RWE event is analyzed with a three-dimensional core simulator. This is a conservative steady state analysis for the determination of the appropriate power distribution limits during the event. Since it is not a dynamic simulation, no timed sequence of events is available.
LDCN-10-004                                  15.4-21

COLUMBIA GENERATING STATION                  Amendment 57 FINAL SAFETY ANALYSIS REPORT                 December 2003 Table 15.4-2 Sequence of Events for an Abnormal Startup of an Idle Recirculation Loop Time (sec)                           Event 0.00    Plant operating with one recirculation loop only.
5.00    Start idle recirculation loop pump motor.
29.6     Peak value of core inlet subcooling.
29.6     Peak thermal power. Estimated APRM thermal power approximately 1% below APRM thermal power setpoint.
45.7     Pump motor at full speed.
80+      Reactor reaches new equilibrium condition.
15.4-22

COLUMBIA GENERATING STATION                            Amendment 60 FINAL SAFETY ANALYSIS REPORT                           December 2009 Table 15.4-3 Reactor Recirculation Pump Flow Increase Input Parameters and Initial Conditions Parameter                                        Value Reactor Power/Core Flow       Flow increase is initiated from several power/flow points and terminates at 111% rated power, 108.5%rated flow Power Distribution            The MCPR equals the safety limit at the final power/flow condition Reactivity                    The results are applicable from Beginning of Cycle to End of Cycle for nominal and reduced feedwater temperatures Control Rod Configuration     The control rod pattern is the same at the initial and final points.
LDCN-08-035                                15.4-23

COLUMBIA GENERATING STATION                       Amendment 59 FINAL SAFETY ANALYSIS REPORT                      December 2007 Table 15.4-4 Control Rod Drop Accident Evaluation Parameters I.      Data and assumptions used to estimate radioactive source from postulated accidents.
A. Power level                                               Section 15.4.9.5.1 B. Burnup                                                    Section 15.4.9.5.1 C. Fuel damaged                                              1.8% of core D. Release of activity by nuclide                            Table 15.4-6 E. Iodine fractions (1)     Organic                                           0.0015 (2)     Elemental                                         0.0485 (3)     Particulate                                       0.95 F. Reactor coolant activity before the accident.             N/A II. Data and assumptions used to estimate activity released.
A. Condenser leak rate (%/day)                               1.0 B. Turbine building leak rate (%/day)                        N/A C. Valve closure time (sec)                                  N/A D. Adsorption and filtration efficiencies (1)     Organic iodine                                    N/A (2)     Elemental iodine                                  N/A (3)     Particulate iodine                                N/A (4)     Particulate fission products                      N/A E. Recirculation system parameters (1)     Flow rate                                         N/A (2)     Mixing efficiency                                 N/A (3)     Filter efficiency                                 N/A F. Containment spray parameters (flow rate, drop size, etc.) N/A LDCN-05-009                                   15.4-24

COLUMBIA GENERATING STATION                    Amendment 57 FINAL SAFETY ANALYSIS REPORT                   December 2003 Table 15.4-4 Control Rod Drop Accident Evaluation Parameters (Continued)
G. Containment volumes                                    N/A H. All other pertinent data and assumptions               None III. Dispersion data                                               Table 15.0-4 IV. Dose data A. Method of dose calculation                             Reference 15.4-6 B. Dose conversion assumptions                            Reference 15.4-6 C. Peak activity concentrations in condenser              Table 15.4-5 D. Doses                                                  Table 15.4-7 LDCN-03-003                                  15.4-25

COLUMBIA GENERATING STATION                          Amendment 59 FINAL SAFETY ANALYSIS REPORT                         December 2007 Table 15.4-5 Control Rod Drop Accident Activity Airborne in the Condenser (Curies) 3556 MWth 1m           30 m          2 hrs         8 hrs        12 hrs       24 hrs Kr83m         4.12E+04     3.43E+04       1.96E+04     2.06E+03      4.61E+02      5.13E+00 Kr85m         8.50E+04     7.88E+04       6.21E+04     2.40E+04      1.27E+04      1.90E+03 Kr85          4.77E+03     4.77E+03       4.76E+03     4.75E+03      4.74E+03      4.72E+03 Kr87          1.54E+05     1.18E+05       5.20E+04     1.95E+03      2.18E+02      3.05E-01 Kr88          2.19E+05     1.95E+05       1.34E+05     3.03E+04      1.12E+04      5.72E+02 Kr89          2.05E+05     3.71E+02       1.14E-06     6.96E-18      1.01E-16      7.70E-18 Xe131m        3.24E+03     3.23E+03       3.22E+03     3.16E+03      3.13E+03      3.02E+03 Xe133m        1.93E+04     1.91E+04       1.88E+04     1.74E+04      1.65E+04      1.41E+04 Xe133         6.30E+05     6.28E+05       6.23E+05     6.01E+05      5.87E+05      5.47E+05 Xe135m        1.23E+05     3.40E+04       6.24E+02     7.12E-05      1.68E-09      2.52E-16 Xe135         1.52E+05     1.46E+05       1.31E+05     8.30E+04      6.13E+04      2.47E+04 Xe137         4.52E+05     2.62E+03       2.99E-04     4.13E-18      3.26E-17      2.41E-17 Xe138         4.00E+05     1.22E+05       3.11E+03     1.30E-03      7.24E-08      2.47E-18 Total noble gases         2.49E+06     1.39E+06       1.05E+06     7.68E+05      6.97E+05      5.96E+05 I-131*        3.06E+05     2.64E+05       1.83E+05     8.50E+04      6.15E+04      2.47E+04 I-132         6.71E+05     1.98E+05       1.34E+05     3.03E+04      1.12E+04      5.72E+02 I-133         6.05E+05     1.22E+05       3.11E+03     1.30E-03      7.24E-08      1.02E-17 I-134         3.24E+03     3.23E+03       3.22E+03     3.16E+03      3.13E+03      3.02E+03 I-135         2.51E+06     1.41E+06       1.07E+06     7.85E+05      7.14E+05      6.10E+05 Total Iodine        4.09E+06     1.99E+06       1.39E+06     9.03E+05      7.90E+05      6.38E+05
* The isotopic iodine activity is the sum of the elemental and organic iodines with 97%
elemental and 3% organic.
The particulate iodine comprise 0%.
LDCN-05-009                                 15.4-26

COLUMBIA GENERATING STATION                        Amendment 59 FINAL SAFETY ANALYSIS REPORT                      December 2007 Table 15.4-5 Control Rod Drop Accident Activity Airborne in the Condenser (Curies) (Continued) 3556 MWth 1m           30 m          2 hrs        8 hrs       12 hrs      24 hrs Rb86       5.87E-02     5.86E-02      5.84E-02     5.77E-02    5.73E-02     5.60E-02 Cs134      8.23E+00     8.23E+00      8.22E+00     8.20E+00    8.18E+00     8.14E+00 Cs136      1.82E+00     1.82E+00      1.81E+00     1.79E+00    1.77E+00     1.71E+00 Cs137      6.63E+00     6.63E+00      6.62E+00     6.61E+00    6.59E+00     6.56E+00 Sb127      1.38E-02     1.38E-02      1.36E-02     1.30E-02    1.26E-02     1.14E-02 Sb129      3.95E-02     3.66E-02      2.88E-02     1.10E-02    5.84E-03     8.61E-04 Te127m     1.95E-03     1.95E-03      1.94E-03     1.94E-03    1.93E-03     1.91E-03 Te127      1.38E-02     1.38E-02      1.38E-02     1.36E-02    1.34E-02     1.25E-02 Te129m     5.81E-03     5.80E-03      5.79E-03     5.75E-03    5.72E-03     5.63E-03 Te129      3.72E-02     3.74E-02      3.43E-02     1.52E-02    8.10E-03     1.20E-03 Te131m     1.75E-02     1.73E-02      1.67E-02     1.45E-02    1.32E-02     9.97E-03 Te132      1.67E-01     1.66E-01      1.64E-01     1.55E-01    1.49E-01     1.33E-01 Ba137m     1.54E+00     6.62E+00      6.62E+00     6.61E+00    6.59E+00     6.56E+00 Ba139      7.82E-02     6.14E-02      2.90E-02     1.43E-03    1.94E-04     4.75E-07 Ba140      7.65E-02     7.64E-02      7.61E-02     7.49E-02    7.41E-02     7.17E-02 Mo99       1.02E-02     1.02E-02      1.00E-02     9.39E-03    8.99E-03     7.90E-03 Tc99m      9.06E-03     9.12E-03      9.27E-03     9.45E-03    9.33E-03     8.55E-03 Ru103      9.81E-03     9.81E-03      9.79E-03     9.72E-03    9.68E-03     9.55E-03 Ru105      7.21E-03     6.69E-03      5.33E-03     2.14E-03    1.16E-03     1.87E-04 Ru106      4.26E-03     4.26E-03      4.26E-03     4.24E-03    4.23E-03     4.21E-03 Rh105      6.83E-03     6.83E-03      6.80E-03     6.42E-03    6.04E-03     4.87E-03 Y90        3.50E-05     6.38E-05      1.52E-04     4.90E-04    7.02E-04     1.28E-03 Y91        4.56E-04     4.66E-04      4.95E-04     5.82E-04    6.22E-04     6.87E-04 Y92        6.39E-04     4.76E-03      1.26E-02     1.28E-02    7.81E-03     1.10E-03 Y93        5.94E-04     5.74E-04      5.18E-04     3.42E-04    2.59E-04     1.13E-04 Zr95       7.13E-04     7.13E-04      7.12E-04     7.08E-04    7.06E-04     6.98E-04 Zr97       7.23E-04     7.09E-04      6.66E-04     5.21E-04    4.42E-04     2.70E-04 LDCN-05-009                              15.4-27

COLUMBIA GENERATING STATION                        Amendment 59 FINAL SAFETY ANALYSIS REPORT                      December 2007 Table 15.4-5 Control Rod Drop Accident Activity Airborne in the Condenser (Curies) (Continued) 3556 MWth 1m           30 m          2 hrs        8 hrs       12 hrs      24 hrs Nb95       7.13E-04     7.13E-04      7.13E-04     7.11E-04    7.10E-04     7.06E-04 La140      8.08E-04     1.43E-03      3.33E-03     1.04E-02    1.46E-02     2.54E-02 La141      7.26E-04     6.66E-04      5.10E-04     1.75E-04    8.58E-05     1.01E-05 La142      6.91E-04     5.55E-04      2.81E-04     1.84E-05    3.00E-06     1.29E-08 Pr143      6.31E-04     6.32E-04      6.35E-04     6.44E-04    6.49E-04     6.58E-04 Nd147      2.86E-04     2.85E-04      2.84E-04     2.79E-04    2.76E-04     2.66E-04 Am241      1.28E-07     1.28E-07      1.28E-07     1.28E-07    1.27E-07     1.27E-07 Cm242      2.91E-05     2.91E-05      2.90E-05     2.89E-05    2.89E-05     2.87E-05 Cm244      2.36E-06     2.35E-06      2.35E-06     2.35E-06    2.34E-06     2.33E-06 Ce141      1.85E-03     1.85E-03      1.85E-03     1.83E-03    1.82E-03     1.80E-03 Ce143      1.67E-03     1.66E-03      1.60E-03     1.40E-03    1.28E-03     9.85E-04 Ce144      1.36E-03     1.36E-03      1.36E-03     1.35E-03    1.35E-03     1.34E-03 Np239      2.93E-02     2.91E-02      2.85E-02     2.64E-02    2.51E-02     2.15E-02 Pu238      3.99E-06     3.99E-06      3.99E-06     3.98E-06    3.97E-06     3.95E-06 Pu239      7.89E-07     7.89E-07      7.89E-07     7.87E-07    7.85E-07     7.82E-07 Pu240      1.30E-06     1.30E-06      1.30E-06     1.29E-06    1.29E-06     1.29E-06 Pu241      3.70E-04     3.70E-04      3.69E-04     3.68E-04    3.68E-04     3.66E-04 Sr89       3.37E-02     3.37E-02      3.37E-02     3.35E-02    3.33E-02     3.29E-02 Sr90       5.58E-03     5.58E-03      5.57E-03     5.56E-03    5.55E-03     5.52E-03 Sr91       4.32E-02     4.17E-02      3.74E-02     2.42E-02    1.81E-02     7.54E-03 Sr92       5.01E-02     4.41E-02      2.97E-02     6.14E-03    2.15E-03     9.15E-05 LDCN-05-009                              15.4-28

COLUMBIA GENERATING STATION                           Amendment 59 FINAL SAFETY ANALYSIS REPORT                         December 2007 Table 15.4-6 Control Rod Drop Accident Activity Airborne to the Environment (Curies) 3556 MWth 1m           0.5 hr        2 hrs        8 hrs        12 hrs       24 hrs Kr83m           2.78E-01     7.86E+00      2.43E+01     4.38E+01     4.56E+01      4.61E+01 Kr85m           5.74E-01     1.71E+01      6.09E+01     1.61E+02     1.91E+02      2.19E+02 Kr85            3.21E-02      9.92E-01     3.97E+00     1.59E+01     2.38E+01      4.75E+01 Kr87           1.04E+00      2.83E+01      7.87E+01     1.17E+02     1.18E+02      1.18E+02 Kr88           1.48E+00      4.31E+01      1.45E+02     3.20E+02     3.52E+02      3.69E+02 Kr89           1.54E+00      8.07E+00      8.08E+00     8.08E+00     8.08E+00      8.08E+00 Xe131m          2.18E-02      6.73E-01     2.69E+00     1.07E+01     1.59E+01      3.13E+01 Xe133m          1.30E-01     4.00E+00      1.58E+01     6.10E+01     8.92E+01      1.66E+02 Xe133          4.24E+00      1.31E+02      5.22E+02     2.05E+03     3.04E+03      5.88E+03 Xe135m          8.48E-01     1.48E+01      2.00E+01     2.01E+01     2.01E+01      2.01E+01 Xe135          1.02E+00      3.10E+01      1.18E+02     3.80E+02     5.00E+02      7.01E+02 Xe137          3.32E+00      2.09E+01      2.10E+01     2.10E+01     2.10E+01      2.10E+01 Xe138          2.75E+00      5.00E+01      7.03E+01     7.08E+01     7.08E+01      7.08E+01 Total Noble    1.73E+01      3.58E+02      1.09E+03     3.28E+03     4.50E+03      7.70E+03 Gases I-131*          4.08E-01     1.19E+01      4.01E+01     1.05E+02     1.35E+02      2.12E+02 I-132          4.81E+00      1.48E+02      5.83E+02     2.21E+03     3.23E+03      6.10E+03 I-133           8.80E-01     1.58E+01      2.40E+01     3.60E+01     4.39E+01      6.76E+01 I-134          2.06E+00      5.93E+01      1.97E+02     4.97E+02     6.18E+02      8.19E+02 I-135          4.80E+00      6.40E+01      1.66E+02     3.41E+02     3.73E+02      3.90E+02 Total Iodine   1.30E+01      2.99E+02      1.01E+03     3.19E+03     4.40E+03      7.59E+03
* The isotopic iodine activity is the sum of the elemental and organic iodines with 97%
elemental and 3% organic.
The particulate iodine comprise 0%.
LDCN-05-009                                  15.4-29

COLUMBIA GENERATING STATION                       Amendment 59 FINAL SAFETY ANALYSIS REPORT                      December 2007 Table 15.4-6 Control Rod Drop Accident Activity Airborne to the Environment (Curies) (Continued) 3556 MWth 1m         0.5 hr         2 hrs       8 hrs       12 hrs      24 hrs Rb86       3.95E-07     1.22E-05      4.88E-05    1.94E-04    2.90E-04     5.73E-04 Cs134      5.54E-05     1.71E-03      6.86E-03    2.74E-02    4.11E-02     8.19E-02 Cs136      1.23E-05     3.79E-04      1.52E-03    6.02E-03    8.99E-03     1.77E-02 Cs137      4.47E-05     1.38E-03      5.52E-03    2.21E-02    3.31E-02     6.60E-02 Sb127      9.31E-08     2.87E-06      1.14E-05    4.47E-05    6.60E-05     1.26E-04 Sb129      2.66E-07     7.92E-06      2.83E-05    7.46E-05    8.82E-05     1.01E-04 Te127m     1.31E-08     4.05E-07      1.62E-06    6.48E-06    9.70E-06     1.93E-05 Te127      9.31E-08     2.88E-06      1.15E-05    4.58E-05    6.83E-05     1.33E-04 Te129m     3.91E-08     1.21E-06      4.83E-06    1.93E-05    2.88E-05     5.72E-05 Te129      2.50E-07     7.77E-06      3.04E-05    9.08E-05    1.10E-04     1.28E-04 Te131m     1.18E-07     3.63E-06      1.43E-05    5.33E-05    7.65E-05     1.34E-04 Te132      1.12E-06     3.46E-05      1.38E-04    5.35E-04    7.88E-04     1.49E-03 Ba137m     5.43E-06     1.21E-03      5.35E-03    2.19E-02    3.29E-02     6.58E-02 Ba139      5.29E-07     1.45E-05      4.15E-05    6.44E-05    6.55E-05     6.56E-05 Ba140      5.15E-07     1.59E-05      6.36E-05    2.53E-04    3.77E-04     7.41E-04 Mo99       6.89E-08     2.12E-06      8.44E-06    3.27E-05    4.80E-05     9.02E-05 Tc99m      6.11E-08     1.89E-06      7.65E-06    3.12E-05    4.69E-05     9.18E-05 Ru103      6.61E-08     2.04E-06      8.17E-06    3.26E-05    4.88E-05     9.69E-05 Ru105      4.86E-08     1.45E-06      5.19E-06    1.39E-05    1.66E-05     1.93E-05 Ru106      2.87E-08     8.87E-07      3.55E-06    1.42E-05    2.13E-05     4.24E-05 Rh105      4.60E-08     1.42E-06      5.68E-06    2.23E-05    3.27E-05     6.00E-05 Y90        2.33E-10     1.02E-08      7.78E-08    8.86E-07    1.88E-06     6.88E-06 Y91        3.07E-09     9.60E-08      3.97E-07    1.75E-06    2.76E-06     6.06E-06 Y92        3.78E-09     5.63E-07      6.33E-06    4.33E-05    6.04E-05     7.81E-05 Y93        4.00E-09     1.22E-07      4.63E-07    1.52E-06    2.02E-06     2.90E-06 LDCN-05-009                            15.4-30

COLUMBIA GENERATING STATION                       Amendment 59 FINAL SAFETY ANALYSIS REPORT                      December 2007 Table 15.4-6 Control Rod Drop Accident Activity Airborne to the Environment (Curies) (Continued) 3556 MWth 1m         0.5 hr         2 hrs       8 hrs       12 hrs      24 hrs Zr95       4.81E-09     1.48E-07      5.94E-07    2.37E-06    3.55E-06     7.06E-06 Zr97       4.87E-09     1.49E-07      5.79E-07    2.06E-06    2.86E-06     4.60E-06 Nb95       4.81E-09     1.48E-07      5.94E-07    2.38E-06    3.56E-06     7.10E-06 La140      5.37E-09     2.31E-07      1.72E-06    1.91E-05    4.00E-05     1.41E-04 La141      4.90E-09     1.45E-07      5.11E-07    1.29E-06    1.50E-06     1.68E-06 La142      4.67E-09     1.30E-07      3.81E-07    6.23E-07    6.37E-07     6.40E-07 Pr143      4.25E-09     1.32E-07      5.28E-07    2.13E-06    3.21E-06     6.48E-06 Nd147      1.92E-09     5.94E-08      2.37E-07    9.42E-07    1.40E-06     2.76E-06 Am241      8.63E-13     2.67E-11      1.07E-10    4.27E-10    6.39E-10     1.28E-09 Cm242      1.96E-10     6.05E-09      2.42E-08    9.67E-08    1.45E-07     2.89E-07 Cm244      1.59E-11     4.90E-10      1.96E-09    7.84E-09    1.18E-08     2.34E-08 Ce141      1.25E-08     3.85E-07      1.54E-06    6.15E-06    9.20E-06     1.83E-05 Ce143      1.13E-08     3.47E-07      1.37E-06    5.12E-06    7.36E-06     1.30E-05 Ce144      9.15E-09     2.83E-07      1.13E-06    4.52E-06    6.77E-06     1.35E-05 Np239      1.97E-07     6.07E-06      2.41E-05    9.28E-05    1.36E-04     2.52E-04 Pu238      2.69E-11     8.31E-10      3.33E-09    1.33E-08    1.99E-08     3.98E-08 Pu239      5.32E-12     1.64E-10      6.58E-10    2.63E-09    3.94E-09     7.86E-09 Pu240      8.75E-12     2.70E-10      1.08E-09    4.33E-09    6.48E-09     1.29E-08 Pu241      2.49E-09     7.69E-08      3.08E-07    1.23E-06    1.85E-06     3.68E-06 Sr89       2.27E-07     7.02E-06      2.81E-05    1.12E-04    1.68E-04     3.34E-04 Sr90       3.76E-08     1.16E-06      4.65E-06    1.86E-05    2.78E-05     5.55E-05 Sr91       2.91E-07     8.84E-06      3.36E-05    1.09E-04    1.44E-04     2.05E-04 Sr92       3.38E-07     9.81E-06      3.26E-05    7.00E-05    7.63E-05     7.96E-05 LDCN-05-009                            15.4-31

COLUMBIA GENERATING STATION             Amendment 59 FINAL SAFETY ANALYSIS REPORT            December 2007 Table 15.4-7 Control Rod Drop Accident Radiological Effects (rem)
Area                      Time  TEDE Dose Exclusion area (1950 m)               2 hr      0.03 Low population zone (4827 m)          30 days   0.03 Control Room                          30 days    0.7 LDCN-05-009                                15.4-32

Amendment 53 November 1998 Abnormal Startup of an Idle Recirculation Loop at Columbia Generating Station            57.9% Uprated Power, 34.1% Flow Final Safety Analysis Report Draw. No. 020002.03    Rev. Figure 15.4-1.1

Amendment 53 November 1998 Abnormal Startup of an Idle Recirculation Loop at Columbia Generating Station            57.9% Uprated Power, 34.1% Flow Final Safety Analysis Report Draw. No. 020002.04    Rev. Figure 15.4-1.2

Amendment 53 November 1998 Abnormal Startup of an Idle Recirculation Loop at Columbia Generating Station            57.9% Uprated Power, 34.1% Flow Final Safety Analysis Report Draw. No. 020002.05    Rev. Figure 15.4-1.3

Amendment 53 November 1998 Abnormal Startup of an Idle Recirculation Loop at Columbia Generating Station            57.9% Uprated Power, 34.1% Flow Final Safety Analysis Report Draw. No. 020002.06    Rev. Figure 15.4-1.4

Amendment 53 November 1998 Abnormal Startup of an Idle Recirculation Loop at Columbia Generating Station            57.9% Uprated Power, 34.1% Flow Final Safety Analysis Report Draw. No. 020002.07    Rev. Figure 15.4-1.5

Amendment 59 December 2007 Design Basis Model Core Coolant Condenser TURBINE             No credit was taken for mixing or holdup in the Turbine Building. Therefore the BUILDING            TB was not included in the model.
Environment Leakage Path Model for Rod Drop Accident Columbia Generating Station Final Safety Analysis Report Draw. No. 960222.71         Rev.        Figure 15.4-2 Form No. 960690FH LDCN-05-009, 06-000

COLUMBIA GENERATING STATION                          Amendment 60 FINAL SAFETY ANALYSIS REPORT                        December 2009 15.5     INCREASE IN REACTOR COOLANT INVENTORY 15.5.1      INADVERTENT HIGH-PRESSURE CORE SPRAY STARTUP This transient is classified as a nonlimiting event for both original and uprated power conditions. The transient is not analyzed for each reload, but was analyzed for the GE14 New Fuel Introduction. Inadvertent startup of the high-pressure core spray (HPCS) system was analyzed because it provides the greatest auxiliary source of cold water into the vessel.
15.5.1.1       Identification of Causes and Frequency Classification 15.5.1.1.1      Identification of Causes Manual startup (i.e., operator error) and continued injection of the HPCS system is postulated for this analysis.
15.5.1.1.2      Frequency Classification This transient disturbance is categorized as an incident of moderate frequency.
15.5.1.2       Sequence of Events and Systems Operation The HPCS system is manually initiated and injects into the reactor vessel, reaching full flow in approximately one second. The addition of the cooler water to the upper plenum causes a reduction in steam flow. This causes some reactor pressure decrease as the turbine control system responds to the event. As the steam flow decreases, the feedwater system responds by decreasing flow. In less than a minute, the reactor and the auxiliary steam systems stabilize at a new, lower power level. The analysis assumes normal functioning of plant instrumentation and controls. No engineered safety feature (ESF) function is expected in response to this transient. Plant parameter responses are shown in Figure 15.5-1.
15.5.1.2.1      The Effect of Single Failures and Operator Errors Inadvertent operation of the HPCS system results in a mild depressurization. Level control and pressure regulator actuation are expected to establish a new stable operating state. The effect of a single failure in the DEH control system will have no effect on the transient because of its redundant design.
The effect of a single failure in the level control system has rather straightforward consequences including level rise or fall by improper control of the feedwater system.
Increasing level will trip the turbine and automatically stop injection by the HPCS system.
Decreasing level will automatically initiate a scram at the L3 level trip.
LDCN-08-035                                    15.5-1

COLUMBIA GENERATING STATION                           Amendment 60 FINAL SAFETY ANALYSIS REPORT                          December 2009 15.5.1.3      Core and System Performance 15.5.1.3.1      Mathematical Model The one-dimensional ODYN transient analysis model described in Reference 15.5-1 was used to simulate this transient.
15.5.1.3.2      Input Parameter and Initial Conditions The important parameters are shown in Table 15.5-1.
15.5.1.3.3      Results The calculated uncorrected CPR for the simulated bundles is less than 0.01 (Reference 15.5-2). A summary of transient key peak values is found in Table 15.0-1.
15.5.1.3.3.1 Consideration of Uncertainties. Important analytical factors including reactivity coefficient and feedwater temperature change have been assumed to be at the worst conditions so that any deviations in the actual plant parameters will produce a less severe transient.
15.5.1.4      Barrier Performance Figure 15.5-1 indicates only a slight pressure reduction from initial conditions; therefore, reactor coolant pressure boundary pressure margins are not impacted.
15.5.1.5      Radiological Consequences Since this event does not result in any fuel failures or any release of primary coolant to either the secondary containment or to the environment, there are no radiological consequences associated with this event.
15.5.2      CHEMICAL VOLUME CONTROL SYSTEM MALFUNCTION (OR OPERATOR ERROR)
This event is not applicable to boiling water reactor plants.
15.5.3      BOILING WATER REACTOR TRANSIENTS WHICH INCREASE REACTOR COOLANT INVENTORY These events are discussed in Sections 15.1 and 15.2.
LDCN-08-035                                    15.5-2

COLUMBIA GENERATING STATION                      Amendment 60 FINAL SAFETY ANALYSIS REPORT                     December 2009 15.

==5.4      REFERENCES==

15.5-1        Qualification of the One-Dimensional Core Transient Model for Boiling Water Reactors, Volumes 1, 2, 3 and 4, NEDC-24154-P-A, February 2000.
15.5-2        GE Hitachi Nucear Energy, Inadvertent High Pressure Core Spray Startup Analysis, 0000-0098-5369-R0, March 2009.
LDCN-08-035                                15.5-3

COLUMBIA GENERATING STATION                         Amendment 60 FINAL SAFETY ANALYSIS REPORT                        December 2009 Table 15.5-1 Input Parameters and Initial Conditions HPCS Injection Parameter                                         Value Reactor power                                 102% (3556 MWth)
Core flow                                     106% ICF and 88% ELLLA HPCS water source                             Suppression pool HPCS source pressure                          14.7 psia HPCS source temperature                       40&deg; F HPCS source enthalpy                          11.0 Btu/lbm HPCS pump flow                                12.6 % of rated feedwater flow (3800 gal/min)
Vessel-to-suppression pool differential       1020 psid pressure LDCN-08-035                                 15.5-5

Amendment 60 December 2009 200.0                                                                                                                 100.0 Neutron Flux Average Surface Heat Flux Core Inlet Flow Core Inlet Subcooling                                                               75.0 Vessel Press Rise (psi) 150.0                                                                                                                                                                Safety Valve Flow Relief Valve Flow Bypass Valve Flow 50.0
   % Rated                                                                                             % Rated 100.0 25.0 50.0 0.0 0.0                                                                                                                -25.0 0.0      5.0     10.0      15.0        20.0      25.0      30.0    35.0                                                  0.0     5.0     10.0      15.0         20.0        25.0         30.0   35.0 Time (sec)                                                                                                                    Time (sec) 150.0                                                                                                              0.5 Level - Inch above Sep Skirt Vessel Steam Flow                                                                                                        Void Reactivity Turbine Steam Flow                                                                                                       Doppler Reactivity 125.0                                      Feedwater Flow                                                                                                           Scram Reactivity HPCS Flow (% Rated FW)                                                                                                   Total Reactivity 0.3 Reactivity Components ($)
100.0
      % Rated 75.0                                                                                                             0.0 50.0
                                                                                                                                   -0.3 25.0 0.0                                                                                                             -0.5 0.0      5.0     10.0      15.0        20.0      25.0     30.0    35.0                                           0.0         5.0     10.0       15.0         20.0         25.0         30.0   35.0 Time (sec)                                                                                                                  Time (sec)
Inadvertent Start of High Pressure Core Columbia Generating Station                                                                     Spray Pump at 102% Uprated Power, Final Safety Analysis Report                                                                                  88% Flow Draw. No.                                020002.18                   Rev.                   Figure   15.5-1 Form No. 960690 LDCN-08-035

COLUMBIA GENERATING STATION                          Amendment 59 FINAL SAFETY ANALYSIS REPORT                         December 2007 15.6    DECREASE IN REACTOR COOLANT INVENTORY 15.6.1      INADVERTENT SAFETY/RELIEF VALVE OPENING This event is discussed in Section 15.1.4.
15.6.2      INSTRUMENT LINE PIPE BREAK This faulted condition is not a limiting event for either original or uprated power conditions.
Therefore, the uprated power analysis for the accident has not been updated.
This event involves the postulated pipe break in a small steam or liquid line that is connected to the reactor coolant pressure boundary (RCPB) and is located in the reactor building. If the break were inside primary containment, the event would be bounded by the steam line break inside containment (LOCA) (see Section 15.6.5). That event is bounding because the instrument line sizes are bounded by the spectrum of breaks considered in the LOCA analysis.
15.6.2.1      Identification of Causes and Frequency Classification 15.6.2.1.1     Identification of Causes There is no specific event or circumstance identified which results in the failure of an instrument line. These lines are designed to specific engineering specifications and standards, and seismic and environmental requirements. However, for the purpose of evaluating the consequences of this event, the failure of an instrument line is assumed to occur.
15.6.2.1.2     Frequency Classification This event is categorized as a limiting fault.
15.6.2.2      Sequence of Events and Systems Operation The instrument line ruptures (complete circumferential break) and releases reactor coolant into the secondary containment. The analysis assumes that the reactor coolant activity is at the Technical Specification limit corresponding to an iodine spike of 4&#xb5;Ci/g dose equivalent 131I and that the break cannot be isolated. The operators have a variety of methods to detect the leak such as monitoring plant area temperatures and radiation levels, system pressures, or sump inventories, or during operator rounds. It is assumed that the reactor operators identify the break after 20 minutes and initiate a reactor scram.
Using available plant systems, the operators maintain reactor water level and cool down and depressurize the reactor within 5 hr, at a rate less than or equal to the 100&deg;F/hr limit in the Technical Specifications. Examples of plant systems or components the operators can use for LDCN-06-043                                    15.6-1

COLUMBIA GENERATING STATION                           Amendment 59 FINAL SAFETY ANALYSIS REPORT                          December 2007 inventory and temperature controls include HPCS, RCIC, SRVs, RHR, or the condensate feed system. No credit is taken for the automatic initiation of the RPS or ESF.
15.6.2.2.1      The Effect of Single Failures and Operator Errors The event is handled by operator actions. Assuming additional single equipment failure or single operator error occurrences, adequate equipment would be available to respond to the loss of reactor coolant.
15.6.2.3       Core and System Performance The inventory loss is within the capacity of the make up systems available and the shutdown and the cool down are controlled evolutions. Therefore, no fuel damage will occur and no other barriers are challenged.
15.6.2.3.1      Qualitative Summary - Results Since instrument line breaks result in a slower rate of coolant loss and are bounded, the results are qualitative rather than quantitative. Since the rate of coolant loss is slow, an orderly reactor system depressurization follows reactor scram and the primary system is cooled down and maintained without ECCS actuation. No fuel damage or core uncovery occurs as a result of this event.
15.6.2.4       Barrier Performance 15.6.2.4.1      General The release of primary coolant through the orificed instrument line would not result in an increase in secondary containment pressure.
15.6.2.5       Radiological Consequences The radiological consequences are based on the following assumptions and methods:
: a.      The broken instrumentation line contains a 0.5-in. diameter flow restricting orifice inside the drywell.
: b.      Flow is critical at the orifice and is determined using the GOTHIC computer program (Reference 15.6-1) that employs the Henry model for subcooled liquid and the Moody model for saturated and superheated vapors (Reference 15.6-4).
: c.      The total integrated mass of fluid released by means of the break during the blowdown is 121,000 lb. Of this total, 29,800 lb flash to steam.
15.6-2

COLUMBIA GENERATING STATION                          Amendment 59 FINAL SAFETY ANALYSIS REPORT                         December 2007
: d. The specific models, assumptions and the program used for the radiological analysis is in Reference 15.6-3. Specific values of parameters used in the evaluation are presented in Table 15.6-1. The leakage path used in these calculations is shown in Figure 15.6-1.
: e. The activity released from the instrument line break is based on the iodine spike concentration of 4&#xb5;Ci/g dose equivalent 131I and is assumed to not mix or be held up within the secondary containment and is released to the environment at a flow rate of 80,000 cfm without SGT filtration.
: f. The activity released to the secondary containment and the environment is presented in Table 15.6-2.
15.6.2.5.1     Results The calculated exposures are presented in Table 15.6-3.
15.6.3      STEAM GENERATOR TUBE FAILURE This event is not applicable to boiling water reactor (BWR) plants.
15.6.4      STEAM SYSTEM PIPING BREAK OUTSIDE CONTAINMENT This event involves the postulation of a large steam line pipe break outside the primary containment. The analysis assumes that a main steam line instantaneously and circumferentially breaks at a location downstream of the outboard isolation valve. The plant is designed to immediately detect such an occurrence, initiate isolation of the broken line, and actuate the necessary protective features. The main steam line was selected for analysis because the postulated event envelops evaluation of steam line failures outside containment.
15.6.4.1      Identification of Causes and Frequency Classification 15.6.4.1.1     Identification of Causes A main steam line break is postulated without the cause being identified. These lines are designed to specific engineering codes and standards, and seismic and environmental requirements. However, for the purpose of evaluating the consequences of a postulated large steam line rupture, the failure of a main steam line is assumed to occur.
15.6.4.1.2     Frequency Classification This event is categorized as a limiting fault.
LDCN-06-043                                    15.6-3

COLUMBIA GENERATING STATION                             Amendment 59 FINAL SAFETY ANALYSIS REPORT                           December 2007 15.6.4.2       Sequence of Events and Systems Operation 15.6.4.2.1      Sequence of Events When the steam line breaks, steam flow through the failed line will rapidly increase, initiating the high main steam line flow trip that initiates the signal to close the main steam isolation valves (MSIVs). The closing MSIVs initiate a reactor protection (RPS) signal, scramming the reactor. The analysis assumes that the MSIVs are fully closed 6 seconds after the break.
Performance of the engineered safety feature (ESF) systems in response to the loss of coolant is discussed in Chapter 6.
The sequence of events and approximate time required to reach the event is given in Table 15.6-4.
15.6.4.2.2      Systems Operation A postulated guillotine break of one of the four main steam lines outside the containment results in mass loss from both ends of the break. The flow from the upstream side is initially limited by the flow restrictor upstream of the inboard isolation valve. Flow from the downstream side is initially limited by the total area of the flow restrictors in the three unbroken lines. Initially, only steam will issue from the broken end of the steam line. The flow in each line is limited by critical flow at the limiter to a maximum of 200% of rated flow for each line. Rapid depressurization of the RPV causes the water level to rise resulting in a steam-water mixture flowing from the break until the valves are closed. Mass loss (steam and water) is reduced and finally terminated (except for leakage) as the MSIVs close.
15.6.4.2.3      The Effect of Single Failures and Operator Errors The effect of single failures has been considered in analyzing this event. All of the protective sequences for this event are capable of single equipment failure or single operator error accommodation and yet still complete the necessary safety action.
15.6.4.3       Core and System Performance The temperature and pressure transients resulting as a consequence of this accident are insufficient to cause fuel damage.
15.6.4.3.1      Input Parameters and Initial Conditions See Section 6.3 for initial conditions.
15.6-4

COLUMBIA GENERATING STATION                           Amendment 59 FINAL SAFETY ANALYSIS REPORT                          December 2007 15.6.4.3.2      Results There is no fuel damage as a consequence of this accident.
See Section 6.3 for ECCS analysis.
15.6.4.3.3      Considerations of Uncertainties Discussions of the uncertainties associated with the ECCS performance and the containment isolation systems are discussed in Sections 6.3 and 7.3, respectively.
15.6.4.4       Barrier Performance Since this break occurs outside the primary containment, barrier performance within the containment envelope is not applicable. There are sufficient vent openings in the steam tunnel to ensure that the secondary containment structure will not be damaged.
15.6.4.5       Radiological Consequences The radiological analysis is based on NRC Regulatory Guide 1.183 (Reference 15.6-5). The dispersion of the plume is based on the puff model given in Regulatory Guide 1.194 (Reference 15.6-6).
The specific models, assumptions, and the program used for computer evaluation are described in Reference 15.6-3. Specific values of parameters used in the evaluation are presented in Table 15.6-5. There is no fuel damage as a result of this accident. The only activity available for release from the break is that which is present in the reactor coolant and steam lines prior to the break. The iodine inventories and the subsequent exposures are based on the equilibrium conditions and maximum reactor coolant activity for an iodine spiking event as allowed by the Technical Specifications. The analysis assumes all the activity in this discharge becomes airborne and released directly and unfiltered to the environment. The release of activity to the environment is presented in Table 15.6-6.
The following assumptions and conditions are used in determining the mass loss from the primary system from the inception of the break to full closure of the MSIVs:
: a.      The reactor is operating at the power level associated with maximum mass release,
: b.      Nuclear system pressure is 1060 psia and remains constant during closure,
: c.      An instantaneous circumferential break of the main steam line occurs, LDCN-05-009                                    15.6-5

COLUMBIA GENERATING STATION                            Amendment 59 FINAL SAFETY ANALYSIS REPORT                           December 2007
: d. Isolation valves start to close at 0.5 sec on high flow signal and are fully closed at 6 sec,
: e. The Moody critical flow model (Reference 15.6-4) is applicable, and
: f. The flow limiters allow up to 200% of rated flow through the MSIVs, and
: g. Level rise time is conservatively assumed to be one second. Mixture quality is conservatively taken to be a constant 7% (steam weight percentage) during mixture flow.
The total integrated mass leaving the RPV through the steam line break is 130,000 lb of which 105,000 lb is liquid and 25,000 lb is steam. Only the liquid portion of the discharged coolant is assumed to carry the iodine activity of 4 &#xb5;Ci/gm dose-equivalent of I-131. The entire amount of activity in the liquid is assumed to be released to the environment.
The transport pathway is a direct unfiltered release to the environment and an unfiltered entrance to the control room as presented in Figure 15.6-2.
15.6.4.5.1     Results The calculated doses for the design basis analysis are presented in Table 15.6-7. The doses are within the limits of 10 CFR 50.67.
15.6.5      LOSS-OF-COOLANT ACCIDENTS (RESULTING FROM SPECTRUM OF POSTULATED PIPING BREAKS WITHIN THE REACTOR COOLANT PRESSURE BOUNDARY) - INSIDE CONTAINMENT Accidents that could result in the release of radioactive fission products directly into the containment are the results of postulated breaks in the reactor coolant system pressure boundary (RCPB). The analysis postulates that the most severe pressurization transient to the primary containment is caused by a complete circumferential break of the suction line of one of the two recirculation loops. Flow through the break transports the reactor vessel contents to the suppression pool.
The loss-of-coolant accident (LOCA) postulates the break of any of the spectrum of piping systems that form the RCPB. The plant and operator responses to the spectrum of breaks are presented in Chapter 6. Chapter 6 demonstrates that fuel, core, and barrier performance requirements are met for the spectrum of breaks. The bounding radiological analysis for the LOCA event detailed in this section reflects an inadequate core cooling accident that degrades to complete core damage. The event assumed for the analysis is the break inside containment of one of the main steam lines. The radiological analysis assumptions presented in LDCN-05-009                                    15.6-6

COLUMBIA GENERATING STATION                           Amendment 59 FINAL SAFETY ANALYSIS REPORT                          December 2007 Section 15.6.5 are separate and distinct and are not mechanistically tied to the pipe break analyzed in Chapter 6.
15.6.5.1       Identification of Causes and Frequency Classification 15.6.5.1.1      Identification of Causes There are no realistic, identifiable events that would result in a pipe break inside the containment of the magnitude required to cause the fuel damage sufficient to release the source terms assumed in this section. The piping is designed to specific engineering codes and standards and for severe seismic and environmental conditions. However, since such an accident provides an upper limit estimate of the dose consequences for the limiting faulted condition, it is evaluated without the causes being identified.
15.6.5.1.2      Frequency Classification This event is categorized as a limiting fault.
15.6.5.2       Sequence of Events and Systems Operation The sequence of events and system operations are discussed in Chapter 6. The effect of single failures and operator errors is discussed in Chapter 6.
15.6.5.3       Core and System Performance For the plant response to the LOCA and the evaluation of the system and core performance, see Chapter 6.
15.6.5.4        Radiological Consequences The radiological consequences are based on the guidance provided in Regulatory Guide 1.183 (Reference 15.6-5) for the purpose of determining adequacy of the plant design to meet 10 CFR 50.67 limits.
A schematic of the transport pathway is shown in Figure 15.6-3.
15.6.5.4.1      Design Basis Analysis The specific models, assumptions, and computer code used to evaluate the radiological consequences of the bounding LOCA based on the above criteria are presented in Reference 15.6-3. Specific values of parameters used in this evaluation are presented in Table 15.6-8.
LDCN-05-009                                    15.6-7

COLUMBIA GENERATING STATION                           Amendment 59 FINAL SAFETY ANALYSIS REPORT                          December 2007 15.6.5.4.1.1 Fission Product Release from Fuel. It is assumed that 100% of the noble gases and 30% of the iodine are released from an equilibrium core operating at a power level of 3556 MWt for 1000 days prior to the accident. Of this release, 100% of the noble gases become airborne. Some of the iodine is removed by plate-out and filtration; therefore, it is not available for airborne release to the environment. The activity airborne in the containment is presented in Table 15.6-9.
15.6.5.4.1.2 Fission Product Transport to the Environment. The fission product transport to the environment consists of two basic pathways. One transport pathway consists of leakage from the containment to the secondary containment by several different mechanisms and is discharged to the environment through the SGT system at an elevated location. Of the secondary containment flow, 50 cfm bypasses the SGT filters. The second transport pathway consists of leakage from the containment directly to the environment through piping systems that originate in containment and terminate outside the reactor building. The individual mechanisms for leakage from the primary containment are:
: a.      Containment leakage - Leakage from primary containment to the secondary containment. Prior to the completion of secondary containment drawdown this leakage is assumed to be a direct release to the environment; however, when drawdown is complete, 20 minutes post accident, this leakage is treated by the SGT system before it is released to the environment. No credit is taken for forced mixing and holdup within the secondary containment.
: b.      ESF leakage - Leakage from engineered safety feature (ESF) components outside the primary containment (all ESF equipment which circulates primary coolant or suppression pool water during the course of the postulated accident) to the secondary containment. This leakage is treated in a manner similar to the containment leakage described above.
: c.      Hydrogen purge - No hydrogen purge is required or assumed throughout the postaccident period.
: d.      MSIV leakage - Leakage from the primary containment (or the RPV) through the main steam isolation valves (MSIVs) to the turbine building. Iodine is assumed to plate-out in three of the four main steam lines. Plate-out in the broken fourth main steam line is not credited. In that line it is assumed one MSIV fails open (single failure), whereas all MSIVs in the other three steam lines are assumed to close.
: e.      Bypass leakage - Leakage from the primary containment that bypasses the secondary containment and is released, untreated, directly to the environment.
LDCN-05-009                                   15.6-8

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 Fission product activities in secondary containment and those released to the environment based on the above assumptions are given in Tables 15.6-10 and 15.6-11, respectively.
15.6.5.4.1.3 Suppression Pool pH Control. The suppression pool pH is maintained above 7.0 for the duration of the accident as a result of the standby liquid control system injection of sodium pentaborate solution. The solution is assumed to be injected and fully mixed with the suppression pool water within 8 hours post-LOCA.
15.6.5.4.1.4 Results. The calculated doses for the design basis analysis are presented in Table 15.6-12 and are within the limts of 10 CFR 50.67.
15.6.6      FEEDWATER LINE BREAK - OUTSIDE CONTAINMENT In order to evaluate large liquid process line pipe breaks outside containment, the failure of a feedwater line is assumed to evaluate the response of the plant design to this postulated event.
The postulated break of the feedwater line, representing the largest liquid line outside the containment, provides the envelope evaluation relative to this type of occurrence. The break is assumed to be instantaneous, circumferential, and outboard of the outermost isolation valve.
The analysis has not been updated for the change in MSIV isolation setpoint from Level 2 to Level 1 because the analysis remains bounded by the recirculation line break LOCA (Reference 15.6-9).
15.6.6.1       Identification of Causes and Frequency Classification 15.6.6.1.1      Identification of Causes A feedwater line break is assumed without the cause being identified. The subject piping is designed to specific engineering codes and standards.
15.6.6.1.2      Frequency Classification This event is categorized as a limiting fault.
15.6.6.2       Sequence of Events and Systems Operation 15.6.6.2.1      Sequence of Events The sequence of events is shown in Table 15.6-13.
15.6.6.2.2      Systems Operation It is assumed that the normally operating plant instrument and controls are functioning. Credit is taken for the actuation of the reactor isolation system and ECCS. The RPS (SRVs, ECCS, LDCN-09-007                                     15.6-9

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 and control rod drives) and plant protection system (RHR heat exchanger) are assumed to function. The ESF system is assumed to operate normally. Although not an ECCS and not credited nor required for mitigation of this event, RCIC will also be used if available for maintaining vessel level as it initiates at approximately the same low reactor vessel level as HPCS.
15.6.6.2.3      The Effect of Single Failures and Operator Errors The feedwater line outside the containment is a special case of the general LOCA break spectrum considered in Section 6.3. The general single-failure analysis for LOCAs is discussed in Section 6.3.3.3. For the feedwater line break outside the containment, since the break is isolable, the HPCS can provide adequate flow to the vessel to maintain core cooling and prevent fuel rod cladding failure. A single failure of the HPCS would require actuation of ADS and the low-pressure core cooling systems to keep the core covered with water.
15.6.6.3       Core and System Performance 15.6.6.3.1      Qualitative Summary The accident evaluation qualitatively considered in this section is considered to be conservative and to envelope assessment of the consequences of the postulated failure of one of the feedwater piping lines external to the containment. The accident is postulated to occur at the input parameters and initial conditions given in Table 6.3-2.
15.6.6.3.2      Qualitative Results The feedwater line break outside the containment is less limiting than the steam line break outside the containment or the LOCA inside the containment.
The reactor vessel is isolated on low-low water level and the HPCS would restore the reactor water level to the normal elevation. The fuel is covered throughout the event and there are no pressure or temperature transients sufficient to cause fuel damage.
15.6.6.3.3      Consideration of Uncertainties This event was conservatively analyzed and uncertainties were adequately considered (see Section 6.3 for details).
15.6.6.4       Barrier Performance A break spectrum analysis for the complete range of reactor conditions indicates that the limiting fault event for breaks outside the containment is a complete severance of one of the 15.6-10

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 main steam lines. The feedwater system piping break is less severe than the main steam line break.
15.6.6.5       Radiological Consequences The specific models, assumptions, and the program used for computer evaluation are described in Reference 15.6-2. Specific values of parameters used in the evaluation are presented in Table 15.6-14. A diagram of the leakage path for this accident is shown in Figure 15.6-4.
15.6.6.5.1      Fission Product Release Fission product release is assumed to occur from two pathways: activity being pumped from the condenser hotwell and activity returning to the feedwater system from the reactor water cleanup (RWCU) system. The activity in both of these sources is based on the Technical Specification coolant limit.
Noble gas activity in the condensate is negligible since the air ejectors remove most of the noble gas from the condenser.
15.6.6.5.2      Fission Product Transport to the Environment The transport pathway consists of liquid release from the break, carryover to the turbine building atmosphere due to flashing and partitioning and unfiltered release to the environment through the turbine building ventilation system.
Of the 860,000 lb of condensate released from the break, 86,000 lb flashes to steam with assumed iodine carryover of 100%. Of the activity remaining in the unflashed liquid, 5% is assumed to become airborne. Normally, all feedwater reaching the break location will have passed through condensate demineralizers which have a 90% iodine removal efficiency.
However, as a result of the increased feedwater flow caused by the break, differential pressure across the demineralizers is assumed to initiate flow through the demineralizer bypass line.
This bypass line then carries 15% of the total flow resulting in an effective iodine removal efficiency for all flow of 76.5%. In addition, it is also assumed that 2771 lb of liquid returning from the RWCU are released prior to isolation of the RWCU. The activity concentration in this return steam is 1% of the RPV coolant concentration.
Taking no credit for holdup, decay, or plate-out during transport through the turbine building, the release of activity to the environment is presented in Table 15.6-15. The release is assumed to take place within 2 hr of the occurrence of the break.
15.6-11

COLUMBIA GENERATING STATION                          Amendment 63 FINAL SAFETY ANALYSIS REPORT                         December 2015 15.6.6.5.3     Results The calculated exposures for the realistic analysis are presented in Table 15.6-16 and are a small fraction of 10 CFR 100 guidelines.
15.

==6.7      REFERENCES==

15.6-1         GOTHIC Containment Analysis Package, Technical Manual, Version 4.0, Numerical Applications, Inc., NA18907-06, Revision 3.
15.6-2         Nguyen, D., Realistic Accident Analysis for General Electric Boiling Water Reactor - The RELAC Code and Users Guide, (NEDO-21142).
15.6-3         Energy Northwest, Columbia Generating Station Alternative Source Term, CGS-FTS-0168, Revision 2, June 2011.
15.6-4         Moody, F. J, Maximum Two-Phase Vessel Blowdown from Pipes, ASME Paper Number 65-WA/HT-1, March 15, 1965.
15.6-5         Regulatory Guide 1.183, Revision 0, Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors, July, 2000.
15.6-6         Regulatory Guide 1.194, Revision 0, Atmospheric Relative Concentrations for Control Room Radiological Habitability Assessments at Nuclear Power Plants, July, 2003.
15.6-7         Federal Guidance Report 11, Limiting Values of Radionuclide Intake and Air Concentration and Dose Conversion Factors for Inhalation, Submersion and Ingestion, Oak Ridge National Laboratory, 1988.
15.6-8         Federal Guidance Report 12, External Exposure to Radionuclides in Air, Water and Soil, Oak Ridge National Laboratory, 1993.
15.6-9         GE Hitachi Nuclear Energy, License Amendment Request for Proposed Changes to Columbia Technical Specifications: Changing Group 1 Isolation Valves Low Reactor Water Level Isolation Signal from the Current Level 2 to Level 1, 0000-0081-6730-R1, July 2008.
LDCN-15-011                                  15.6-12

COLUMBIA GENERATING STATION                     Amendment 59 FINAL SAFETY ANALYSIS REPORT                    December 2007 Table 15.6-1 Instrument Line Break Accident - Parameters Tabulated for Postulated Accident Analyses Design Basis Parameters                                Assumptions I.      Data and assumptions used to estimate radioactive source from postulated accidents A.      Power level                                               N/A B.      Burnup                                                    N/A C.      Fuel damaged                                              None D.      Airborne activity by nuclide                              Table 15.6-2 E.      Iodine fractions (1)      Organic                                          0.15%
(2)      Elemental                                        4.85%
(3)      Particulate                                      95%
F.      Initial reactor coolant activity with iodine spike        4 ci/g 131 I                                                      1.6 ci/g 132 I                                                      14.8 ci/g 133 I                                                      11.0 ci/g 134 I                                                      30.0 ci/g 135 I                                                      16.0 ci/g II. Data and assumptions used to estimate activity released A.      Primary containment leak rate (%/day)                     N/A B.      Secondary containment effluent rate (cfm)                 80,000a C.      Valve movement times                                      N/A D.      Adsorption and filtration efficiencies (1)      Organic iodine                                   N/A (2)      Elemental iodine                                 N/A (3)      Particulate iodine                               N/A (4)      Particulate fission products                     N/A E.      Recirculation system parameters (1)      Flow rate                                        N/A (2)      Mixing efficiency                                N/A (3)      Filter efficiency                                N/A F.      Containment spray parameters (flow rate, drop size, etc.) N/A G.      Containment volumes                                       N/A H.      All other pertinent data and assumptions                  None LDCN-06-043                                 15.6-13

COLUMBIA GENERATING STATION                      Amendment 59 FINAL SAFETY ANALYSIS REPORT                     December 2007 Table 15.6-1 Instrument Line Break Accident - Parameters Tabulated for Postulated Accident Analyses (Continued)
Design Basis Parameters                                 Assumptions III. Dispersion data A. Offsite                                               See Table 15.0-4 B. Control Room                                          See Table 15.0-5 IV. Dose data A. Method of dose calculation                            Reference 15.6-5 B. Dose conversion assumptions                           Reference 15.6-7 C. Peak activity released from secondary containment     Table 15.6-2 D. Doses                                                 Table 15.6-3 a
No forced mixing in secondary containment is considered.
LDCN-06-043                                 15.6-14

COLUMBIA GENERATING STATION                  Amendment 59 FINAL SAFETY ANALYSIS REPORT                 December 2007 Table 15.6-2 Instrument Line Failure Activity Airborne in Secondary Containment (Ci) 2 hr             5 hr             8 hr        1 day      30 days 133 Xe     7.02E-07        2.60E-07        0.00E+00     0.00E+00    0.00E+00 135 Xe     1.22E-05        3.67E-06        0.00E+00     0.00E+00    0.00E+00 Total     1.29E-05        3.93E-06        0.00E+00     0.00E+00    0.00E+00 131 I     2.00E-02        8.09E-03        0.00E+00     0.00E+00    0.00E+00 132 I     1.03E-01        1.72E-02        0.00E+00     0.00E+00    0.00E+00 133 I     1.29E-01        4.80E-02        0.00E+00     0.00E+00    0.00E+00 134 I     7.60E-02        2.80E-03        0.00E+00     0.00E+00    0.00E+00 135 I     1.64E-01        4.93E-02        0.00E+00     0.00E+00    0.00E+00 Total     4.92E-01        1.25E-01        0.00E+00     0.00E+00    0.00E+00 Activity Airborne in the Environment (Ci) 2 hr             5 hr             8 hr        1 day      30 days 133 Xe     1.90E-03        3.93E-03         4.91E-03     6.06E-03    6.08E-03 135 Xe     3.56E-02        6.76E-02         8.02E-02     9.06E-02    9.06E-02 Total     3.75E-02        7.15E-02         8.51E-02     9.67E-02    9.67E-02 131 I    4.87E+01        8.46E+01         8.72E+01     8.72E+01    8.72E+01 132 I    3.51E+02        4.81E+02         4.86E+02     4.86E+02    4.86E+02 133 I    3.26E+02        5.51E+02         5.65E+02     5.65E+02    5.65E+02 134 I    4.91E+02        5.52E+02         5.53E+02     5.53E+02    5.53E+02 135 I    4.46E+02        7.06E+02         7.22E+02     7.22E+02    7.22E+02 Total    1.66E+03        2.37E+03         2.41E+03     2.41E+03    2.41E+03 LDCN-06-043                              15.6-15

COLUMBIA GENERATING STATION                          Amendment 59 FINAL SAFETY ANALYSIS REPORT                        December 2007 Table 15.6-3 Instrument Line Failure Radiological Effects Total Effective Dose Equivalent      Limit Area                                     (rem)               (rem TEDE)
Control Room                                                1.58                    5 Exclusion area (1950 m) (2 hr)                              0.36                   2.5 Low population zone (4827 m) (30 days)                      0.16                   2.5 LDCN-06-043                                 15.6-16

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 Table 15.6-4 Sequence of Events for Steam Line Break Outside Containment Time                                       Event 0       Guillotine break of one main steam line outside primary containment.
0.5a    High steam line flow signal initiates closure of MSIV.
      <1.0       Reactor begins to scram.
      >6.0       Main steam line isolation valves fully closed.
10        Safety/relief valves open on high vessel pressure. The valves open and close to maintain vessel pressure at approximately 1100 psi.
600        Operator initiates ADS or manually controls relief valves. Vessel depressurizes rapidly.
750        High-pressure core spray initiates on low water level.
1270         Core effectively reflooded. No fuel rod failure.
a Approximately.
LDCN-03-003                             15.6-17

COLUMBIA GENERATING STATION                       Amendment 59 FINAL SAFETY ANALYSIS REPORT                      December 2007 Table 15.6-5 Steam Line Break Accident - Parameters Tabulated for Postulated Accident Analyses Design Basis Parameters                             Assumptions I. Data and assumptions used to estimate radioactive source from postulated accidents.
A.      Power level                                                N/A B.      Burnup                                                     N/A C.      Fuel damaged                                               None D.      Release of activity by nuclide                             Table 15.6-6 1
E.      Iodine fractions (1)      Organic                                           N/A (2)      Elemental                                         N/A (3)      Particulate                                       N/A F.      Reactor coolant activity before the accident corresponds 4 ci/gm to the iodine spike of 4 ci/gm dose-equivalent I-131 II. Data and assumptions used to estimate activity released.
A.      Primary containment leak rate (%/day)                      N/A B.      Secondary containment leak rate (%/day)                    N/A C.      Isolation valve closure time (sec)                         6 D.      Adsorption and filtration efficiencies (1)      Organic iodine1                                   N/A (2)      Elemental iodine                                  N/A (3)      Particulate iodine                                N/A (4)      Particulate fission products                      N/A 1
Since no filtration is credited, speciation of iodines is not applicable.
LDCN-05-009                                     15.6-18

COLUMBIA GENERATING STATION                       Amendment 59 FINAL SAFETY ANALYSIS REPORT                      December 2007 Table 15.6-5 Steam Line Break Accident - Parameters Tabulated for Postulated Accident Analyses (Continued)
Design Basis Parameters                                  Assumptions E. Recirculation system parameters                           N/A (1)    Flow rate                                          N/A (2)    Mixing efficiency                                  N/A (3)    Filter efficiency                                  N/A F. Containment spray parameters (flow rate, drop size, etc.) N/A G. Containment volumes                                       N/A H. All other pertinent data and assumptions                  None III. Dispersion data (1)    Offsite                                            Table 15.0-4 (2)    Control Room                                       8.19 E-4 sec/m3 IV. Dose data A. Method of dose calculation                                Reference 15.6-3 B. Dose conversion assumptions                               Reference 15.6-7 C. Peak activity concentrations in containment               N/A D. Doses                                                     Table 15.6-7 LDCN-05-009                                  15.6-19

COLUMBIA GENERATING STATION           Amendment 59 FINAL SAFETY ANALYSIS REPORT          December 2007 Table 15.6-6 Steam Line Break Accident Activity Release to Environment (Curies)
Activity Isotope                         Released 131 I                              1.91E 02 LDCN-05-009                          15.6-20

COLUMBIA GENERATING STATION                   Amendment 59 FINAL SAFETY ANALYSIS REPORT                  December 2007 Table 15.6-7 Steam Line Break Accident Radiological Effects of a Puff Release Area                         TEDE (rem)
Exclusion area (1950 m)                          0.40 Low population zone (4827 m)                     0.11 Control Room                                     1.8 LDCN-05-009                             15.6-21

COLUMBIA GENERATING STATION                      Amendment 59 FINAL SAFETY ANALYSIS REPORT                     December 2007 Table 15.6-8 Loss-of-Coolant Accident - Parameters Tabulated for Postulated Accident Analysis Design Basis Parameters                                    Assumptions I.      Data and assumptions used to estimate radioactive source from postulated accidents A.      Power level                                3556 B.      Burnup                                     N/A C.      Fuel damaged                               100%
D.      Airborne activity by nuclide               Table 15.6-10 and 15.6-11 E.      Iodine fractions (1)    Organic                             0.0015 (2)    Elemental                           0.0485 (3)    Particulate                         0.95 F.      Reactor coolant activity before the        N/A accident II. Data and assumptions used to estimate activity released A.      Primary containment leak rate includes     0 - 24 hrs       0.5 MSIV leakage (% volume/day)                 24 - 720 hrs     0.25 B.      Secondary containment leak rate (%/day)    N/A C.      Drawdown period (minutes)                  20 D.      Adsorption and filtration efficiencies (%)
(1)    Organic iodine                      98%
(2)    Elemental iodine                    98%
(3)    Particulate iodine                  98%
(4)    Particulate fission products        98%
LDCN-05-009                                   15.6-22

COLUMBIA GENERATING STATION                       Amendment 59 FINAL SAFETY ANALYSIS REPORT                      December 2007 Table 15.6-8 Loss-of-Coolant Accident - Parameters Tabulated for Postulated Accident Analysis (Continued)
Design Basis Parameters                                     Assumptions E. Secondary containment volumetric         50 flow rate bypassing SGT filters1, cfm F. Secondary containment bypass             0 - 24 hrs   0.04% volume per day leakage                                  24 - 720 hrs 0.02% volume per day G. Recirculation system parameters (1)     Flow rate (cfm)                  N/A (2)     Mixing efficiency                N/A (3)     Filter efficiency                N/A H. Containment spray removal rates          Time (hr)    Removal Rate (1/hr) 0                0.0 0.25             6.20 2.44             0.62 24.0             0.0 I. Containment volumes                      Table 6.2-1 J. MSIV leak rate per steam line            0 - 24 hrs   16 scfh 24 - 720 hrs 8 scfh K. ESF leakage into secondary               2 gpm containment L. CREF bypass leakage                      50 cfm III. Dispersion data (1)     Offsite                          Table 15.0-4 (2)     Control room                     Table 15.0-5 1
SGT filter bypass will reduce SGT filter efficiency from 99% to 98%.
LDCN-05-009                                   15.6-23

COLUMBIA GENERATING STATION                        Amendment 59 FINAL SAFETY ANALYSIS REPORT                       December 2007 Table 15.6-8 Loss-of-Coolant Accident - Parameters Tabulated for Postulated Accident Analysis (Continued)
Design Basis Parameters                                    Assumptions IV.      Dose data A. Method of dose calculation                 Reference 15.6-5 B. Dose conversion assumptions                Reference 15.6-7, 15.6-8 C. Peak activity concentrations in            Table 15.6-9 containment D. Doses                                      Table 15.6-12 LDCN-05-009                                 15.6-24

LDCN-05-009 Table 15.6-9 Loss-of-Coolant Accident Primary Containment1 Activity (Curies)
Isotope                0.25 hr       0.5 hr        0.8 hr       1.0 hr     2.0 hr     4.0 hr     8.0 hr     24.0 hr     30 day 131 I                  2.15E+06      1.72E+06      2.42E+06     2.63E+06   2.69E+06   3.93E+05   1.25E+05   4.09E+04    3.03E+03 132 I                  2.82E+06      2.10E+06      2.75E+06     2.79E+06   2.15E+06   2.17E+05   3.57E+04   1.12E+02    1.03E-01 133 I                  4.16E+06      3.30E+06      4.62E+06     4.97E+06   4.95E+06   6.82E+05   1.92E+05   3.92E+04    3.25E-06 134 I                  3.81E+06      2.49E+06      2.87E+06     2.55E+06   1.18E+06   3.47E+04   4.52E+02   4.13E-04         0 COLUMBIA GENERATING STATION 135 I                  3.78E+06      2.94E+06      4.05E+06     4.29E+06   3.97E+06   4.77E+05   1.02E+05   6.80E+03         0 Total iodines          1.67E+07      1.26E+07      1.67E+07     1.72E+07   1.49E+07   1.80E+06   4.55E+05   8.71E+04    3.03E+03 83m Kr                 2.51E+05      4.92E+05      1.80E+06     3.02E+06   5.87E+06   2.84E+06   6.34E+05   1.58E+03         0 85m Kr                 5.45E+05      1.13E+06      4.35E+06     7.71E+06   1.86E+07   1.39E+07   7.36E+06   5.84E+05         0 85 Kr                  3.17E+04      6.82E+04      2.74E+05     5.05E+05   1.43E+06   1.46E+06   1.46E+06   1.45E+06    1.29E+06 87 Kr                  9.02E+05      1.69E+06      5.92E+06     9.53E+06   1.56E+07   5.33E+06   5.97E+05   9.35E+01         0 15.6-25 88 Kr                  1.38E+06      2.79E+06      1.05E+07     1.82E+07   4.03E+07   2.51E+07   9.29E+06   1.76E+05         0 FINAL SAFETY ANALYSIS REPORT 89 Kr                  6.47E+04      5.31E+03      8.12E+02     5.71E+01   3.42E-04   1.60E-15   3.36E-38   5.95E-129        0 131m Xe                2.15E+04      4.63E+04      1.86E+05     3.42E+05   9.66E+05   9.81E+05   9.71E+05   9.30E+05    1.56E+05 133m Xe                1.28E+05      2.74E+05      1.10E+06     2.01E+06   5.63E+06   5.60E+06   5.33E+06   4.33E+06    6.17E+02 133 Xe                 4.19E+06      9.00E+06      3.61E+07     6.64E+07   1.87E+08   1.89E+08   1.86E+08   1.72E+08    3.52E+06 135m Xe                4.40E+05      4.87E+05      1.00E+06     9.51E+05   1.88E+05   9.29E+02   2.18E-02        0           0 135 Xe                 1.02E+06      2.23E+06      8.57E+06     1.56E+07   4.20E+07   4.21E+07   3.82E+07   1.79E+07         0 137 Xe                 2.50E+05      3.75E+04      1.05E+04     1.35E+03   8.99E-02   5.09E-11   1.59E-29   1.52E-103        0 138 Xe                 1.50E+06      1.75E+06      3.81E+06     3.82E+06   9.34E+05   7.13E+03   3.98E-01   3.87E-18         0 Total noble gases      1.07E+07      2.00E+07      7.36E+07     1.28E+08   3.19E+08   2.86E+08   2.50E+08   1.97E+08    4.97E+06 Alkali metals          9.84E+05      7.85E+05      9.21E+05     9.62E+05   9.72E+05   1.29E+05   3.05E+04   9.57E+01    7.73E+01 Te-group               2.83E+05      2.31E+05      2.04E+06     2.49E+06   2.41E+06   3.09E+05   6.56E+04   1.72E+02    5.34E+01 Noble metals           0.00E+00      0.00E+00      1.55E+05     1.97E+05   1.99E+05   2.57E+04   5.82E+03   1.60E+01    3.99E+00 Amendment 59 La-group               0.00E+00      0.00E+00      2.40E+04     3.19E+04   3.17E+04   9.64E+03   3.11E+03   1.33E+01    1.00E+01 Ce-group               0.00E+00      0.00E+00      1.15E+05     1.46E+05   1.52E+05   1.98E+04   4.49E+03   1.18E+01    1.05E+00 December 2007 1
Primary Containment includes the Dry Well & the Wet Well Air-Space

LDCN-05-009 Table 15.6-10 Loss-of-Coolant Accident Secondary Containment Activity (Curies) - 20 Minute Drawdown Isotope             0.25 hr    0.5 hr     0.75 hr    1 hr       2 hr        4 hr       8 hr       24 hr      30 day 131 I                    0     6.89E+00   9.90E+00   1.15E+01   1.50E+01    7.11E+00   6.08E+00   5.47E+00   4.11E-01 132 I                    0     8.38E+00   1.13E+01   1.22E+01   1.19E+01    3.26E+00   8.84E-01   6.86E-03   1.79E-07 133 I                    0     1.32E+01   1.89E+01   2.17E+01   2.75E+01    1.23E+01   9.36E+00   5.24E+00        0 134 I                    0     9.98E+00   1.18E+01   1.12E+01   6.54E+00    6.29E-01   2.20E-02   5.53E-08        0 COLUMBIA GENERATING STATION 135 I                    0     1.18E+01   1.65E+01   1.88E+01   2.21E+01    8.61E+00   4.95E+00   9.08E-01        0 Total iodines            0     5.02E+01   6.84E+01   7.54E+01   8.29E+01    3.19E+01   2.13E+01   1.16E+01   4.11E-01 83m Kr                   0     1.65E+00   5.88E+00   1.02E+01   2.02E+01    9.84E+00   2.20E+00   5.47E-03        0 85m Kr                   0     3.77E+00   1.42E+01   2.59E+01   6.40E+01    4.81E+01   2.55E+01   2.03E+00        0 85 Kr                    0     2.28E-01   8.97E-01   1.70E+00   4.91E+00    5.06E+00   5.06E+00   5.03E+00   2.24E+00 15.6-26 FINAL SAFETY ANALYSIS REPORT 87 Kr                    0     5.66E+00   1.94E+01   3.21E+01   5.36E+01    1.85E+01   2.07E+00   3.25E-04        0 88 Kr                    0     9.33E+00   3.44E+01   6.13E+01   1.38E+02    8.69E+01   3.22E+01   6.10E-01        0 89 Kr                    0     1.78E-02   2.66E-03   1.92E-04   1.17E-09    5.56E-21   1.17E-43        0          0 131m Xe                  0     1.55E-01   6.08E-01   1.15E+00   3.32E+00    3.40E+00   3.37E+00   3.22E+00   2.70E-01 133m Xe                  0     9.17E-01   3.59E+00   6.78E+00   1.93E+01    1.94E+01   1.85E+01   1.50E+01   1.07E-03 133 Xe                   0     3.01E+01   1.18E+02   2.24E+02   6.43E+02    6.59E+02   6.49E+02   6.06E+02   6.47E+00 135m Xe                  0     1.63E+00   3.29E+00   3.20E+00   6.44E-01    3.22E-03   7.58E-08        0          0 135 Xe                   0     7.70E+00   2.87E+01   5.35E+01   1.50E+02    1.61E+02   1.57E+02   8.24E+01        0 137 Xe                   0     1.25E-01   3.43E-02   4.53E-03   3.09E-07    1.77E-16   5.52E-35        0          0 138 Xe                   0     5.87E+00   1.25E+01   1.28E+01   3.21E+00    2.47E-02   1.38E-06        0          0 Total noble gases        0     6.72E+01   2.42E+02   4.33E+02   1.10E+03    1.01E+03   8.95E+02   7.14E+02   8.98E+00 Amendment 59 Alkali metals            0     2.75E+00   3.18E+00   3.33E+00   3.38E+00    4.51E-01   1.07E-01   3.34E-04   1.34E-04 Te-group                 0     8.69E-01   6.92E+00   8.69E+00   8.45E+00    1.08E+00   2.29E-01   5.99E-04   9.28E-05 Noble metals             0     0.00E+00   5.18E-01   6.76E-01   6.92E-01    8.96E-02   2.03E-02   5.60E-05   6.92E-06 December 2007 La-group                 0     0.00E+00   8.11E-02   1.12E-01   1.12E-01    3.36E-02   1.09E-02   4.65E-05   1.74E-05 Ce-group                 0     0.00E+00   3.82E-01   5.04E-01   5.30E-01    6.92E-02   1.57E-02   4.11E-05   1.81E-06

LDCN-05-009 Table 15.6-11 Loss-of-Coolant Accident Activity Released to the Environment (Curies) - 20 Minute Drawdown Isotope             0.25 hrs   0.5 hrs    0.75 hrs   1 hrs      2 hrs       4 hrs      8 hrs      24 hrs     30 d 131 I               6.59E+01   1.39E+02   1.80E+02   2.31E+02   4.48E+02    5.49E+02   6.37E+02   8.35E+02   3.03E+03 132 I               8.83E+01   1.82E+02   2.31E+02   2.89E+02   5.27E+02    7.45E+02   1.13E+03   2.52E+03   1.15E+04 133 I               1.28E+02   2.69E+02   3.47E+02   4.44E+02   8.49E+02    1.03E+03   1.17E+03   1.42E+03   1.67E+03 134 I               1.23E+02   2.45E+02   2.99E+02   3.53E+02   4.98E+02    5.25E+02   5.28E+02   5.28E+02   5.28E+02 COLUMBIA GENERATING STATION 135 I               1.17E+02   2.44E+02   3.13E+02   3.97E+02   7.35E+02    8.74E+02   9.63E+02   1.05E+03   1.06E+03 Total iodines       5.22E+02   1.08E+03   1.37E+03   1.71E+03   3.06E+03    3.72E+03   4.43E+03   6.35E+03   1.78E+04 83m Kr              1.09E+01   4.59E+01   1.47E+02   3.80E+02   2.19E+03    4.92E+03   6.81E+03   7.35E+03   7.35E+03 85m Kr              2.34E+01   1.02E+02   3.43E+02   9.21E+02   6.15E+03    1.67E+04   2.99E+04   4.36E+04   4.42E+04 85 Kr               1.34E+00   6.00E+00   2.09E+01   5.82E+01   4.33E+02    1.37E+03   3.25E+03   1.07E+04   1.64E+05 15.6-27 87 Kr               3.98E+01   1.62E+02   5.03E+02   1.25E+03   6.46E+03    1.27E+04   1.55E+04   1.59E+04   1.59E+04 FINAL SAFETY ANALYSIS REPORT 88 Kr               5.95E+01   2.55E+02   8.42E+02   2.22E+03   1.40E+04    3.49E+04   5.53E+04   6.71E+04   6.73E+04 89 Kr               9.01E+00   1.13E+01   1.16E+01   1.16E+01   1.16E+01    1.16E+01   1.16E+01   1.16E+01   1.16E+01 131m Xe             9.12E-01   4.07E+00   1.42E+01   3.94E+01   2.93E+02    9.28E+02   2.18E+03   7.06E+03   5.55E+04 133m Xe             5.42E+00   2.41E+01   8.40E+01   2.33E+02   1.72E+03    5.38E+03   1.24E+04   3.71E+04   9.18E+04 133 Xe              1.77E+02   7.92E+02   2.76E+03   7.66E+03   5.68E+04    1.80E+05   4.22E+05   1.35E+06   6.45E+06 135m Xe             2.28E+01   6.80E+01   1.40E+02   2.36E+02   4.35E+02    4.58E+02   4.59E+02   4.59E+02   4.59E+02 135 Xe              4.33E+01   1.98E+02   6.85E+02   1.86E+03   1.34E+04    4.24E+04   9.96E+04   2.67E+05   3.33E+05 137 Xe              2.69E+01   3.79E+01   3.99E+01   4.04E+01   4.04E+01    4.04E+01   4.04E+01   4.04E+01   4.04E+01 138 Xe              7.66E+01   2.35E+02   5.02E+02   8.78E+02   1.74E+03    1.87E+03   1.87E+03   1.87E+03   1.87E+03 Total noble gases   4.97E+02   1.94E+03   6.09E+03   1.58E+04   1.04E+05    3.02E+05   6.49E+05   1.81E+06   7.23E+06 Alkali metals       2.99E+01   6.16E+01   7.76E+01   9.54E+01   1.68E+02    1.96E+02   2.10E+02   2.14E+02   2.16E+02 Te-group            6.96E+00   1.64E+01   3.87E+01   8.25E+01   2.70E+02    3.38E+02   3.71E+02   3.81E+02   3.82E+02 Amendment 59 Noble metals        0          0          1.54E+00   4.94E+00   2.01E+01    2.56E+01   2.84E+01   2.93E+01   2.94E+01 La-group            0          0          2.30E-01   7.72E-01   3.23E+00    4.56E+00   5.82E+00   6.30E+00   6.65E+00 Ce-group            0          0          1.13E+00   3.66E+00   1.51E+01    1.94E+01   2.15E+01   2.22E+01   2.22E+01 December 2007

COLUMBIA GENERATING STATION        Amendment 59 FINAL SAFETY ANALYSIS REPORT       December 2007 Table 15.6-12 Loss-of-Coolant Accident (Design Basis Analysis)
Radiological Effects TEDE Total Effect                                (rem)
Exclusion area (1950 m) (2 hr)               4.1 Low population zone (4827 m) (30 days)       4.0 Control Room (30 days)                       3.5 LDCN-05-009                                15.6-28

COLUMBIA GENERATING STATION                         Amendment 61 FINAL SAFETY ANALYSIS REPORT                        December 2011 Table 15.6-13 Sequence of Events for Feedwater Line Break Outside Containment Time                                           Event 0                 One feedwater line breaks.
0+                Feedwater line check valves isolate the reactor from the break.
   <30 sec           At low reactor water level, reactor scram would initiate and, at low-low reactor water level, HPCS and MSIV closureb would initiate and recirculation pumps would trip.
2 minutesa        The SRVs open and close and maintain the reactor vessel pressure at approximately 1100 psig.
1 to 2 hr         Normal reactor cooldown established.
a Approximately.
b The analysis has not been updated for the change in MSIV isolation setpoint from Level 2 to Level 1 because it remains bounded by the recirculation line break LOCA (Reference 15.6-9).
LDCN-09-007                                 15.6-29

COLUMBIA GENERATING STATION                     Amendment 59 FINAL SAFETY ANALYSIS REPORT                    December 2007 Table 15.6-14 Feedwater Line Break Accident - Parameters Tabulated for Postulated Accident Analysis Parameter                                   Value I. Data and assumptions used to estimate radioactive source from postulated accidents A. Power level                                            N/A B. Burnup                                                 N/A C. Fuel damaged                                           None D. Release of activity by nuclide                         Table 15.6-15 E. Iodine fractions (1)     Organic                                        0 (2)     Elemental                                      1%
(3)     Particulate                                    0 (4)     Reactor coolant activity before the accident   Section 15.6.6.5.1 II. Data and assumptions used to estimate activity released A. Primary containment leak rate (%/day)                  N/A B. Secondary containment leak rate (%/day)                N/A C. RWCU total isolation valve closure time (sec)          75 D. Adsorption and filtration efficiencies (1)     Organic iodine                                 N/A (2)     Elemental iodine                               N/A (3)     Particulate iodine                             N/A (4)     Particulate fission products                   N/A E. Recirculation system parameters                        N/A (1)     Flow rate                                      N/A (2)     Mixing efficiency                              N/A (3)     Filter efficiency                              N/A F. Containment spray parameters (flow rate, drop size,    N/A etc.)
G. Containment volumes                                    N/A H. All other pertinent data and assumptions               None 15.6-30

COLUMBIA GENERATING STATION                       Amendment 59 FINAL SAFETY ANALYSIS REPORT                      December 2007 Table 15.6-14 Feedwater Line Break Accident - Parameters Tabulated for Postulated Accident Analysis (Continued)
Parameter                                    Value III. Dispersion data A. Boundary and LPZ distance (m)                     1950/4827 B.     /Qs for time intervals of 0-2 hr - EAB/LPZ       2.62 x 10-4/1.06 x 10-4 IV. Dose data A. Method of dose calculation                        Reference 15.6-2 B. Dose conversion assumptions                       Reference 15.6-2 C. Peak activity concentrations in containment       N/A D. Doses                                             Table 15.6-16 15.6-31

COLUMBIA GENERATING STATION           Amendment 59 FINAL SAFETY ANALYSIS REPORT          December 2007 Table 15.6-15 Feedwater Line Break Accident Activity Release to Environment (Curies)
Isotope                          Activity 131 I                           2.22 x 10-2 132 I                           2.05 x 10-1 133 I                           1.52 x 10-1 134 I                           4.45 x 10-1 135 I                           2.22 x10-1 Total                          1.04 x 10 15.6-32

COLUMBIA GENERATING STATION             Amendment 59 FINAL SAFETY ANALYSIS REPORT            December 2007 Table 15.6-16 Feedwater Line Break Accident Biological Effects of a Puff Release Whole Body Dose    Thyroid Dose Area                             (rem)          (rem)
Exclusion area (1950 m)                     1.37 x 10-4     5.47 x 10-3 Low population zone (4827 m)                5.53 x 10-5     2.21 x 10-3 15.6-33

Amendment 53 November 1998 Turbine Building Main Steam Line Isolation Valves Turbine            Turbine Flow P                                                               Stop Valve         Admission Break                                                 Valve Reactor Vessel Check Valve Steam Tunnel Flow Limiter Containment Bypass Line Main Turbine Main Condenser Feedwater Pump Steam Flow Schematic for Steam Break Columbia Generating Station                                   Outside Containment Final Safety Analysis Report Draw. No. 900547.74                  Rev.      Figure   15.6-2 Form No. 960690

Amendment 59 December 2007 SGT Secondary Containment PC leakage t > 20 min KK-doors + RB Walls Environment Drywell Primary Containment leakage                                              PC leakage for t < 20 min SC bypass leakage MSIV leakage from failed steamline MSIV leakage from the 3 intact steamlines                                    plateout Core t > 20 min Wet Well Air-Space Suppression Pool                 ESF leakage (1 gpm)                                           t < 20 min Leakage Path for LOCA Columbia Generating Station Final Safety Analysis Report Draw. No.                   900547.75        Rev.          Figure                15.6-3 Form No. 960690FH LDCN-05-009

Amendment 53 November 1998 Turbine (Steam)
Flow Main Containment Condenser Hotwell Break Reactor                             Pumps/Heaters/             Pumps/Demin/
Vessel                                 Controls                   Controls Check   Check Valve    Valve Bypass Check Valve Leakage Path for Feedwater Line Break Columbia Generating Station                                Outside Containment Final Safety Analysis Report Draw. No. 900547.76      Rev. Figure 15.6-4 Form No. 960690

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 15.7    RADIOACTIVE RELEASE FROM SUBSYSTEMS AND COMPONENTS These events are classified as nonlimiting events for both original and uprated power conditions. Therefore, no further analysis has been performed.
15.7.1      RADIOACTIVE GAS WASTE SYSTEM LEAK OR FAILURE Not applicable.
15.7.2      LIQUID RADIOACTIVE SYSTEM FAILURE Not applicable.
15.7.3      POSTULATED RADIOACTIVE RELEASES DUE TO LIQUID RADWASTE TANK FAILURE 15.7.3.1       Identification of Causes and Frequency Classification 15.7.3.1.1      Identification of Causes The liquid radwaste tanks are constructed to specific engineering codes and standards and to the uniform building code seismic requirements. These tanks operate at atmosphere pressure and low temperatures. A positive action interlock system is provided to prevent inadvertent opening of a drain valve because of operator error. Accordingly, the possibility of a complete tank failure or drainage is considered small.
An unspecified event is postulated to cause the complete release of the average radioactivity inventory in the tank containing the largest quantities of significant radionuclides in the liquid radwaste system. The tank postulated to rupture is one of the two decontamination solution concentrated waste tanks (see Figure 11.2-1).
15.7.3.1.2      Frequency Classification This accident is categorized as a limiting fault.
15.7.3.2       Sequence of Events and Systems Operation 15.7.3.2.1      Sequence of Events The sequence of events expected to occur is as follows:
15.7-1

COLUMBIA GENERATING STATION                         Amendment 55 FINAL SAFETY ANALYSIS REPORT                        May 2001 Sequence of Events - Liquid Radwaste Tank Failure Events                                    Time Event begins-failure occurs                                0 Area radiation alarms alert plant personnel            1 minute Operator action begins                                 10 minute 15.7.3.2.2     Systems Operation Failure of a concentrated waste tank does not require a shutdown nor does it impair a safe shutdown. It will lead to limited operation of the concentrated waste system using the remaining tank.
The liquid contents of this tank will also be contained by the building walls and an unlined, 18-in. high concrete dike around the radwaste tank area. Floor drain sump pumps would receive a high water level alarm, activate automatically, and remove the spilled liquid.
15.7.3.2.3     The Effects of Single Failures and Operator Errors This event has been analyzed without taking credit for any expected operator action or system operation; therefore, a discussion of single equipment failure or single operator error is not applicable.
15.7.3.3      Core and System Performance The failure of this liquid radwaste system component does not directly affect the nuclear steam supply system (NSSS). It will lead to decoupling of NSSS with the subject system.
This failure has no applicable effect on the reactor core or the NSSS safety performance.
Specific assumptions and parameters are presented in Table 15.7-1.
15.7.3.4      Barrier Performance This event does not involve any containment barrier integrity except the tank itself and the radwaste building. The dike and walls of the radwaste building surrounding the tanks are built to Seismic Category I criteria. In the analysis of spill consequences, no credit is taken for the dike or radwaste building in recontaining the spilled liquid.
LDCN-00-034                                    15.7-2

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 15.7.3.5      Radiological Consequences The entire volume (700 gal) of concentrator waste tank assumed to spill with isotope inventory given in Table 11.2-1. Tritium concentration is assumed to be 0.01 Ci/ml (Environmental Report, Operating License Section 3.5.1).
The hypothetical radwaste tank failure was evaluated using conservative assumptions such as no containment in the radwaste building and unimpeded flow vertically through 50-60 ft of sand and gravel.
The following offsite concentration data for the radionuclides of interest are provided for the WNP-1/4 wells and at the Columbia River:
Concentration              Concentration at at WNP-1/4 Wells              Columbia River             Concentration Radionuclide                  (Ci/ml)                    (Ci/ml)               Limit (Ci/ml) 3 H                       1.0 x 10-7                  1.3 x 10-8                   1 x 10-3 90 Sr                     1.7 x 10-4                  4.2 x 10-7                   5 x 10-7 137 Cs                    2.2 x 10-10                 1.4 x 10-27                  1 x 10-6 The calculations show the strontium concentration exceeding the unrestricted area limitation at the WNP-1/4 wells. These wells are a temporary water supply and are under the control of Energy Northwest. Should a spill occur there will be ample time to assess the severity and extent of contamination.
Concentration at the river bank will be diluted by the river flow. The nearest surface water users are several miles downstream.
15.7.4      FUEL HANDLING ACCIDENT 15.7.4.1      Identification of Causes and Frequency Classification 15.7.4.1.1     Identification of Causes The fuel handling accident is assumed to occur as a consequence of a failure of the fuel assembly lifting mechanism resulting in dropping a raised irradiated fuel assembly onto other fuel bundles seated in the reactor pressure vessel (RPV). The event was selected as the bounding event because it considers the maximum height and weight, while assuming a minimum water level above the damaged fuel.
15.7.4.1.2     Frequency Classification This event is categorized as a limiting fault.
LDCN-03-003                                    15.7-3

COLUMBIA GENERATING STATION                          Amendment 59 FINAL SAFETY ANALYSIS REPORT                         December 2007 15.7.4.2        Sequence of Events and Systems Operation The following sequence of events is assumed in the analysis.
No fuel movement will take place in the first 24 hr following shutdown. At 24 hr post-shutdown fuel movement starts and the fuel handling equipment is assumed to fail dropping the fuel grapple and an irradiated fuel bundle onto the irradiated fuel bundles seated in the RPV.
Fuel is damaged and fission products are released to the reactor coolant, then to the reactor building atmosphere, and finally to the environment over a 2-hr period. No credit is taken for holdup or mixing in the reactor building, nor is credit taken for filtration by the standby gas treatment (SGT).
15.7.4.2.1       The Effects of Single Failures and Operator Errors No systems or operator actions are credited to mitigate a fuel handling accident.
15.7.4.3        Core and System Performance 15.7.4.3.1       Mathematical Model Because of the complex nature of the impact and the resulting damage to fuel assembly components, a rigorous prediction of the number of failed rods is not possible. For this reason, a simplified energy approach was taken and numerous conservative assumptions were made to ensure a conservative estimate of the number of failed rods.
The kinetic energy acquired by a falling fuel assembly may be dissipated in one or more impacts. The energy absorption on successive impacts is estimated by considering a plastic impact.
The energy transferred in the dropped assembly is considered in two phases. First, the fuel assembly is expected to impact on the reactor core at a small angle from the vertical, inducing a bending mode of failure on the fuel rods of the dropped assembly. The kinetic energy of the fall is dissipated in the impact. The analysis assumes that the energy of the dropped assembly is absorbed by only the cladding and other core structures. The assumption that no energy is absorbed by the fuel material results in considerable conservatism in the mass-energy calculations. Half of the energy is dissipated in the structure of the dropped assembly, failing all the rods in the assembly. The remaining half is allocated evenly across the structural mass of the impacted assemblies. The energy dissipated by the cladding is calculated by multiplying the impacted assembly energy by the cladding mass fraction and dividing by the energy required to fail a rod (based on 1% uniform plastic deformation).
LDCN-05-009                                    15.7-4

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 The second phase considers the kinetic energy developed by the irradiated fuel assembly and lifting mechanism tipping over and impacting the core horizontally. The kinetic energy developed is equal to the initial potential energy of the assembly relative to the top of the core.
Again, half of the energy is absorbed by the dropped assembly and half by the impacted assemblies. The number of failed rods in the impacted assemblies is determined using the cladding mass fraction and the energy required to fail a rod.
15.7.4.3.2      Input Parameters and Initial Conditions The parameters and conditions used to determine the number of failed rods are listed below:
: a.      The fuel assembly is dropped from a height of 34 ft. The maximum height allowed by the fuel handling equipment is less than 34 ft;
: b.      The dropped mass consists of a fuel assembly (600 lb bounding analyzed wet weight for GNF2 10 x 10 fuel, 586 lb bounding analyzed wet weight for GE14 10 x 10 fuel, 617 lb wet weight for GE 8 x 8 fuel and 665 lb dry weight for ATRIUM-10) and the fuel grapple (350 lb wet weight);
: c.      The energy required to fail a fuel rod is approximately 157 ft-lb for GNF2 10 x 10 fuel, 175 ft-lb for GE14 10 x 10 fuel, 250 ft-lb for GE 8 x 8 fuel and 205 ft-lb for ATRIUM-10; see Reference 15.7-3 for SVEA-96.
15.7.4.3.3      Results Based on a core of GE 8 x 8 fuel, the calculation predicts 124 failed fuel rods; 62 rods in the dropped assembly, 43 rods in the first impact, and 19 additional rods in the second impact.
Westinghouse analysis predicts a maximum of 123 failed rods (Reference 15.7-3) and AREVA NP calculated that up to 156 rods could fail (Reference 15.7-4). Analysis of the GE14 10 x 10 fuel estimates that a total of 151 fuel rods will fail (Reference 15.7-5). Analysis of GNF2 10 x 10 fuel estimates that a total of 172 fuel rods will fail.
15.7.4.4       Barrier Performance The reactor coolant pressure boundary, primary containment and secondary containment are open at the time of the accident. However, a similar event could occur in the spent fuel pool (SFP), during spent fuel transfer from the RPV to, or handling in, the SFP. Assuming a drop height of 4 ft, the number of failed rods as a result of a GE 8 x 8 bundle (unchanneled) drop in the SFP was calculated and found to be 90 rods; the number for channeled GE 8 x 8 is less than that. The dose analysis for a drop of a bundle over the core, which assumes 250 failed rods, bounds a drop of a bundle in the SFP.
LDCN-15-011                                    15.7-5

COLUMBIA GENERATING STATION                          Amendment 60 FINAL SAFETY ANALYSIS REPORT                        December 2009 15.7.4.5       Radiological Consequences The fission product inventory is based on a plant-specific ORIGEN 2 run for pre-power uprate basis of 3489 MW with 1000 days exposure adjusted as described in Section 15.4.9.5.1. The release is based on damage to 250 fuel rods. A 24-hr period for decay from the power condition is assumed. Figure 15.7-1 indicates the leakage flow path for this accident.
15.7.4.5.1      Design Basis Analysis Specific values of parameters used in the evaluation are presented in Table 15.7-2. The dispersion coefficients used to determine offsite doses are presented in Table 15.0-4.
15.7.4.5.1.1 Fission Product Release From Fuel. The fission product inventory of a core average exposure fuel rod is adjusted by a peaking factor of 1.7 to establish the inventory of each damaged rod. Five percent of the noble gases inventory (10% for 85Kr) and 5% of the iodine inventory (8% for 131I), and 12% of the alkali metals inventory are assumed to be released to the reactor well. The activity airborne in the secondary containment is presented in Table 15.7-3.
15.7.4.5.1.2 Fission Product Transport to the Environment. The transport pathway consists of mixing in the reactor well water, migration from the reactor well to the secondary containment atmosphere, and release to the environment without passing through the SGT. All of the noble gas, 0.5% of the iodines, and 0% of the alkali metals are assumed to become airborne in the secondary containment (Reference 15.7-1).
From the activity airborne in the reactor building, 99% is released to the environment in 2 hr.
The release of activity to the environment is presented in Table 15.7-4.
15.7.4.5.1.3 Results. The calculated doses for the design basis analysis are presented in Table 15.7-5 and are within the limits of 10 CFR 50.67.
15.7.5      SPENT FUEL CASK DROP ACCIDENT The spent fuel cask is equipped with ANSI N14.6 (Reference 15.7-2) compliant lifting lugs and a lifting yoke compatible with the reactor building crane main hook. The reactor building crane is provided with sufficient redundancy such that no credible postulated failure of any crane component required to lift, hold, and move loads, will result in the dropping of the fuel cask. Therefore, an analysis of the spent fuel cask drop is not required.
15.7-6

COLUMBIA GENERATING STATION                       Amendment 63 FINAL SAFETY ANALYSIS REPORT                      December 2015 15.

==7.6      REFERENCES==

15.7-1        Energy Northwest, Columbia Generating Station Alternative Source Term, CGS-FTS-0168, Revision 2, June 2011.
15.7-2        Special Lifting Devices for Shipping Containers Weighing 10,000 Pounds (4500 kg) or More, ANSI N14.6-1993, June 1993.
15.7-3        ABB/Combustion Engineering, Fuel Assembly Mechanical Design Report for WNP-2, CE NPSD-792-P, May 1996.
15.7-4        AREVA NP, Columbia Generating Station Cycle 19 Reload Analysis, ANP-2602, Revision 0, March 2007.
15.7-5        GEH-0000-0075-4920, GE14 Fuel Design Cycle-Independent Analyses for Energy Northwest Columbia Generating Station (most recent version referenced in the COLR).
LDCN-15-011                                 15.7-7

COLUMBIA GENERATING STATION                        Amendment 57 FINAL SAFETY ANALYSIS REPORT                       December 2003 Table 15.7-1 Liquid Radwaste Tanks Failure - Parameters and Concentrations Parameter                                    Value I. Data and assumptions used to estimate             Entire volume (700 gal) of radioactive source                                concentrator waste tank assumed to spill with isotope inventory given in Table 11.2-1. Tritium concentration assumed to be 0.01 mCi/ml from the CGS ER-OL.
II. Data and assumptions used to estimate activity released A.      Containment leak rate (%/day)             N/A B.      Secondary containment leak rate (%/day)   N/A C.      Valve movement times                      N/A D.      Absorption and filtration efficiencies    N/A (1)     Organic iodine                    N/A (2)     Elemental iodine                  N/A (3)     Particulate iodine                N/A (4)     Particulate fission products      N/A E.      Recirculation system parameters           N/A (1)     Flow rate                         N/A (2)     Mixing efficiency                 N/A (3)     Filter efficiency                 N/A F.      Containment spray parameters (flow        N/A rate, drop size, etc.)
G.      Containment volumes                       N/A H.      Other pertinent data and assumptions      See Section 2.4.13.3 III. Concentration data
          @ WNP-1/4 Wells                                          Conc. Limita Radionuclide        @ Col. R (Ci/ml)       (Ci/ml)               (Ci/ml) 3 H                       1.0 x 10-7             1.3 x 10  -8 1 x 10-3 90 Sr                     1.7 x 10-4             4.2 x 10-7              5 x 10-7 137 Cs                    2.2 x 10-10            1.4 x 10-27             1 x 10-6 a
From 10 CFR Part 20.
15.7-9

COLUMBIA GENERATING STATION                   Amendment 59 FINAL SAFETY ANALYSIS REPORT                  December 2007 Table 15.7-2 Fuel Handling Accident Parameters Tabulated for Postulated Accident Analysis Design Basis Parameters                             Assumptions I.      Data and assumptions used to estimate radioactive source from postulated accidents A. Power level                                      3556 Fuel decay period                                24 hrs B. Radial peaking factor                            1.7 C. Assumed fuel damaged                             250 rods Bundles in the core                              764 Rods per bundle                                  62 D. Release of activity from the gap to the reactor  Figure 15.7-1 well water E. Iodine species fractions released                Figure 15.7-1 (1)    Organic (2)    Elemental (3)    Particulate F. Reactor coolant activity before the accident     N/A II. Data and assumptions used to estimate activity released A. Primary containment leak rate (%/day)            N/A B. Secondary containment release rate               99% of the activity in 2 hr with a flow rate of 2.3 SC volumes per hr C. Valve movement times                             N/A D. SGT filtration                                   N/A E. Scrubbing by reactor well water                  Figure 15.7-1 (1)    Organic iodine (2)    Elemental iodine (3)    Particulate iodine (4)    Particulate alkali metals LDCN-05-009                                  15.7-10

COLUMBIA GENERATING STATION                       Amendment 59 FINAL SAFETY ANALYSIS REPORT                      December 2007 Table 15.7-2 Fuel Handling Accident Parameters Tabulated for Postulated Accident Analysis (Continued)
Design Basis Parameters                                  Assumptions F. Recirculation system parameters (1)     Flow rate                                     N/A (2)     Mixing efficiency                             N/A (3)     Filter efficiency                             N/A G. Containment spray parameters (flow rate,              N/A drop size, etc.)
H. Containment volumes                                   N/A I. Other pertinent data and assumptions (1)     SGT filtration                                None (2)     CREF filtration                               None (3)     Holdup in reactor building                    None (4)     Mixing in reactor building                    None III. Dispersion data (for duration of release, 0 - 2 hr)
(1)    Offsite                                           Table 15.0-4 (2)    Control room                                      8.69E-4 sec/m3 IV. Dose data A. Method of dose calculation                        Regulatory Guide 1.183 B. Dose conversion assumptions                       Regulatory Guide 1.183 C. Peak activity concentrations in containment       N/A D. Doses                                             Table 15.7-5 LDCN-05-009                                   15.7-11

LDCN-05-009 Table 15.7-3 Fuel Handling Accident Activity Airborne in Secondary Containment (Curies)
Isotope   6 minutes   12 minutes    0.5 hr       1 hr          2 hr         4 hr        8 hr       1 day       4 days     30 days 131 I         2.64E+02    2.10E+02     1.05E+02    3.31E+01      3.29E+00     3.26E+00    3.22E+00    3.04E+00    2.35E+00     2.51E-01 132 I          1.95E-01    1.50E-01     6.87E-02    1.87E-02      1.39E-03     7.65E-04    2.33E-04    1.98E-06    9.73E-16    6.23E-20 133 I         1.58E+02    1.25E+02     6.19E+01    1.93E+01      1.86E+00     1.74E+00    1.52E+00     8.96E-01    8.21E-02    8.31E-11 COLUMBIA GENERATING STATION 134 I          1.54E-06    1.13E-06     4.44E-07    9.40E-08      4.21E-09     8.45E-10    3.40E-11    8.99E-17    6.50E-19    1.25E-36 135 I         2.72E+01    2.14E+01     1.04E+01    3.11E+00       2.80E-01     2.28E-01    1.51E-01    2.91E-02    1.75E-05    1.10E-22 Total iodine    4.49E+02    3.56E+02     1.77E+02    5.55E+01      5.43E+00     5.23E+00    4.90E+00    3.97E+00    2.43E+00     2.51E-01 83m Kr         5.55E-01    4.25E-01     1.90E-01    4.98E-02      3.42E-03     1.62E-03    3.62E-04    9.06E-07    1.78E-18    7.63E-20 15.7-12 FINAL SAFETY ANALYSIS REPORT 85m Kr        2.10E+02    1.64E+02     7.85E+01    2.29E+01      1.95E+00     1.42E+00     7.57E-01    6.04E-02    6.91E-07    5.85E-21 85 Kr         1.06E+03    8.42E+02     4.22E+02    1.33E+02      1.33E+01     1.33E+01    1.33E+01    1.33E+01    1.33E+01    1.32E+01 87 Kr          3.24E-02    2.43E-02     1.03E-02    2.49E-03      1.44E-04     4.81E-05    5.39E-06    8.50E-10    9.87E-22    1.21E-30 88 Kr         6.26E+01    4.85E+01     2.26E+01    6.30E+00       4.91E-01     2.99E-01    1.11E-01    2.11E-03    3.80E-11    4.03E-22 89 Kr          6.66E-19    1.43E-19     1.54E-21    1.49E-23      1.56E-24     2.38E-20    3.88E-19    4.10E-20    1.19E-19    4.03E-51 131m Xe    3.39E+02    2.70E+02     1.35E+02    4.26E+01      4.24E+00     4.22E+00    4.18E+00    4.02E+00    3.38E+00     7.55E-01 133m Xe    1.58E+03    1.25E+03     6.26E+02    1.97E+02      1.94E+01     1.89E+01    1.80E+01    1.47E+01    5.95E+00     2.34E-03 133 Xe        6.73E+04    5.34E+04     2.68E+04    8.50E+03      9.24E+02     1.30E+03    1.98E+03    3.78E+03    4.60E+03    1.62E+02 135m Xe     1.92E-20    1.17E-20     2.64E-21    2.22E-22      1.88E-24     1.85E-26    4.61E-28    1.38E-20    1.72E-21    7.32E-53 135 Xe        1.67E+04    1.32E+04     6.58E+03    2.14E+03      3.64E+02     1.02E+03    1.71E+03    1.39E+03    1.22E+01     5.37E-20 Amendment 59 137 Xe         6.42E-21    1.76E-21     3.71E-23    2.48E-25      6.80E-27     4.31E-24    1.39E-19    1.11E-20    1.01E-20    8.74E-51 138 Xe         1.73E-20    1.07E-20     2.58E-21    2.42E-22      2.50E-24     2.92E-26    4.76E-28    1.83E-21    2.69E-22    3.34E-52 Total noble December 2007 gases           8.73E+04    6.92E+04     3.47E+04    1.10E+04      1.33E+03     2.36E+03    3.73E+03    5.20E+03    4.63E+03    1.76E+02

LDCN-05-009 Table 15.7-4 Fuel Handling Accident Activity Released to the Environment (Curies)
Isotope   6 minutes   12 minutes    0.5 hr       1 hr         2 hr          4 hr        8 hr       1 day       4 days     30 days 131 I         6.84E+01    1.23E+02     2.28E+02    2.98E+02     3.28E+02      3.28E+02    3.29E+02    3.29E+02    3.29E+02    3.29E+02 132 I          5.12E-02    9.07E-02     1.63E-01    2.07E-01     2.23E-01      2.23E-01    2.23E-01    2.23E-01    2.23E-01    2.23E-01 133 I         4.09E+01    7.33E+01     1.35E+02    1.77E+02     1.95E+02      1.95E+02    1.95E+02    1.95E+02    1.95E+02    1.95E+02 COLUMBIA GENERATING STATION 134 I          4.16E-07    7.21E-07     1.23E-06    1.49E-06     1.56E-06      1.56E-06    1.56E-06    1.56E-06    1.56E-06    1.56E-06 135 I         7.07E+00    1.26E+01     2.31E+01    3.01E+01     3.28E+01      3.28E+01    3.28E+01    3.28E+01    3.28E+01    3.28E+01 Total iodine    1.16E+02    2.09E+02     3.86E+02    5.06E+02     5.56E+02      5.56E+02    5.57E+02    5.57E+02    5.57E+02    5.57E+02 83m Kr         1.47E-01    2.59E-01     4.61E-01    5.81E-01     6.21E-01      6.21E-01    6.21E-01    6.21E-01    6.21E-01    6.21E-01 15.7-13 FINAL SAFETY ANALYSIS REPORT 85m Kr        5.49E+01    9.78E+01     1.78E+02    2.30E+02     2.50E+02      2.50E+02    2.50E+02    2.50E+02    2.50E+02    2.50E+02 85 Kr         2.75E+02    4.93E+02     9.13E+02    1.20E+03     1.32E+03      1.32E+03    1.32E+03    1.32E+03    1.32E+03    1.32E+03 87 Kr          8.63E-03    1.51E-02     2.64E-02    3.28E-02     3.47E-02      3.47E-02    3.47E-02    3.47E-02    3.47E-02    3.47E-02 88 Kr         1.64E+01    2.92E+01     5.26E+01    6.73E+01     7.26E+01      7.26E+01    7.26E+01    7.26E+01    7.26E+01    7.26E+01 89 Kr          3.64E-19    4.43E-19     4.64E-19    4.64E-19     4.64E-19      4.64E-19    4.65E-19    4.78E-19    4.38E-16    1.27E-13 131m Xe    8.80E+01    1.58E+02     2.92E+02    3.85E+02     4.23E+02      4.23E+02    4.23E+02    4.23E+02    4.23E+02    4.23E+02 133m Xe    4.10E+02    7.35E+02     1.36E+03    1.79E+03     1.96E+03      1.96E+03    1.96E+03    1.96E+03    1.96E+03    1.96E+03 133 Xe        1.74E+04    3.13E+04     5.79E+04    7.63E+04     8.40E+04      8.40E+04    8.40E+04    8.40E+04    8.40E+04    8.40E+04 135m Xe     5.74E-21    9.23E-21     1.34E-20    1.46E-20     1.47E-20      1.47E-20    1.47E-20    1.47E-20    9.44E-18    1.02E-13 135 Xe        4.34E+03    7.78E+03     1.44E+04    1.89E+04     2.10E+04      2.10E+04    2.10E+04    2.10E+04    2.10E+04    2.10E+04 Amendment 59 137 Xe         3.03E-21    3.86E-21     4.16E-21    4.17E-21     4.17E-21      4.17E-21    4.31E-21    2.95E-20    8.44E-16    1.27E-13 138 Xe         5.10E-21    8.26E-21     1.22E-20    1.34E-20     1.35E-20      1.35E-20    1.35E-20    1.35E-20    5.69E-18    1.05E-13 Total noble December 2007 gases           2.26E+04    4.06E+04     7.51E+04    9.89E+04     1.09E+05      1.09E+05    1.09E+05    1.09E+05    1.09E+05    1.09E+05

COLUMBIA GENERATING STATION                    Amendment 59 FINAL SAFETY ANALYSIS REPORT                   December 2007 Table 15.7-5 Fuel Handling Accident (Design Basis Analysis)
Radiological Effects Area                        TEDE (rem)
Exclusion area (1950 m) (2 hr)                      1.0 Low population zone (4827 m) (30 day)               0.3 Control room (30 day)                               3.7 LDCN-05-009                             15.7-14

Amendment 59 December 2007 Core Gap
                                                       % Activity        Species Fractions Released Released Particulate Elemental Organic Iodines                    5            0.95     0.0485 0.0015 I-131                      8            0.95     0.0485 0.0015 Noble Gas                  5            0.00     1.0000 0.0000 Kr-85                     10            0.00     1.0000 0.0000 Alkali Metals             12            1.00     0.0000 0.0000 (Cs & Rb)
Reactor Well Water (Scrubbing)
Scrubbing by Reactor Well Water
                                                                     % Scrubbed % Released                DF Particulate*           100 .000           0.000 Elemental               99.714            0.286 350 Organic                   0.286          99.714         1
* All Alkali Metals are particulates and get 100% scrubbed, All particulate iodines convert to elemental.
Secondary Containment                 (1) No SGT Filtration (2) No Holdup in Reactor Building (3) No Mixing in Reactor Building Only noble gases, elemental and organic iodines get released to the environment and to the Control Room No CREF filtration Environment:                                Control Room EAB and LPZ Leakage Path for Fuel Handling Accident Columbia Generating Station Final Safety Analysis Report Draw. No. 900547.77       Rev.        Figure  15.7-1 Form No. 960690FH LDCN-05-009

COLUMBIA GENERATING STATION                          Amendment 59 FINAL SAFETY ANALYSIS REPORT                        December 2007 15.8    ANTICIPATED TRANSIENTS WITHOUT SCRAM 15.8.0       CAPABILITIES OF PRESENT DESIGN TO ACCOMMODATE ANTICIPATED TRANSIENTS WITHOUT SCRAM The anticipated transients without scram (ATWS) events described in this section are not design basis events for Columbia Generating Station (CGS). A proposed method for minimizing the effects of failure-to-scram is described in References 15.8-1 and 15.8-2.
The recirculation pump trip (RPT), alternate rod insertion (ARI), and two pump standby liquid control (SLC) system operation features are utilized at CGS to provide protection against failure to scram. Due to the CGS design feature utilizing SLC system injection through the high-pressure core spray (HPCS) header, a plant-unique analysis was performed to demonstrate ATWS protection and mitigation at pre-power uprate conditions.
The ATWS acceptance criteria are established in Reference 15.8-3 as:
: a.        The reactor coolant pressure boundary (RCPB) remains below emergency pressure limits,
: b.        The containment pressure remains below design limits. The suppression pool temperature remains below local saturation temperature limits as defined in Reference 15.8-3,
: c.        A coolable geometry is maintained,
: d.        Radiological releases are maintained within 10 CFR 100 allowable limits. With implementation of Alternate Source Term (AST), the radiological release acceptance criterion becomes 10 CFR 50.67, and
: e.        Equipment necessary to mitigate the postulated ATWS event are evaluated to provide a high degree of assurance (assurance of function) that it will function in the environment (pressure, temperature, humidity, and radiation) predicated to occur as a result of the ATWS event.
The ATWS analysis, performed in conformance with NEDE-24222, did not include a SLCS pump suction valve delay in the SLCS injection time. To determine the impact of the 35 sec opening time for the suction valves upstream of the SLCS pumps, the limiting ATWS event for peak suppression pool temperature (i.e., MSIVC) was analyzed with the 35 sec delay in SLC system injection time. The results presented for the hot shutdown time, peak suppression pool temperature, and peak containment pressure for MSIVC in Table 15.8-3 include the effects of the 35 sec delay.
LDCN-05-009, 07-011                             15.8-1

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 Section 15.8.9 shows that for the ATWS event with the most severe heat flux transient, fuel related applicable limits were met with considerable margins. In addition, Reference 15.8-3 concludes that maximum peak cladding temperature will not exceed 2200F and the maximum local oxidation will be much less than 17%. Thus, criteria 3 and 4 are shown to be satisfied by the plant specific and generic analyses. Sections 15.8.7 and 15.8.9 show that resulting primary system pressures will be less than emergency pressure limit and that suppression pool temperature increase and peak pressure are within design limits. Reference 15.8-3 concludes that the safety/relief valve (SRV) air clearing loads will be bounded by the design loads. Thus criteria 1 and 2 are satisfied. In Reference 15.8-5, Energy Northwest concluded that ATWS equipment had been determined to be qualified by (a) materials analysis of agreeable components including test reports when available, (b) existing qualification to other accident profiles (LOCA, HELB) that encompass the ATWS profile, or (c) location in a mild environment that is not affected by the ATWS accident environment. This satisfies criterion 5.
Power Uprate Evaluation The ATWS events were analyzed at power uprate operating conditions to demonstrate protection and mitigation of the consequences of these events. These analyses were performed at 3629 MWt power level and bound operation at uprate power level of 3486 MWt. The selection of critical events which were analyzed were guided by Reference 15.8-3.
For power uprate evaluation, it was conservatively assumed that ARI has failed, thus, requiring SLC system injection to achieve reactor shutdown.
The analysis presented herein are applicable to application of flow control valve (FCV) or adjustable speed drive to reactor recirculation system (RRC). A summary of ATWS results are shown in Table 15.8-3. The analysis results presented in this section are based on a representative reload core at the time of the analysis (Cycle 8). Power uprate ATWS analyses were performed with Extended Load Line Limit Analysis (ELLLA) operating conditions.
These analyses show that performance at the power uprate condition is within vessel maximum pressure, fuel temperature and containment pressure limits for the most severe ATWS transients (Reference 15.8-6).
LDCN-10-004, 15-011                            15.8-2

COLUMBIA GENERATING STATION                       Amendment 60 FINAL SAFETY ANALYSIS REPORT                      December 2009 Maximum Extended Load Line Limit Analysis (MELLLA)
The ATWS events were analyzed at MELLLA operating conditions to demonstrate protection and mitigation of the consequences of these events. These analyses were performed at 3486 MWt power level. The selection of critical events which were analyzed was guided by References 15.8-8, 15.8-10 and 15.8-11.
It was conservatively assumed that ARI has failed, thus requiring SLC system injection to achieve reactor shutdown. ATWS mitigation is achieved with one or two subsystems of SLC provided the SLC solution is enriched to 44 atom percent Boron-10.
A summary of ATWS results are shown in Table 15.8-3. The analysis results presented in this section are based on a representative reload core at the time of the analysis (Cycle 20)
(Reference 15.8-12). The analysis was dispositioned for GNF2 fuel introduction (reference 15.8-13).
15.8.1       INADVERTENT CONTROL ROD WITHDRAWAL This transient is bounded by assumptions in the GE licensing topical reports and the other transients analyzed in this section.
15.8.2       LOSS OF FEEDWATER 15.8.2.1         Identification of Causes and Frequency Classification 15.8.2.1.1        Identification of Causes Section 15.2.7 provides identification of causes for loss of feedwater event. The loss of feedwater event with failure to scram will initiate an ATWS event.
LDCN-10-004, 15-011                            15.8-2a

COLUMBIA GENERATING STATION                           Amendment 59 FINAL SAFETY ANALYSIS REPORT                          December 2007 15.8.2.1.2      Frequency Classification This event is of extremely low probability and is categorized as a limiting fault.
15.8.2.2       Sequence of Events and System Operation 15.8.2.2.1      Sequence of Events Table 15.8-4 lists the sequence of events for Figure 15.8-1.
15.8.2.2.1.1 Identification of Operator Actions. For the simulation purpose, the following operator actions have been assumed.
: a. Allow automatic operation of the HPCS and reactor core isolation cooling (RCIC),
: b. Begin boron injection at two minutes following ATWS high-pressure trip or at boron injection initiation temperature (BIIT), whichever is later, and
: c. Switch residual heat removal (RHR) to suppression pool cooling mode 11 minutes following initiation of the transient.
The emergency operating procedures provide operator actions for an ATWS event.
15.8.2.2.2      System Operation For the loss of feedwater ATWS event, a complete failure to scram is postulated to occur for all reactor protection system (RPS) scram signals. All other plant control systems maintain normal operation. The relief valves are all assumed to function at the specified setpoints.
Loss of feedwater flow results in a proportional reduction of vessel inventory causing the vessel water level to drop. The first corrective action is the initiation of HPCS and RCIC on Level 2. For this event, a complete failure of ARI is postulated. The operator must manually initiate SLC system to inject boron into the reactor vessel for reactor shutdown.
15.8.2.2.3      The Effect of Single Failure and Operator Errors This ATWS event is based on the assumed complete failure of all control rods to scram. This is a multiple equipment failure. For the conservative assumption of failure of the ARI system, the ATWS event is terminated by boron injection through operator activation of the SLC system. This event is less limiting compared with other ATWS events analyzed at power uprate condition.
LDCN-07-011                                    15.8-3

COLUMBIA GENERATING STATION                            Amendment 61 FINAL SAFETY ANALYSIS REPORT                           December 2011 15.8.2.3       Core and System Performance 15.8.2.3.1      Mathematical Model Reference 15.8-7 describes the generic evaluation methodology for the ATWS event evaluated at uprated power conditions. Additional plant specific analyses were performed for a bounding 10% power uprate using the same methodology.
15.8.2.3.2      Input Parameters and Initial Conditions The initial operating conditions and equipment performance characteristics are given in Tables 15.8-1 and 15.8-2, respectively. MSIV closure occurs on low-low-low water level (L1) but is analyzed based on low-low water level (L2), conservatively overpredicting suppression pool heatup. The HPCS/RCIC flow rates are conservatively high and water level setpoints represent nominal values. The ATWS high pressure setpoint was set at the upper analytical limit. The SRV setpoints were set using a statistical spread of the analytical setpoint limits for the first opening of each value and reset to a statistical spread of the nominal setpoints for all remaining SRV openings during the transient event.
15.8.2.3.3      Results The results of this ATWS event simulation are shown in Figure 15.8-1. Feedwater pump trip is assumed to occur at the onset of the event. Upon the loss of the feedwater flow, reactor pressure, water level, and neutron flux begin to fall. Once reactor water level reaches low-low water level (L2), the protection system trips the recirculation pumps, initiates HPCS and RCIC and signals closure of main steam line isolation valves (MSIVs). Reactor pressure begins to rise due to closure of MSIVs. The relief valves begin to open due to reactor pressure increase.
It is conservatively assumed the operator manually initiates SLC system 2 minutes after the ATWS setpoint has been reached.
15.8.2.3.4      Consideration of Uncertainties Uncertainties in these analyses involve protection system setpoints, system capacities, and system response times. For ATWS transient analyses, best estimated values are used when possible. Examples of conservative bounding values which were used to cover uncertainties are as follows:
: a.      For conservatism, the analysis assumed the highest probable ATWS high-pressure trip setpoint, and
: b.      Boron injection is the later time of BIIT or 2 minutes following ATWS high-pressure trip.
LDCN-09-007                                     15.8-4

COLUMBIA GENERATING STATION                             Amendment 63 FINAL SAFETY ANALYSIS REPORT                            December 2015 15.8.2.4       Barrier Performance The calculated peak vessel bottom head pressure is 1202 psig, which is below the American Society of Mechanical Engineers (ASME) Code Limit of 1375 psig for the RCPB and well below the ASME service level C of 1500 psig. The consequences of this event do not result in any temperature or pressure transient in excess of the criteria for which the fuel, pressure vessel, or containment are designed. Therefore, barrier integrity and function is maintained.
15.8.2.5       Radiological Consequences While this event does not result in fuel failure it does result in the discharge of normal coolant activity to the suppression pool by means of SRV operation. Since this activity is contained in the primary containment, there will be no uncontrolled release to the environment.
15.8.3       LOSS OF ALTERNATE CURRENT POWER This transient is bounded by the other transients analyzed in this section.
15.8.4       LOSS OF ELECTRICAL LOAD This transient is bounded by assumptions in the GE licensing topical reports and the other transients analyzed in this section. (Reference 15.8-11) 15.8.5       LOSS OF CONDENSER VACUUM This transient is bounded by assumptions in the GE licensing topical reports and the other transients analyzed in this section.
15.8.6       TURBINE TRIP This event was analyzed at pre-power uprate condition for low power and full power (corresponding to 3323 MWt) operation. At uprated conditions, the event is bounded by the other transients analyzed in this section. The selection of critical events were guided by Reference 15.8-3.
LDCN-10-004                                    15.8-5

COLUMBIA GENERATING STATION                        Amendment 63 FINAL SAFETY ANALYSIS REPORT                       December 2015 15.8.7       CLOSURE OF MAIN STEAM LINE ISOLATION VALVES 15.8.7.1        Identification of Causes and Frequency Classification 15.8.7.1.1       Identification of Causes Various steam line and nuclear system malfunctions, or operator actions, can initiate MSIV closure. These are detailed in Section 15.2.4. The MSIV closure event with failure to scram will initiate an ATWS event.
15.8.7.1.2       Frequency Classification This event is of extremely low probability and is categorized as a limiting fault.
15.8.7.2        Sequence of Events and System Operation 15.8.7.2.1       Sequence of Events Table 15.8-5 lists the sequence of events for Figure 15.8-2.
15.8.7.2.1.1 Identification of Operator Actions. For the simulation purpose, the following operator actions have been assumed:
: a.       Allow automatic operation of RCIC, inhibit HPCS consistent with Emergency Operating Procedures,
: b.       Begin boron injection at 2 minutes following ATWS high-pressure trip or at BIIT, whichever is later, and
: c.       Switch RHR to suppression pool cooling mode 11 minutes following initiation of the transient.
Emergency Operating Procedures provide operator actions for an ATWS event.
15.8.7.2.2       System Operation For the MSIV closure ATWS event, a complete failure to scram is postulated to occur for all RPS scram signals. All other plant control systems maintain normal operation. The relief valves are all assumed to function at the specified setpoints. The RPT occurs at the ATWS high pressure trip setpoint. For this event, a complete failure of ARI is postulated. The operator must manually initiate SLC system to inject boron into the reactor vessel for reactor shutdown.
LDCN-10-004                                    15.8-6

COLUMBIA GENERATING STATION                            Amendment 63 FINAL SAFETY ANALYSIS REPORT                           December 2015 15.8.7.2.3      The Effect of Single Failures and Operator Errors For the conservative assumption of failure of ARI system, the ATWS event is terminated by boron injection through operator activation of the SLC system. Relief valves operate to limit system pressure. All of these aspects are designed to single failure criterion. Analyses have been performed for dual and single SLC pump operation with natural of 44 atom percent Boron-10 enrichment, respectively. The single pump SLC transport time delay accounts for the reduced flow rate in the system.
15.8.7.3       Core and System Performance 15.8.7.3.1      Mathematical Model References 15.8-8, 15.8-11 and 15.8-12 describes the generic evaluation methodology for the ATWS event under MELLLA conditions.
15.8.7.3.2      Input Parameters and Initial Conditions The initial operating conditions and equipment performance characteristics are given in Table 15.8-1A. The ATWS high pressure setpoint was set at the upper analytical limit. The SRV setpoints were set using a statistical spread of the analytical setpoint limits for the first opening of each value and reset to a statistical spread of the nominal setpoints for all remaining SRV openings during the transient event.
15.8.7.3.3      Results The results of this ATWS event simulation are shown in Table 15.8-3 and Figure 15.8-2. The MSIVs close within a nominal 4 sec stroke time. Once the MSIVs reach the 85% open position, a reactor scram is initiated. The scram was assumed to fail to insert any control rods.
The rapid increase in reactor pressure generates rapid increase in reactor core power due to collapsing core voids. The relief valves begin to open responding to reactor pressure rise.
Upon reaching the ATWS high-pressure setpoint, the RPT occurs and reduces core power. It is conservatively assumed the operator manually initiates SLC system 2 minutes after the ATWS setpoint has been reached.
The peak calculated vessel bottom head pressure is below the ASME Service Level C limit of 1500 psig.
LDCN-10-004                                   15.8-7

COLUMBIA GENERATING STATION                             Amendment 63 FINAL SAFETY ANALYSIS REPORT                            December 2015 The calculated peak suppression pool temperature of the event is below the containment design limit. The calculated peak containment pressure is also below the containment design limit.
15.8.7.3.4      Consideration of Uncertainties Uncertainties in these analyses involve protection system setpoints, system capacities, and system response times. For ATWS transient analyses, best estimated values are used when possible. Examples of conservative bounding values which were used to cover uncertainties are as follows:
: a.      For conservatism, the analyses assumed the highest probable ATWS high-pressure trip setpoint, and
: b.      Boron injection is the later time of BIIT or 2 minutes following ATWS high-pressure trip.
: c.      A 35 sec opening time for the suction values upstream to the SLCS pumps was modeled increasing the SLCS initiation time.
15.8.7.4       Barrier Performance The calculated peak vessel bottom head pressure is below the ASME Service Level C limit of 1500 psig. The consequences of this event do not result in any temperature or pressure transient in excess of the criteria for which the fuel, pressure vessel, or containments are designed. Therefore, these barrier integrity and function is maintained.
15.8.7.5       Radiological Consequences While this event does not result in fuel failure it does result in the discharge of normal coolant activity to the suppression pool by means of SRV operation. Since this activity is contained in the primary containment, there will be no uncontrolled release to the environment.
LDCN-10-004                                     15.8-8

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.8.8      INADVERTENT OPENING OF RELIEF VALVE 15.8.8.1      Identification of Causes and Frequency Classification 15.8.8.1.1     Identification of Causes This event assumes that a SRV may open and stick in the open position. These events are detailed in Section 15.1.4. The inadvertent opening of relief valve (IORV) event with failure to scram will initiate an ATWS event.
15.8.8.1.2     Frequency Classification This event is of extremely low probability and is categorized as a limiting fault.
15.8.8.2      Sequence of Events and System Operation 15.8.8.2.1     Sequence of Events The analysis has not been updated for the change in MSIV isolation setpoint from Level 2 to Level 1 because the analysis is bounding and conclusions of the analysis are not affected (Reference 15.8-9).
Table 15.8-7 lists the sequence of events for Figure 15.8-4.
15.8.8.2.1.1 Identification of Operator Actions. For the simulation purpose, the following operator actions have been assumed:
: a. Initiate boron injection 2 minutes after BIIT,
: b. Disable HPCS, RCIC, and low level MSIV closure,
: c. Use feedwater to manually control the water level at the top of active fuel, and
: d. Manually trip the recirculation pumps.
15.8.8.2.1.2 System Operation. For the IORV ATWS event, a complete failure to scram is postulated to occur for all RPS scram signals. All other plant control systems maintain normal operation. For this event, a complete failure of ARI is also postulated. The operator must manually initiate SLC system to inject boron into the reactor vessel for reactor shutdown.
15.8.8.2.2     The Effect of Single Failures and Operator Errors For the conservative assumption of failure of ARI system, the ATWS event is terminated by boron injection through operator activation of the SLC system. This is a multiple equipment failure event. All of these aspects are designed to single failure criterion.
LDCN-09-007                                   15.8-9

COLUMBIA GENERATING STATION                            Amendment 61 FINAL SAFETY ANALYSIS REPORT                           December 2011 The instrumentation, which detects and audibly alarms the resulting suppression pool temperature rise, and the RHR containment heat removal system are designed to meet the single failure criteria. The operator must, however, manually initiate suppression pool cooling.
15.8.8.3       Core and System Performance 15.8.8.3.1      Mathematical Model Reference 15.8-7 describes the generic evaluation methodology for the ATWS event evaluated at uprated power conditions. Additional plant specific analyses were performed for a bounding 10% power uprate using the same methodology.
15.8.8.3.2      Input Parameters and Initial Conditions The initial operating conditions and equipment performance characteristics are given in Tables 15.8-1 and 15.8-2, respectively. The HPCS/RCIC flow rates are conservatively high and water level setpoints represent nominal values. The ATWS high pressure setpoint was set at the upper analytical limit. The SRV setpoints were set using a statistical spread of the analytical setpoint limits for the first opening of each value and reset to a statistical spread of the nominal setpoints for all remaining SRV openings during the transient event.
15.8.8.3.3      Results The results of this ATWS event simulation are shown in Figure 15.8-4. The opening of a SRV allow steam to be discharged into the suppression pool. The sudden increase in the rate of steam flow leaving the reactor vessel causes a mild depressurization transient.
Discharge of steam into the suppression pool increases the suppression pool temperature. The operator initiates SLC system 2 minutes after the suppression pool temperature reaches 110F, trips the recirculation pumps, and initiates feedwater runback to lower the reactor water level to top of active fuel (TAF). Suppression pool cooling begins 11 minutes after the initiation of the event. The operator disables HPCS and RCIC level 2 initiation. The MSIV Level 2 closure is also disabled. Turbine steam flow is terminated upon closure of the MSIVs due to low steam line pressure.
15.8-10

COLUMBIA GENERATING STATION                            Amendment 61 FINAL SAFETY ANALYSIS REPORT                           December 2011 15.8.8.3.4      Consideration of Uncertainties Uncertainties in these analyses involve protection system setpoints, system capacities, and system response times. For ATWS transient analyses, best estimated values are used when possible. Examples of conservative bounding values which were used to cover uncertainties are as follows:
: a.      For conservatism, the analysis assumed the highest probable ATWS high-pressure trip setpoint, and
: b.      Boron injection is the later time of BIIT or 2 minutes following ATWS high-pressure trip.
15.8.8.4       Barrier Performance The IORV ATWS event is a mild depressurization which has no significant effect on RCPB.
During the event, the suppression pool is continually heated due to SRV discharge. The peak suppression pool temperature and pressure are within the design criteria of the containment.
15.8.8.5       Radiological Consequences While this event does not result in fuel failure, it does result in the discharge of normal coolant activity to the suppression pool by means of SRV operation. Since this activity is contained in the primary containment, there will be no uncontrolled release to the environment.
15.8.9       PRESSURE REGULATOR FAILURE - OPEN (PREGO) 15.8.9.1       Identification of Causes and Frequency Classification 15.8.9.1.1      Identification of Causes The causes for this event is detailed in Section 15.1.3. The PREGO event with failure to scram will initiate an ATWS event.
15.8.9.1.2      Frequency Classification This event is of extremely low probability and is categorized as a limiting fault.
15.8.9.2       Sequence of Events and System Operation 15.8.9.2.1      Sequence of Events Table 15.8-8 lists the sequence of events for Figure 15.8-5.
15.8-11

COLUMBIA GENERATING STATION                             Amendment 63 FINAL SAFETY ANALYSIS REPORT                            December 2015 15.8.9.2.1.1 Identification of Operator Actions. For the simulation purpose, the following operator actions have been assumed.
: a.      Allow automatic operation of RCIC, inhibit HPCs consistent with Emergency Operating Procedures,
: b.      Begin boron injection at 2 minutes following ATWS high-pressure trip or at BIIT, whichever is later, and
: c.      Switch RHR to suppression pool cooling mode 11 minutes following initiation of the transient.
The emergency operating procedures provide operator actions for an ATWS event.
15.8.9.2.1.2 System Operation. For the PREGO ATWS event, a complete failure to scram is postulated to occur for all RPS scram signals. All other plant control systems maintain normal operation. For this event, a complete failure of ARI is also postulated. The operator must manually initiate SLC system to inject boron into the reactor vessel for reactor shutdown.
15.8.9.2.3      The Effect of Single Failures and Operator Errors For the conservative assumption of failure of ARI system, the ATWS event is terminated by boron injection through operator activation of the SLC system. This is a multiple equipment failure event. All of these aspects are designed to single failure criterion.
The instrumentation, which detects and audibly alarms the resulting suppression pool temperature rise, and the RHR containment heat removal system are designed to meet the single failure criteria.
15.8.9.3       Core and System Performance 15.8.9.3.1      Mathematical Model References 15.8-8, 15.8-11 and 15.8-12 describe the generic evaluation methodology for the ATWS event under MELLLA conditions.
15.8.9.3.2      Input Parameters and Initial Conditions The initial operating conditions an equipment performance characteristics are given in Table 15.8-1A. The ATWS high pressure setpoint was set at the upper analytical limit. The SRV setpoints were set using a statistical spread of the analytical setpoint limits for the first opening of each value and reset to a statistical spread of the nominal setpoints for all remaining SRV openings during the transient event.
LDCN-10-004                                    15.8-12

COLUMBIA GENERATING STATION                             Amendment 63 FINAL SAFETY ANALYSIS REPORT                            December 2015 15.8.9.3.3      Results The results of this ATWS event simulation are shown in Table 15.8-3 and Figure 15.8-5. The DEH control system failure with 130% steam flow demand signal is assumed to occur.
Ensuing reactor depressurization results in formation of voids in the reactor coolant and causes a decrease in reactor power almost immediately. The MSIV closure occurs due to trip signal from low steam line pressure. Reactor pressure rises to the relief setpoints and the recirculation pumps trip on the high pressure ATWS setpoint.
Discharge of steam into the suppression pool increases the suppression pool temperature. The operator initiates feedwater runback to lower the reactor water level to TAF after the suppression pool temperature reaches 110F. The HPCS and RCIC systems are initiated at low reactor water level. The SLC system is manually initiated 2 minutes after the ATWS high pressure setpoint was reached.
15.8.9.3.4      Consideration of Uncertainties Uncertainties in these analyses involve protection system setpoints, system capacities, and system response times. For ATWS transient analyses, best estimated values are used when possible. Examples of conservative bounding values which were used to cover uncertainties are as follows:
: a.      For conservatism, the analysis assumed the highest probable ATWS high-pressure trip setpoint, and
: b.      Boron injection is the later time of BIIT or 2 minutes following ATWS high-pressure trip.
15.8.9.4       Barrier Performance The calculated peak vessel bottom head pressure is below the ASME Service Level C limit of 1500 psig. The consequences of this event do not result in any temperature or pressure transient in excess of the criteria for which the fuel pressure vessel or containment are designed. Therefore, barrier integrity and function is maintained.
15.8.9.5       Radiological Consequences While this event does not result in fuel failure, it does result in the discharge of normal coolant activity to the suppression pool by means of SRV operation. Since this activity is contained in the primary containment, there will be no uncontrolled release to the environment.
LDCN-10-004                                    15.8-13

COLUMBIA GENERATING STATION                            Amendment 63 FINAL SAFETY ANALYSIS REPORT                           December 2015 15.8.10     SINGLE REACTOR RECIRCULATION SYSTEM PUMP OPERATION The following discussion is based on pre-uprate power level of 3323 MWt. Thus, the 100%
rod line corresponds to 3323 MWt power at rated core flow.
For pre-uprate condition, it was shown that operation of the plant with only a single RRC pump and the resulting transient conditions which could occur while in this mode are bounded by the other transients analyzed in this section, and the parametric studies performed in Reference 15.8-4. This conclusion was based on evaluating the effects of power, void reactivity worth and doppler worth at both 100% conditions, and at conditions present under single RRC pump operation.
Sensitivity studies presented in Reference 15.8-4 compare the turbine trip at 100% power condition with the turbine trip at lower power conditions, such as one would have under single RRC pump.
The rod line for single RRC pump operation for pre-uprate condition was normally maintained between 100% and 104.25% power level. At less than 100% power the average void in the core was slightly higher for operation on the 104.25% rod line than for operation on the 100%
rod line. In addition, the doppler worth at lower power conditions is higher than at 100%
power. The presence of higher voids and the increased doppler worth when operating at the 104.15% rod line is bounded by the parametric analyses in Reference 15.8-4. These parametric analyses determined the sensitivity of plant response between the MSIV closure at 100% power and the MSIV closure with higher reactivity coefficients at 100% power. The void worth assumed in the higher reactivity coefficient case gives a much higher effect than the increased average void present in the single RRC pump operation mode at the 104.25% rod line, which bounds this case. The doppler reactivity worth used in the MSIV closure with higher reactivity coefficients is representative of the doppler reactivity worth found at lower power conditions such as those present in the single RRC pump operation mode.
LDCN-10-004                                    15.8-14

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                       December 2015 15.8.11     REFERENCES 15.8-1        Hatch Unit 1 FSAR. Amendment 10, Appendix L, Failure-to-Scram Analysis, October 27, 1971.
15.8-2        Michelotti, L. A., Analysis of Anticipated Transients Without Scram, NEDO-10349.
15.8-3        NEDE-24222, Assessment of BWR Mitigation of ATWS, Volume II (NUREG-0460 Alternate No. 3).
15.8-4        EI International, Inc., Final Report, Anticipated Transients Without Scram Analysis for the WNP-2 Nuclear Power Plant, SA-JAD-087-90, December 1989.
15.8-5        Supply System Letter G02-90-116, G. C. Sorensen (Supply System) to NRC, Nuclear Plant No. 2. Operating License (NPF-21 Resolution of Anticipated Transient Without Scram (ATWS) for WNP- 2, dated June 29, 1990.
15.8-6        GE Nuclear Energy, WNP-2 Power Uprate Project NSSS Engineering Report, GE-NE-208-17-0993, Revision 1, December 1994.
15.8-7        GE Nuclear Energy, Generic Evaluations of General Electric Boiling Water Reactor Power Uprate, Licensing Topical Report NEDC-31984P, July 1991 and Supplements 1 & 2.
15.8-8        Generic Guidelines for General Electric Boiling Water Reactor Extended Power Uprate, NEDC-32424P-A, February 1999 (ELTR-1).
15.8-9        GE Hitachi Nuclear Energy, License Amendment Request for Proposed Changes to Columbia Technical Specifications: Changing Group 1 Isolation Valves Low Reactor Water Level Isolation Signal from the Current Level 2 to Level 1, 0000-0081-6730-R1, July 2008.
15.8-10       Generic Evaluations of General Electric Boiling Water Reactor Extended Power Uprate, NEDC-32523P-A, February 2000 (ELTR-2) and Supplement 1, Volume 1, February 1999 and Volume II, April 1999.
15.8-11       Constant Pressure Power Uprate, NEDC-33004P-A, Revision 4, July 2003.15.8-12Project Task Report ENERGY NORTHWEST Columbia Generating Station ARTS/MELLLA Task T0902: Anticipated Transients Without Scram, 0000-0101-1095-R2, May 2010.
LDCN-15-011                                 15.8-15

COLUMBIA GENERATING STATION                        Amendment 63 FINAL SAFETY ANALYSIS REPORT                       December 2015 15.8-13     002N3439, GNF2 Fuel Design Cycle-Independent Analyses for Energy Northwest Columbia Generating Station, (most recent version referenced in the COLR).
LDCN-15-011                           15.8-16

COLUMBIA GENERATING STATION               Amendment 59 FINAL SAFETY ANALYSIS REPORT             December 2007 Table 15.8-1 Anticipated Transients Without Scram Analysis Initial Conditions Parameters                            Value Reactor dome pressure (psig)                                       1020 Vessel core flow (Mlb/hr)                                          108.5 Vessel steam flow (Mlb/hr)                                         15.728 Reactor thermal power (MWt)                                        3629 Initial vessel and recirculation piping inventory (lbm)            609,600 Narrow range sensed initial water level (ft above separator skirt) 4.13 Initial core average void fraction (%)                             41.8 Void reactivity coefficient (&#xa2;/%)                                  -12.937 Doppler coefficient (%/F)                                          -0.31087 Feedwater enthalpy (Btu/lb)                                        403.1 Sodium penetaborate solution concentration (% by weight)           13.6 Suppression pool liquid volume (ft3)                               112,197 Suppression pool temperature (F)                                  90 Service water temperature (F)                                     90 LDCN-07-011                                    15.8-17

COLUMBIA GENERATING STATION                      Amendment 63 FINAL SAFETY ANALYSIS REPORT                    December 2015 Table 15.8-1A Anticipated Transients Without Scram Analysis for MELLLA Initial Conditions and Equipment Performance Characteristics Parameter                                      Value Dome Pressure (psia)                                                      1035 MELLLA Core Flow (Mlbm/br / % rated)                                      87.6 / 80.7 Core Thermal Power (MWt / %CLTP)                                          3486 / 100.0 Steam / Feed Flow (Mlbm/hr / %NBR)                                        15.013 / 100 Sodium Pentaborate Solution Concentration in the SLCS Storage             13.6 Tank (% by weight)
Boron 10 Enrichment (atom %)                                              19.8*
SLCS Injection Location                                                   HPCS Number of SLCS Pumps Operating                                            2 SLCS Injection Rate (gpm)                                                 82.4*
SLCS Liquid Transport Time (sec)                                          321 Initial Suppression Pool Liquid Volume (ft3)                              112197 Initial Suppression Pool Temperature (&deg;F)                                 90 RHR Heat Exchanger Design Effectiveness per Loop (BTU/sec&deg;F)              289 Number of RHR Heat Exchanger Loops                                        2 RHR Heat Exchanger Design Effectiveness during LOOP                       289 (BTU/sec&deg;F)
Number of RHR Heat Exchanger Loops Available for LOOP Event               2 RHR Service Water Temperature (&deg;F)                                        90 Transient time at which the RHR suppression pool cooling is               660 established (seconds)
High Dome Pressure ATWS-RPT Setpoint (psig)                               1170 SRV Capacity  per valve (lbm/hr) / Reference Pressure (psig) /           876500/ 1165 / 3 Accumulation (%)
SRV Configuration                                                         18 SRV (4 OOS)
* Values for two SLC pumps injection. For single pump injection, flow rate is 41.2 gpm and Boron-10 enrichment is 44 atom %.
LDCN-10-004                                 15.8-17a

COLUMBIA GENERATING STATION                     Amendment 59 FINAL SAFETY ANALYSIS REPORT                    December 2007 Table 15.8-2 Anticipated Transients Without Scram Analysis Equipment Performance Characteristics Parameter                                    Value Main steam line isolation valve nominal closure time (sec)                  4 Relief valve system capacity (% of current NBR steam flow at 1144 psia)     100.18 Number of SRVs                                                              18 Relief valve and sensor time delay (sec)                                    0.4 Relief valve opening time (sec)                                             0.15 Relief valve closure time delay (sec)                                       0.3 Standby liquid control system injection rate (gpm)                          86.0 High-pressure core spray/RCIC low water level initiation nominal setpoint   -3.04 (L2)
(ft above separator skirt)
High-pressure core spray/RCIC high water level shutoff setpoint (ft above   5.667 (L8) separator skirt)
High-pressure core spray flow rate (gpm at 1035 psia)                       3875 Reactor core isolation cooling flow rate (gpm)                              600 Anticipated transients without scram high pressure UAL setpoint (psia)      1186 Anticipated transients without scram dome pressure sensor and logic time    0.53 delay (sec)
Total bypass capacity (Mlb/hr)                                              35.5 Total bypass capacity (% of uprate steam flow)                              22.7 Pump inertia constant (sec)                                                 5.4729 Residual heat removal pool cooling capacity (Btu/sec-F)                    578 15.8-18

COLUMBIA GENERATING STATION                     Amendment 63 FINAL SAFETY ANALYSIS REPORT                   December 2015 Table 15.8-3 Summary of Anticipated Transients Without Scram Results ATWS Event Parameter                        PREGOd   MSIVCd   LOFW         IORV Maximum neutron flux (%)                         297d     265      282.07      116.6 Time (sec)                                       19.2     4.1      22.36       7.96 Maximum average fuel heat flux (%)               153      138      102.9       103.14 Time (sec)                                       22.6     5        0.49        0.69 Maximum bottom pressure (psig)                   1364d    1349     1202.2      1061.4 Time (sec)                                       28.7     9.9      23.62       0.19 Peak suppression pool temperature (F)           178.9    179.6c   161.06      165.29 Peak containment pressure (psig)                 9.6      9.8c     5.97        6.87 Time (sec)                                       3146     3056     8400        6600 Peak cladding temperature (F)                   1572     N/A      N/A         N/A Time (sec)b Min. water level (ft above sep. skirt)b                            -11.24      -10.66 Time (sec)b                                                         91.38      975.4 Time of hot shutdowna (sec)                      895      898      977         1524.6 Time of reaching ATWS setpoint (sec)             22.1     4.4      17.5        N/A Time of BIIT (sec)                               64       47       170         554 a
Hot shutdown is defined as generated power remaining below 1% NBR. For MELLLA, hot shutdown is defined as Neutron Flux remains < 0.1%.
b Values not reported for MELLLA.
c Results for two SLC pump operation. For single pump operation, suppression pool temperature is 187&deg;F and containment pressure is 12 psig.
d Noted parameters for PREGO are beginning of Cycle 20 under MELLLA conditions. All other PREGO and MSIVC results are end of Cycle 20.
LDCN-10-004                                   15.8-19

COLUMBIA GENERATING STATION                         Amendment 61 FINAL SAFETY ANALYSIS REPORT                        December 2011 Table 15.8-4 Sequence of Events for Loss of Feedwater Time                                      Event 0 sec            Feedwater pump trip.
17.5 sec         High-pressure core spray and RCIC initiated on Level 2.
17.5 sec         Main steam line isolation valve closure on Level 2 (see Section 15.8.2.3.2) - scram fails.
17.5 sec         Recirculation pump tripped on Level 2 (ATWS setpoint reached, ARI fails).
22.9 sec         Relief valves lift.
23.6 sec         Vessel pressure peaks.
2 minutes 18 sec Operator initiates SLCS (2 minutes after ATWS setpoint reached).
3 minutes 3 sec  Liquid control flow enters the core.
16 minutes       Hot shutdown achieved.
140 minutes      Suppression pool temperature and containment pressure peak.
LDCN-09-007                             15.8-20

COLUMBIA GENERATING STATION               Amendment 63 FINAL SAFETY ANALYSIS REPORT              December 2015 Table 15.8-5 Sequence of Events for Main Steam Line Isolation Valve Closure (Long Term Transient)
Event                         EOC MELLLA (sec)
MSIV Isolation Initiated                                        0.0 MSIVs Fully Closed                                              4.0 High Pressure ATWS Setpoint                                     4.4 Peak Neutron Flux                                               4.1 Opening of the First Relief Valve                               4.6 Recirculation Pumps Trip                                        4.9 Peak Heat Flux                                                  5.0 Peak Vessel Pressure                                            9.9 Feedwater Reduction Initiated                                  30.0 BIIT Reached                                                   47.0 SLCS Pumps Start                                              124 Hot Shutdown Achieved (Neutron Flux Remains <0.1%)            898 RHR Cooling established                                       660 Peak Suppression Pool Temperature                            3056 LDCN-10-004                                  15.8-21

COLUMBIA GENERATING STATION  Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 15.8-6 DELETED LDCN-10-004                15.8-22

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 Table 15.8-7 Sequence of Events for Inadvertent Open Relief Valve Time                                            Event 0 sec                 Relief valve with the lowest opening setpoint opens.
9 minutes 14 sec      Operator initiates SLCS 2 minutes after suppression pool temperature = 110F (scram and ARI fail).
9 minutes 14 sec      Operator trips recirculation pumps.
9 minutes 14 sec      Operator initiates feedwater runback to bring level to TAF.
11 minutes            Suppression pool cooling begins.
13 minutes            Operator disables HPCS, RCIC Level 2 initiation and MSIV Level 2 closurea.
14 minutes            Liquid control flow enters the core.
25 minutes            Hot shutdown achieved.
29 minutes            Main steam line isolation valve closure on low pressure.
110 minutes           Suppression pool temperature and containment pressure peak.
a The analysis has not been updated for the change in MSIV isolation setpoint from Level 2 to Level 1 because the analysis is bounding and conclusions of the analysis are not affected (Reference 15.8-9).
LDCN-09-007                                   15.8-23

COLUMBIA GENERATING STATION                Amendment 63 FINAL SAFETY ANALYSIS REPORT               December 2015 Table 15.8-8 Sequence of Events for Pressure Regulator Failure Open (Long Term Transient)
Event                      BOC MELLLA (sec)   EOC MELLLA (sec)
TCV and Bypass Valves Start Open                   0.1              0.1 MSIV Closure Initiated by Low                     15.0             14.2 Steamline Pressure MSIVs Fully Closed                                19.0             18.2 Peak Neutron Flux                                 19.2             18.4 High Pressure ATWS Setpoint                       22.6             22.1 Opening of the First Relief Valve                 22.8             22.2 Recirculation Pumps Trip                          23.2             22.6 Peak Heat Flux                                    23.2             22.6 Peak Vessel Pressure                              28.7             27.9 Feedwater Reduction Initiated                     45.8             45.8 BIIT Reached                                      64.0             64.0 LDCN-10-004                               15.8-24

Amendment 53 November 1998 Loss of Feedwater Event Columbia Generating Station Final Safety Analysis Report Draw. No. 020002.29      Rev.      Figure 15.8-1.1

Amendment 53 November 1998 Loss of Feedwater Event Columbia Generating Station Final Safety Analysis Report Draw. No. 020002.30       Rev. Figure 15.8-1.2

Amendment 53 November 1998 Loss of Feedwater Event Columbia Generating Station Final Safety Analysis Report Draw. No. 020002.31       Rev. Figure 15.8-1.3

Amendment 53 November 1998 Loss of Feedwater Event Columbia Generating Station Final Safety Analysis Report Draw. No. 020002.32      Rev.      Figure 15.8-1.4

Amendment 53 November 1998 Loss of Feedwater Event Columbia Generating Station Final Safety Analysis Report Draw. No. 020002.33       Rev. Figure 15.8-1.5

Amendment 63 December 2015 Main Steam Isolation Valve Closure Event Columbia Generating Station Final Safety Analysis Report Draw. No. 020002.34    Rev.1     Figure 15.8-2.1 Form No. 960690 LDCN-10-004

Amendment 63 December 2015 Main Steam Isolation Valve Closure Event Columbia Generating Station Final Safety Analysis Report Draw. No. 020002.35    Rev. 1    Figure 15.8-2.2 Form No. 960690 LDCN-10-004

Amendment 63 December 2015 Main Steam Isolation Valve Closure Event Columbia Generating Station Final Safety Analysis Report Draw. No. 020002.36     Rev. 1    Figure 15.8-2.3 Form No. 960690 LDCN-10-004

Amendment 63 December 2015 DELETED Main Steam Isolation Valve Closure Event Columbia Generating Station Final Safety Analysis Report Draw. No. 020002.37    Rev.      Figure 15.8-2.4 Form No. 960690 LDCN-10-004

Amendment 63 December 2015 DELETED Main Steam Isolation Valve Closure Event Columbia Generating Station Final Safety Analysis Report Draw. No. 020002.38    Rev.      Figure 15.8-2.5 Form No. 960690 LDCN-10-004

Amendment 63 December 2015 DELETED Main Steam Isolation Valve Closure Event with Columbia Generating Station                       4 SRVs Out-of-Service Final Safety Analysis Report Draw. No. 960222.40      Rev.      Figure 15.8-3.1 Form No. 960690 LDCN-10-004

Amendment 63 December 2015 DELETED Main Steam Isolation Valve Closure Event with Columbia Generating Station                         4 SRVs Out-of-Service Final Safety Analysis Report Draw. No. 960222.41      Rev.      Figure 15.8-3.2 Form No. 960690 LDCC-10-004

Amendment 63 December 2015 DELETED Main Steam Isolation Valve Closure Event with 4 Columbia Generating Station                       SRVs Out-of-Service Final Safety Analysis Report Draw. No. 960222.42     Rev.      Figure 15.8-3.3 Form No. 960690 LDCN-10-004

Amendment 63 December 2015 DELETED Main Steam Isolation Valve Closure Event with Columbia Generating Station 4 SRVs Out-of-Service Final Safety Analysis Report Draw. No. 960222.43      Rev. Figure 15.8-3.4 Form No. 960690 LDCN-10-004

Amendment 63 December 2015 DELETED Main Steam Isolation Valve Closure Event with 4 Columbia Generating Station                       SRVs Out-of-Service Final Safety Analysis Report Draw. No. 960222.44     Rev.      Figure 15.8-3.5 Form No. 960690 LDCN-10-004

Amendment 53 November 1998 REDYV 20 Actual Level in Feet WR Sensed Level in Feet 10 Level (Above Sep Skirt) 0
                              -10
                              -20 0              1               2                      3                  4x103                       5 Time, (Seconds)
Inadvertent Opening of Relief Valve Event Columbia Generating Station Final Safety Analysis Report Draw. No. 960222.45      Rev.           Figure   15.8-4.1 Form No. 960690

Amendment 53 November 1998 REDYV 5
Void in $
Doppler in $
4                                                                   Net Reactivity in $
3 2
Reactivity ($)
1 0
                      -1
                      -2
                      -3 0               1              2                      3                4x103                       5 Time, (Seconds)
Inadvertent Opening of Relief Valve Event Columbia Generating Station Final Safety Analysis Report Draw. No. 960222.48    Rev.           Figure   15.8-4.2 Form No. 960690

Amendment 53 November 1998 REDYV 200 150 Reactor Vessel Flow (% Rated) 100 50 0
0               1              2                      3               4x103                       5 Time, (Seconds)
Inadvertent Opening of Relief Valve Event Columbia Generating Station Final Safety Analysis Report Draw. No. 960222.46   Rev.           Figure   15.8-4.3 Form No. 960690

Amendment 53 November 1998 REDYV 1.6x103 Dome Pressure in psia 1.4 Dome Pressure (psia) 1.2 1.0 0.8 0                1                  2                      3              4x103                       5 Time, (Seconds)
Inadvertent Opening of Relief Valve Event Columbia Generating Station Final Safety Analysis Report Draw. No. 960222.47   Rev.           Figure   15.8-4.4 Form No. 960690

Amendment 53 November 1998 REDYV 160 Neutron Flux in %
Avg. Surf Heat Flux in %
120 Flux (% Rated) 80 40 0
0              1                     2                      3               4x103                       5 Time, (Seconds)
Inadvertent Opening of Relief Valve Event Columbia Generating Station Final Safety Analysis Report Draw. No. 960222.49   Rev.           Figure   15.8-4.5 Form No. 960690

Amendment 63 December 2015 Pressure Regulator Failure - Open Event Columbia Generating Station Final Safety Analysis Report Draw. No. 020002.39    Rev. 1     Figure 15.8-5.1 Form No. 960690 LDCN-10-004

Amendment 63 December 2015 Pressure Regulator Failure - Open Event Columbia Generating Station Final Safety Analysis Report Draw. No. 020002.40    Rev.       Figure 15.8-5.2 Form No. 960690 LDCN-10-004

Amendment 53 December 2015 Pressure Regulator Failure - Open Event Columbia Generating Station Final Safety Analysis Report Draw. No. 020002.41    Rev. 1     Figure 15.8-5.3 Form No. 960690 LDCN-10-004

Amendment 63 December 2015 DELETED Pressure Regulator Failure - Open Event Columbia Generating Station Final Safety Analysis Report Draw. No. 020002.42    Rev.       Figure 15.8-5.4 Form No. 960690 LDCN-10-004

Amendment 63 December 2015 DELETED Pressure Regulator Failure - Open Event Columbia Generating Station Final Safety Analysis Report Draw. No. 020002.43    Rev.       Figure 15.8-5.5 Form No. 960690 LDCN-10-004

COLUMBIA GENERATING STATION          Amendment 62 FINAL SAFETY ANALYSIS REPORT         December 2013 Chapter 16 TECHNICAL SPECIFICATIONS (See Operating License Appendix A)
TECHNICAL SPECIFICATION BASES (Separate Volume)
LICENSEE CONTROLLED SPECIFICATIONS (Separate Volume)
LDCN-12-020                     16-1

COLUMBIA GENERATING STATION                                      Amendment 54 FINAL SAFETY ANALYSIS REPORT                                     April 2000 Chapter 17 QUALITY ASSURANCE TABLE OF CONTENTS Section                                                                                             Page 17.1 QUALITY ASSURANCE DURING DESIGN AND CONSTRUCTION..... 17.1-1 17.1.1 ENERGY NORTHWEST QUALITY ASSURANCE PROGRAM ................ 17.1-1 17.1.1.1 Organization ......................................................................... 17.1-2 17.1.1.2 Quality Assurance Program....................................................... 17.1-10 17.1.1.3 Design Control ...................................................................... 17.1-15 17.1.1.4 Procurement Document Control.................................................. 17.1-15 17.1.1.5 Instructions, Procedures, and Drawings........................................ 17.1-16 17.1.1.6 Document Control .................................................................. 17.1-16 17.1.1.7 Control of Purchased Material, Equipment, and Services ................... 17.1-17 17.1.1.8 Identification and Control of Materials, Parts, and Components .......... 17.1-18 17.1.1.9 Control of Special Processes...................................................... 17.1-19 17.1.1.10 Inspection ............................................................................ 17.1-19 17.1.1.11 Test Control ......................................................................... 17.1-20 17.1.1.12 Control of Measuring and Test Equipment..................................... 17.1-21 17.1.1.13 Handling, Storage, and Shipping................................................ 17.1-21 17.1.1.14 Inspection, Test, and Operating Status ......................................... 17.1-22 17.1.1.15 Nonconforming Materials, Parts, or Components ............................ 17.1-22 17.1.1.16 Corrective Action................................................................... 17.1-23 17.1.1.17 Quality Assurance Records ....................................................... 17.1-24 17.1.1.18 Audits................................................................................. 17.1-25 17.1.2 THE BURNS AND ROE, INC. QUALITY ASSURANCE PROGRAM ........ 17.1-26 17.1.2.1 Introduction .......................................................................... 17.1-26 17.1.2.2 The Burns & Roe, Inc. Quality Assurance Topical Report .................. 17.1-26 17.1.2.3 Exceptions to the Burns & Roe, Inc. Quality Assurance Topical Report................................................................................. 17.1-26 17.1.2.3.1 Chapter I - Organization ........................................................ 17.1-26 17.1.2.3.2 Chapter II - Quality Assurance Program..................................... 17.1-27 17.1.2.3.3 Chapter III - Design Control ................................................... 17.1-27 17.1.2.3.4 Chapter IV - Procurement Document Control............................... 17.1-28 17.1.2.3.5 Chapter V - Instructions, Procedures, and Drawings...................... 17.1-29 17.1.2.3.6 Chapter VI - Document Control ............................................... 17.1-29 17.1.2.3.7 Chapter VII - Control of Purchased Material, Equipment, and Services ....................................................................... 17.1-30 17.1.2.3.8 Chapter VIII - Identification and Control of Material Parts and Components .................................................................. 17.1-31 LDCN-99-000                                          17-i

COLUMBIA GENERATING STATION                                     Amendment 54 FINAL SAFETY ANALYSIS REPORT                                    April 2000 Chapter 17 QUALITY ASSURANCE TABLE OF CONTENTS (Continued)
Section                                                                                        Page 17.1.2.3.9 Chapter IX - Control of Special Processes................................... 17.1-31 17.1.2.3.10 Chapter X - Inspection .......................................................... 17.1-31 17.1.2.3.11 Chapter XI - Test Control ...................................................... 17.1-31 17.1.2.3.12 Chapter XII - Control of Measuring and Test Equipment................. 17.1-32 17.1.2.3.13 Chapter XIII - Handling, Storage, and Shipping........................... 17.1-32 17.1.2.3.14 Chapter XIV - Inspection, Test, and Operating Status .................... 17.1-33 17.1.2.3.15 Chapter XV - Nonconforming Materials, Parts, or Components ........ 17.1-33 17.1.2.3.16 Chapter XVI - Corrective Action .............................................. 17.1-34 17.1.2.3.17 Chapter XVII - Quality Assurance Records ................................. 17.1-34 17.1.2.3.18 Chapter XVIII - Audits .......................................................... 17.1-34 17.1.3 GENERAL ELECTRIC COMPANY QUALITY ASSURANCE PROGRAM .............................................................................. 17.1-34 17.1.4 BECHTEL POWER CORPORATION QUALITY ASSURANCE PROGRAM .............................................................................. 17.1-35 17.1.4.1 Quality Assurance Topical Report ............................................... 17.1-35 17.1.4.2 Scope of Responsibility............................................................. 17.1-35 17.1.4.3 Project-Unique Modification to BQ-TOP-1, Revision 3A .................... 17.1-36 ATTACHMENT 1................................................................................. 17.1-38 ATTACHMENT 2................................................................................. 17.1-39 ATTACHMENT 3................................................................................. 17.1-42 ATTACHMENT 4................................................................................. 17.1-43 ATTACHMENT 5................................................................................. 17.1-44 ATTACHMENT 6................................................................................. 17.1-45 ATTACHMENT 7................................................................................. 17.1-46 17.2 QUALITY ASSURANCE DURING THE OPERATIONS PHASE ........... 17.2-1 17-ii

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 Chapter 17 QUALITY ASSURANCE LIST OF TABLES Number                           Title                                       Page 17.1-1 General Electric Quality Assurance Evolutionary Process ............. 17.1-47 17-iii

COLUMBIA GENERATING STATION     Amendment 54 FINAL SAFETY ANALYSIS REPORT    April 2000 Chapter 17 QUALITY ASSURANCE LIST OF FIGURES Number                               Title 17.1-1      Energy Northwest Organization Chart 17.1-2      Energy Northwest CGS Organization Chart 17.1-3      CGS Project Management Organization Chart 17.1-4      Burns and Roe, Inc. CGS Organization Chart 17.1-5      Bechtel CGS Organization Chart LDCN-99-000                              17-iv

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 Chapter 17 QUALITY ASSURANCE 17.1    QUALITY ASSURANCE DURING DESIGN AND CONSTRUCTION The quality assurance requirements during design and construction were defined in the FSAR and were revised through Amendment 30 in June 1983. This section is no longer applicable since these phases are completed.
There are four principal participants in Columbia Generating Station (CGS) design and construction quality programs. They are the Owner, Energy Northwest; the Architect/Engineer (AE), Burns and Roe, Inc. (B&R); the Nuclear Steam Supply System (NSSS) Supplier, General Electric Company (GE); and the Construction Manager (CM), Bechtel Power Corporation.
: a. Energy Northwest, as the owner and Licensee, has overall responsibility for assuring that the plant is designed and constructed in accord with approved Quality Assurance Programs (QAPs). The Energy Northwest CGS Project Quality Assurance organization provides management overview of the other elements of the site QAPs. Section 17.1.1 describes the Energy Northwest CGS QAP.
: b. Burns and Roe, Inc. provides Architect/Engineer and related services for CGS.
Section 17.1.2 describes the B&R QAP.
: c. The General Electric Company (GE) provides NSSS design, fabrication, and erection/construction services for CGS. Section 17.1.3 describes the GE QAP.
: d. The Bechtel Power Corporation provides construction management services for CGS. This service consists primarily of direction and coordination of site contractor activities and includes related Quality Assurance/QC services.
Section 17.1.4 describes the Bechtel QAP.
17.1.1    ENERGY NORTHWEST QUALITY ASSURANCE PROGRAM Energy Northwest has implemented a QAP for the design, procurement, and construction of Energy Northwest Columbia Generating Station (CGS). This QAP has been implemented in accordance with requirements of Appendix B to 10 CFR 50. The applicable requirements of Appendix B, 10 CFR 50 are applied to those items classified as Energy Northwest Quality Class I due to their relationship to a nuclear safety function.
As the license applicant, Energy Northwest is responsible for the plant. Therefore, the Energy Northwest CGS QAP and its implementation has been structured to assure that design, LDCN-02-000                                   17.1-1

COLUMBIA GENERATING STATION                        Amendment 57 FINAL SAFETY ANALYSIS REPORT                       December 2003 procurement, and construction activities are accomplished in accordance with sound engineering principles and practices. Systems, components, and structures that are safety-related, in the context of 10 CFR 20, 10 CFR 50, and 10 CFR 100, are required to be designed, specified, fabricated, installed, and tested in accordance with applicable regulatory requirements, codes, standards, specifications, and procedures.
The description of the Energy Northwest CGS Design and Construction QAP which follows is of the program as it currently exists. This program evolved from the original quality program which first appeared in Appendix D.O of the PSAR. The changes involved in this evolution process include: NRC requested changes; updates in organization responsibilities and authorities; and the incorporation of new requirements.
17.1.1.1       Organization Energy Northwest Managing Director is responsible to the Board of Directors for the overall management of Energy Northwest activities, including the establishment and implementation of policies. The Managing Director resolves issues involving quality brought to his attention because of failure to reach resolution at lower levels of management. Overall Energy Northwest organization is shown on Figure 17.1-1.
The Managing Director has the ultimate responsibility for the QAP. The Managing Director shall ensure that the program is implemented and maintained by assigning the appropriate authority and responsibility to the Director of Licensing and Assurance.
The Deputy Managing Director has the authority to implement the policies of the Managing Director. The Deputy Managing Director is accountable to the Managing Director and is responsible for:
: a.      Coordinating and integrating the activities of Energy Northwest organizations,
: b.      Supporting and advising the Managing Director on the performance of Energy Northwest functions and evaluation of such, and
: c.      Acting for the Managing Director, as required.
The Director of Licensing and Assurance reports and is accountable to the Managing Director for the overall development, implementation, and verification of the Energy Northwest Quality Assurance and Nuclear Safety and Regulatory programs to ensure compliance with regulations, codes, and standards. These responsibilities include:
: a.      Determining the adequacy and effectiveness of program implementation, 17.1-2

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003
: b.      Maintaining cognizance of changing regulatory requirements and providing controlled interface between Energy Northwest and regulatory agencies,
: c.      Exercising authority to stop nonconforming work of any Energy Northwest Contractor or Supplier organization, and
: d.      Administering corporate and project Quality Assurance and Nuclear Safety and Regulatory program activities.
The Director of Licensing and Assurance operates through the Manager of Construction Quality Assurance, the Manager of Audits, and the Manager of Nuclear Safety and Regulatory Programs.
The Director of Operations reports and is accountable to the Managing Director for development and implementation of policies and programs supporting the design, construction, and operational phases of Nuclear Power projects WNP-1, CGS, and WNP-3, and the extended construction delay of WNP-4/5. The Director of Operations carries out his responsibilities through the Director of Generation; the Director of Technology; and the Program Directors of WNP-1, CGS, and WNP-3.
The Director of Power Generation reports to the Director of Operations and is responsible for ensuring that the calibration of measuring and test equipment is performed in accordance with approved procedures which establish calibration frequencies, procedures used, recall methods, identification requirements, tolerances and records required to establish equipment history and calibration data.
The Director of Power Generation carries out his responsibilities through the Manager, Generation Services; the Manager, Generation Maintenance; and the Supervisor of Instrumentation Maintenance and Calibration. The Plant Manager and Test and Startup also report to the Director of Power Generation. Startup activities are conducted in accordance with the Operational QAP, Topical Report EN-QA-004, as referenced in Section 17.2.
The Director, Technology reports to the Director of Operations and is responsible for:
: a.      Providing technical and engineering support to the project,
: b.      Assisting the project engineering organization in providing technical direction to the Architect Engineer,
: c.      Assisting the project in performing technical overview of Energy Northwest activities,
: d.      ASME Code consultation to the project, including interfacing with ASME, 17.1-3

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003
: e.      Performing and managing selected technical programs, having applicability to several projects, including preoperational environmental monitoring, and geology,
: f.      Providing independent technical evaluations when requested by the Director of Operations, and
: g.      Overall Energy Northwest records management policy. Implementation of the policy with regard to functions described in this manual is the responsibility of all Directorates, as applicable.
To accomplish this role, the Director of Technology operates through the Assistant Directors, Technology for Systems Engineering, Generation Engineering, CGS Plant Engineering, and Fuel and Environment.
The Director of Support Services reports to the Managing Director and is responsible for the development and implementation of policies and programs which support design, construction, and operation of Energy Northwest plants in the areas of safety and security. Areas in which the Director of Support Services provides support for the projects include industrial safety and fire protection, technical training, administration, and security. To accomplish this role, the Director of Support Services operates through the Manager, Technical Training Programs; the Manager, Administration; the Manager, Health and Safety Programs; and the Manager, Security Programs.
The Chief Financial Officer reports to the Managing Director and is responsible, through the Manager of Central Materials and Procurement, for the development of corporate material management and procurement policy, and the procurement and control of corporate, multiple-project and specialized materials and related services required to support the design and construction of Energy Northwest nuclear power plants.
The Program Director is directly accountable to the Director of Operations and is responsible for the safe, successful, and timely completion of construction of the nuclear plant (including those responsibilities assigned to the Owner by Section III of the ASME Code). The Program Director accomplishes Project responsibilities by managing and directing the AE who performs the design; the CM who manages the construction on the Project; and Project Energy Northwest personnel. See Figures 17.1-2, 17.1-4, and 17.1-5.
The Deputy Program Director reports to the Program Director and is responsible for managing and directing the completion of the design, construction, and turnover to Operations of the power plant in accordance with established requirements. These responsibilities include:
17.1-4

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003
: a.      Monitoring AE/CM internal performance and also monitoring their management of other Contractors performance against established requirements; determines corrective measures and/or gives direction and advice, as necessary,
: b.      Ensuring necessary licenses and permits are obtained, and
: c.      Providing Project-level reviews and reports, as necessary or directed.
The manager of each CGS department or organization, as well as the manager of each Energy Northwest home office support organization, is responsible for:
: a.      Identifying those activities within his organization which are quality-related,
: b.      Establishing and clearly defining the duties and responsibilities of personnel within his organization who execute those quality-related activities, and
: c.      Ensuring that quality-related activities are accomplished by qualified personnel in accordance with approved procedures, as required.
The principal CGS project organizations are shown on Figures 17.1-2 and 17.1-3.
A description of the primary quality-related functions follows.
The project Engineering Manager reports to the Program Director and is responsible for the timely completion of design for effective field engineering support of the construction effort and for the direction of the AE. Included in his responsibilities are:
: a.      Managing the design activities of the Project and ensuring its technical adequacy. This includes all actions necessary to ensure a plant design which is constructable, which conforms to all regulatory requirements and corporate commitments that are necessary to receive and retain an operating license, and which is safe and efficient to operate;
: b.      Those engineering activities which provide solutions and prevention of technical construction restraints which ensure the technical adequacy of the completed construction. In addition, the project Engineering Manager is responsible for dispositioning Energy Northwest-originated nonconformances; and
: c.      Continuous review of the plant design as it applies to NRC commitments and safety requirements.
The project CM is responsible to the program Director for construction activities at the project, including the direction of the CM. Included in his responsibilities are:
17.1-5

COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                           December 2003
: a. Providing the necessary management, monitoring, control, and reporting elements that are necessary to ensure performance of the CM.
: b. Overview of CM for receiving, storage, issuance, and maintenance of Energy Northwest prepurchased equipment and material from the time of receipt at the project (or release from the Contractor) until it is transferred to the final control of the Energy Northwest.
The Site Administration Manager is responsible to the program Director for providing support services which include management of project facilities, services, personnel services, budget control, procedure development and control; and
: a. Shall be responsible for establishing, developing, implementing, and maintaining procedures/instructions for controlling the receipt, distribution, encoding, retention, and disposition of prepurchased equipment, Energy Northwest, AE, CM, and Contractor quality assurance records.
: b. Shall be responsible for the receipt, control, preservation, and retrieval of project construction records.
These responsibilities are carried out through the Manager, Records Management, and the Facilities/General Services Supervisor.
The Business Manager reports to the program Director. The Business Manager ensures that Corporate Contract Management policies and procedures are implemented which include management of contract administration, procurement, materials management, and materials control.
: a. Supervisor, Contract Administration provides contract administration support including construction contract administration, claims management, contract data reporting, bid preparation, evaluation, and award processing;
: b. Manager, project procurement provides purchasing, renting, leasing, or otherwise obtaining materials, equipment, supplies, services, and related phases of contract administration including preparation, award of contracts, and administration;
: c. Manager, project Material Control provides receiving, handling, warehousing, excess materials, and storage until installed; and
: d. Materials Management provides Project inventory control support, coordination of material, identifies material needed, startup, and operations support.
17.1-6

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 The Manager, Program Control reports to the Program Director CGS, and is responsible for:
: a.      Overall administration and coordination of the Project budget, including analyses of Owners cost, construction management forecasts, and AE estimates,
: b.      Overall analysis and reporting for the performance measurement system,
: c.      Financial verification and processing of payments to contractors and vendors, and
: d.      Coordination and administration of the change management system.
The Manager of Project Licensing reports directly to the Manager, Regulatory Programs and is matrixed to the Program Director. The Manager, Project Licensing is responsible for:
: a.      Providing coordinated Project-level management of licensing activities,
: b.      Developing and implementing Project licensing policies consistent with Corporate policies, and
: c.      Ensuring technical adequacy of licensing submittals.
The Manager, Construction Quality Assurance reports to the Director, Licensing and Assurance and is responsible for the development and implementation of the QAP during the Nuclear Power Plant Design and Construction phases. He is also responsible for Procurement QA; plant modifications; qualification and certification of Energy Northwest nondestructive examination and inspection personnel, and other personnel requiring certification; surveillance of nondestructive examination and inspection activities.
The Manager of Procurement Quality Assurance reports to the Manager of Construction Quality Assurance and is primarily responsible for the definition and implementation of the source surveillance/audit program for verification of activities performed by Energy Northwest vendors (including the NSSS vendors). The Manager of Procurement Quality Assurance is specifically responsible for:
: a.      Review of and concurrence with procurement documents for items and services (other than nuclear fuel) initiated by Corporate personnel,
: b.      Performance of preaward surveys/evaluations of vendors/suppliers, and maintaining and distributing an updated listing of those approved, 17.1-7

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003
: c.      Planning, coordination, and performance of source surveillances, source inspections, and source audits to verify implementation of Energy Northwest direct-purchase Supplier QA/QC Programs,
: d.      Review and/or approval of offsite Energy Northwest-administrated vendor/supplier quality assurance/ quality control procedures and programs,
: e.      Perform receipt-inspection of items received at the Corporate Warehouse and Corporate extensions, f       Verify that received items are handled and stored correctly,
: g.      Ensure training of receiving inspectors,
: h.      Provide program overview of AE vendor surveillance activities,
: i.      Quality assurance vendor surveillance of offsite Supplier activities,
: j.      Audits, surveillances, and/or surveys of suppliers of items, materials, or services who do not have ASME Certification, and
: k.      Provide overview of NSSS vendors.
The Project Quality Assurance Manager reports to the Manager, Construction Quality Assurance and is matrixed to the Program Director. The Project Quality Assurance Manager is responsible for:
: a.      Verification of the implementation of Quality Assurance Requirements Manual,
: b.      Verifying adequate implementation of an approved stop work authority program and directing a stop work order should conditions so dictate,
: c.      Assurance of a program for identification and reporting of nonconformances,
: d.      Verification, by audits and surveillances, that the AE, CM, selected contractors, and other Project organizations are implementing applicable quality requirements,
: e.      Ensuring that adequate staffing is obtained to implement the QAPs at the Project,
: f.      The assignment of adequately trained an qualified/certified personnel to perform quality verification activities, 17.1-8

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003
: g. Overview of AE/CM approval of Contractor procedures and instructions,
: h. Reporting significant conditions adverse to quality to the Program Director and the Director, Licensing and Assurance, and
: i. Reporting quality problems and trends to the Manager, Construction Quality Assurance for use in developing standards for Licensing and Assurance management systems to preclude repetition of quality assurance problems.
The Manager of Audits reports to the Director, Licensing and Assurance and is responsible for maintaining an organization of qualified auditors responsible for verifying implementation of the QAP as follows:
: a. Performing quality assurance audits of internal Energy Northwest organizations and external organizations (e.g., AE/CM); except for Management Audits,
: b. Developing audit and surveillance schedules and selecting qualified personnel to perform the activities of this function,
: c. Certification of Audit Team Leaders,
: d. Training of audit personnel,
: e. Participating in audits and providing overview of AE activities,
: f. Periodic review of Corporate and project audit reports to identify any quality trends which may constitute a need for corrective action, and
: g. Maintenance of audit records.
The Manager of Nuclear Safety and Regulatory programs reports to the Director of Licensing and Assurance and is responsible for the development and implementation of policies and programs which support design, construction, and operation of Energy Northwest plants in the areas of Nuclear Safety and Regulatory Programs. Areas in which the Manager of Nuclear Safety and Regulatory Programs provides support for the Projects include nuclear safety assurance, environmental compliance, and licensing. The Manager, Nuclear Safety and Regulatory Programs is responsible for establishment and maintenance of Energy Northwest/
regulatory interfaces and ensuring that nuclear licensing transmittals receive an adequate, competent, and timely review prior to making commitments. To accomplish this role, the Manager, Nuclear Safety and Regulatory Programs operates through the Manager, Regulatory Programs and the Manager, Programs and Safety Performance.
17.1-9

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 17.1.1.2       Quality Assurance Program Energy Northwest has established and implemented a QAP for the design, procurement, and construction phase of the CGS facility. The QAP is based on the assignment of quality classifications which impose applicable quality requirements to structures, systems, and components.
The Energy Northwest QAP and the supporting procedures and instructions comply with the requirements of Appendix B to 10 CFR Part 50, Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants, and applicable regulatory guides as specified in Section 1.8.2 of the FSAR.
Energy Northwests design and construction activities at CGS are performed in accordance with the policies established by the Energy Northwest QAP Manual for Design and Construction.
A matrix of the Energy Northwest QAP procedures and the corresponding criteria of 10 CFR 50, Appendix B, appears in the table below followed by description of the scope covered by these procedures.
Supply 10 CFR 50, Appendix B Criteria              System QAR Organization                                   QAR-1 Quality Assurance Program                      QAR-2 Design Control                                 QAR-3 Procurement Document Control                   QAR-4 Instructions, Procedures and Drawings          QAR-5 Document Control                               QAR-6 Control of Purchased Materials,                QAR-7 Equipment and Services Identification and Control of                  QAR-8 Material, Parts and Components Control of Special Processes                   QAR-9 17.1-10

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 Inspection                                       QAR-10 Test Control                                     QAR-11 Control of Measuring and Test                    QAR-12 Equipment Handling, Storage and Shipping                   QAR-13 Inspection, Test and Operating                   QAR-14 Status Nonconforming Materials, Parts or                QAR-15 Components Corrective Action                                QAR-16 Quality Assurance Records                        QAR-17 Audits                                           QAR-18
: a. Organization - QAR-1 Establishes an organizational structure that will direct the resources of Energy Northwest and its contractors to engineer, design, procure, fabricate, manufacture, install, construct, and test the Energy Northwest Nuclear projects to maximize safety, reliability, and efficiency.
: b. Program - QAR-2 Defines the QAP established by Energy Northwest for design and construction.
Included in this program is a system for classifying structures, systems, components, design characteristics, and procurement documents to determine the Quality Assurance activities associated with each item.
: c. Design Control - QAR-3 Establishes a system of independent reviews to ensure applicable quality regulatory, code, and design basis requirements are properly translated into design and procurement documents for each structure, system, and component.
The documented review provides a check for design adequacy, inspectability, and compatibility with intended usage.
17.1-11

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003
: d. Procurement Document Control - QAR-4 Establishes a system to ensure that procurement documents and changes thereto incorporate the technical and quality assurance requirements necessary to ensure the quality and integrity of procured material, equipment, and services.
: e. Instructions, Procedures, and Drawings - QAR-5 Establishes system defining the requirements and responsibilities controlling the preparation, review, approval, and release of instructions, procedures, and drawings which implement quality requirements.
: f. Document Control - QAR-6 Establishes a system to control the issuance of documents, including changes thereto, which prescribe activities affecting quality.
: g. Control of Purchased Material, Equipment, and Services - QAR-7 Establishes a system to ensure material, equipment and services are procured in accordance with the requirements specified in the procurement documents.
: h. Identification and Control of Materials, Parts and Components - QAR-8 Establishes a system for the identification and control of material, parts, components, equipment and partially-completed assemblies to ensure that items incorporated into the plant are of proper configuration and, when necessary, traceable to all supporting quality assurance documentation.
: i. Control of Special Processes - QAR-9 Establishes a system for the control of special processes.
: j. Inspection - QAR-10 Establishes a system which ensures the program requirements for inspection are delineated in the specifications and contracts and ensures that inspection and surveillance activities are performed in accordance with predetermined requirements delineated in written instructions in a planned and systematic manner.
17.1-12

COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003
: k. Test Control - QAR-11 Establishes a system to ensure that plant testing activities are performed in accordance with predetermined requirements, approved, and delineated in written instructions.
: l. Control of Measuring and Test Equipment - QAR-12 Establishes a system for the control, calibration, and adjustment of tools, gauges, instruments, and other inspection, measuring, testing, and maintenance devices at specified periods to ensure the usage of proper type, range, and accuracy necessary to verify conformance to established requirements.
: m. Handling, Storage, and Shipping - QAR-13 Establishes system to control the handling, storage, shipping, cleaning, and preservation of material, parts, components, and equipment in accordance with written and approved procedures, instructions and recommendations, to ensure that the designed integrity and functionality of the item are maintained.
: n. Inspection, Test, and Operating Status - QAR-14 Establishes a system to indicate the inspection, test, and operating status for all structures, systems, or components to preclude the inadvertent bypassing of their inspection and test requirements and to prevent their inadvertent operation.
: o. Nonconforming Material, Parts, or Components - QAR-15 Establishes a system to ensure that nonconformances are identified, documented, segregated or otherwise controlled, prevented from inadvertent use or installation and that notification of actions taken is transmitted to the affected parties.
: p. Corrective Action - QAR-16 Establishes a system to ensure that significant conditions adverse to quality are identified, the cause determined, documented, brought to the attention of upper management, corrected as soon as possible, and that measures are taken to preclude repetition.
17.1-13

COLUMBIA GENERATING STATION                            Amendment 54 FINAL SAFETY ANALYSIS REPORT                           April 2000
: q.       Quality Assurance Records - QAR-17 Establishes a system for the control and maintenance of all records sufficient and necessary to provide objective evidence of the activities affecting quality.
: r.       Audits - QAR-18 Establishes a system of audits to be performed in a planned and systematic manner to verify compliance and effectiveness of the Energy Northwest QAP.
The CGS Project Management Instructions (PMI) Manual delineates the responsibilities of and interfaces between project organizations. Each project organization is responsible for developing and using implementing procedures/instructions for their assigned functions.
Quality Assurance Instructions, Project Procurement Manuals, and other procedures or instructions pertinent to specific departmental functions describe the measures used to implement the provisions of the programs.
The Energy Northwest Quality Assurance Manager assigned to the CGS Project is responsible for establishing and administering the CGS Quality Assurance policies, goals, and objectives of the QAP and verifying adequate implementation.
The CGS Quality Assurance personnel have the authority and responsibility to perform the necessary actions, including provisions for stop work authority, to accomplish their assignments.
To ensure that CGS Project personnel who perform quality-related activities are cognizant of the quality requirements, they are provided training and indoctrination as prescribed by the Project Training Program. The initial indoctrination includes discussions as to the purpose of applicable codes and standards and familiarization with Appendix B, 10 CFR Parts 50, 50.55(e), and 10 CFR Part 21. The training phase includes instructions on the Project QA policies and instructions on specific quality activities directly related to individual job functions. Personnel whose activities require specific qualifications such as nondestructive testing, audit, inspection, and testing are suitably evaluated, trained as appropriate, and certified.
Training sessions are an ongoing activity and are appropriately documented. Nondestructive test, audit, test, and inspection personnel qualification records are maintained.
The CGS QAP is audited on a regular basis by the Home Office Energy Northwest Audit Section.
LDCN-99-000                                    17.1-14

COLUMBIA GENERATING STATION                          Amendment 59 FINAL SAFETY ANALYSIS REPORT                         December 2007 Contractors who perform safety-related work include the AE, NSSS Supplier, and CM. These contractors are required to establish and implement QAPs consistent with the applicable requirements of 10 CFR Part 50, Appendix B. These programs are reviewed for adequacy by CGS Project personnel. The AE, NSSS Supplier, and Construction Management Contractor quality-related functions are controlled in accordance with the programs described in Sections 17.1.2, 17.1.3, and 17.1.4, respectively.
17.1.1.3      Design Control Burns and Roe, as AE, is responsible for specifying the overall design of the project, except that GE is responsible for design of the NSSS system. Design by other project organizations (contractors) is performed in accordance with an approved QAP. The details of the Burns and Roe and GE CGS QAPs are described in Sections 17.1.2 and 17.1.3 respectively.
Design control is performed by project organizations in accordance with approved procedures and/or instructions.
Design input, such as design bases, performance requirements, regulatory requirements, appropriate quality standards, and industry codes and standards are properly identified, documented, and translated into design documents, such as drawings and specifications.
Procedures describe the controls established for the review, approval, release, distribution, and revision of design documents involving design interfaces.
Changes in design, including field changes, and the reason for changes, are documented, controlled, and reviewed in accordance with measures commensurate with those applied to the original activity.
Computer programs for quality affecting activities are controlled, in accordance with quality program requirements of the user organization.
17.1.1.4      Procurement Document Control Procurement of material, equipment, and services for the Project is accomplished through procurement specifications contracts, or purchase orders which are prepared, reviewed, and approved by cognizant personnel. Procedures require that procurement documents incorporate the applicable quality assurance, regulatory code, and design requirements. The procurement documents require that bidders submit a QAP or plan for major contracts describing their policies, procedures, and systems to be utilized in the control of quality throughout the applicable phases of production, from design to final shipment, erection, or installation.
Procurement documents provide requirements for suppliers to submit or make available for review applicable documents such as drawings, specifications, procedures, instructions, LDCN-06-000                                  17.1-15

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 inspection and test records, and quality assurance records to the Project for review and/or approval.
Procurement documents require suppliers to provide measures for retention, control, and maintenance of their Quality Assurance records procurement documents specify the appropriate records to be delivered to the Project prior to or with delivery.
When source surveillance is required ,procurement documents require suppliers to provide right of access to their facilities, procedures, and records for inspection and audit by Project personnel. Procurement documents issued after January 1978 require the supplier to establish measures for reporting 10 CFR Part 21 reportable deficiencies and disposition of nonconformances from procurement document requirements. Procurement documents require that the supplier retain the responsibility for monitoring and evaluating their sub-tier suppliers performance to specified requirements.
Procurement documents for spare or replacements contain original, equivalent, or improved technical requirements including codes and standards and current applicable QAP requirements.
Changes and revisions to procurement documents are subject to the same or equivalent review/approval requirements as the original document.
17.1.1.5       Instructions, Procedures, and Drawings Activities affecting quality are described in procedures, instructions, and drawings and the activities are conducted in accordance with these documents.
Procedures, instructions, and drawings include adequate quantitative and qualitative acceptance criteria to ascertain that the prescribed activities have been satisfactorily accomplished.
Procedures, instructions, and drawings are subject to review to assure that applicable codes, standards, and acceptance/rejection criteria are included. Review, approval, or information requirements are included in contract documents.
17.1.1.6       Document Control A document control system is implemented by the Project. The requirements ensure that documents, including changes, are reviewed, approved, and released in a timely manner to the locations where the activity is being performed. The Project prepares procedures, instructions, and drawings as necessary to ensure that activities such as design, procurement, manufacturing, construction and installation, testing, inspection, auditing, calibration, and special processes are adequately prescribed and the necessary quality requirements are stated.
17.1-16

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 Changes to these documents require review and/or approval commensurate to that performed on the original document.
Contractors/subcontractors involved in activities affecting quality are required to establish measures for document control which satisfy project requirements.
Changes to specifications and drawings require approval of the cognizant Engineering personnel. As required by Procurement Documents, changes to supplier and contractor drawings and procedures are reviewed and approved by the Project Organization. Changes to documents such as specifications and drawings are indicated by a revision, change order, or equivalent documented methods.
Project drawings and specifications, supplier and contractor drawings, current revisions, addenda, and changes in design and engineering change notices are released in a controlled manner.
To preclude the inadvertent use of obsolete or superseded documents, a Project drawing/specification status report is periodically issued. These reports indicate the current revision to AE drawings and specifications and related changes, addenda, and design and engineering change notices. Site contractors are required to establish measures to ensure that obsolete or superseded documents are controlled to prevent their inadvertent use.
17.1.1.7       Control of Purchased Material, Equipment, and Services Prior to award of contract, Quality Assurance, Engineering, and other personnel, as required, perform an evaluation of accepted bids to determine the suppliers capability to meet procurement requirements. The evaluation may consist of a direct survey of the prospective suppliers facility and personnel or, a review and evaluation of the implementation of his QAP, or evaluation of the suppliers history of providing satisfactory products to the project, or evaluation of the suppliers current records supported by objective evidence.
Surveillance of suppliers, as required, during fabrication, inspection, testing, and shipment of materials, equipment, and components is performed to provide assurance that material, equipment, and services conform to procurement document requirements. Surveillances are conducted by qualified personnel in accordance with established plans and to procedures that identify the attributes or processes to be witnessed and/or verified and the acceptance criteria.
Those items which are simple and standard in design, manufacture, and test, or where quality characteristics can be verified by standard inspections or tests after delivery, are accepted during receiving inspection with no source surveillance. Receiving inspection is performed in accordance with written procedures or instructions.
Measures are established to provide for delivery of documentation from the supplier to the site, prior to or with delivery. These documents provide objective evidence:
17.1-17

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998
: a.      That the items conform to the procurement quality requirements such as specifications, codes, and standards,
: b.      That the required tests, examinations, and inspections have been performed, and
: c.      That nonconformances have been dispositioned as required.
17.1.1.8       Identification and Control of Materials, Parts, and Components Measures are established to identify and control materials, parts, and components including partially completed subassemblies. Requirements for identification and traceability are determined during initiation of design documents and are specified in procurement specifications and on drawings.
These measures require that items important to the safety of the Project are identified in a manner (i.e., heat/lot number, part number, serial number, etc.) that can be traced to the appropriate documentation, or group of documents, such as drawings, specifications, purchase orders, material certifications, etc. The identification is maintained and verified, as required, throughout fabrication, installation, and use of the item.
Implementation of these measures is accomplished by the responsible contractors in accordance with approved procedures.
Verification that items are properly identified is performed during vendor surveillance and receiving inspection activities.
During receipt inspection, materials, parts, and components are identified as acceptable or unacceptable. Where practicable, unacceptable items are physically segregated from acceptable items. Items identified as unacceptable may be released for installation provided the following conditions are met:
: a.      Traceability and identification is maintained,
: b.      The item can be brought to an acceptable condition without damage to associated equipment or structures, and
: c.      Controls are established to ensure retrievability and, when applicable, limit the use of the item.
17.1-18

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998 17.1.1.9       Control of Special Processes Measures are established for the procedural control of special processes that require interim in-process controls in addition to that inspection and/or examination to ensure achievement of required quality. Examples of these processes are coating/plating, heat treating, welding material cleaning, and nondestructive testing (NDT).
Special processes specified in fabrication/construction documents are controlled and are performed by qualified personnel using approved procedures and equipment evaluated to ensure compliance in accordance with applicable codes, standards, and specifications. Special processes delineated in the procurement documents may require that the applicable contractors submit procedures for review and approval.
17.1.1.10      Inspection Measures are established to assure that an inspection program is planned and scheduled.
Equipment manufacturers, installers, and constructors are required by procurement documents to perform the inspection necessary to verify that items conform to established criteria.
Procurement documents also require that inspection activities are performed in accordance with documented instructions, procedures, and drawings, as applicable.
Measures are implemented to ensure that inspections and/or tests are performed on work operations as necessary to verify quality, that personnel performing inspections are independent of the individual or group performing the activity being inspected and are qualified to the requirements of the applicable codes, standards, and company programs. Records of certification of qualification are maintained in a current status. Inspection planning provides measures to identify mandatory inspection hold points for contractor inspection personnel.
Where appropriate, procedures, instructions, and checklists used in performing inspections, include as a minimum:
: a.      Identification of characteristics and activities to be inspected,
: b.      Identification of the individuals or groups responsible for inspection,
: c.      Acceptance/rejection criteria,
: d.      Inspection method, and
: e.      Inspection reports attesting to the completion of inspection and the identity of the inspector or data recorded.
17.1-19

COLUMBIA GENERATING STATION                         Amendment 54 FINAL SAFETY ANALYSIS REPORT                        April 2000 The inspection program provides that modification, repairs, and replacements are inspected in accordance with the original design and inspection requirements or acceptable alternatives.
Construction inspection, and receiving inspection at the Project Site is performed by Construction Management Contractor Quality Control and/or installing contractor Quality Control personnel for those activities within the scope of their responsibility. Construction Management Contractor Quality Control personnel perform receiving inspection functions on project supplied materials, parts and components. Construction Management Quality Assurance personnel perform surveillance/audit functions on these activities to ensure compliance with project requirements.
The Energy Northwest Project Quality Assurance performs surveillance/audit functions on the preceding activities.
17.1.1.11       Test Control A test program is established to specify the requirements and to provide for identification of the testing necessary to demonstrate that structures, systems, and components perform satisfactorily in service.
Testing as addressed in this section pertains to tests performed on prepurchased equipment and materials and, tests performed by the contractors on installed equipment, components, structures, and systems.
The necessary testing requirements are specified in written procedures which incorporate or reference the acceptance limits contained in design and procurement documents and provide that:
: a.       Calibrated test instrumentation and equipment is available,
: b.       Tests are performed under suitable environmental conditions with adequate test methods,
: c.       Tests are conducted by appropriately trained and qualified personnel,
: d.       Items which are modified, repaired, and replaced are tested in accordance with the same requirements which were applied to the original items or an approved alternate, and
: e.       Test results are documented and evaluated to ensure that test requirements have been satisfied.
LDCN-99-000                                    17.1-20

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998 17.1.1.12     Control of Measuring and Test Equipment Measures are established to ensure that tools, gauges, instruments, and other measuring and testing devices are identified, controlled, adjusted, and calibrated at intervals necessary to maintain accuracy within specified limits.
Suppliers and site contractors whose activities are quality affecting are required to implement control of measuring and test equipment in accordance with approved procedures. These procedures contain provisions that:
: a. Devices are adjusted and calibrated at prescribed intervals against certified standards having valid relationships to nationally recognized standards, or, if no national standard exists, the basis for calibration is documented.
: b. Measuring and test equipment is calibrated at specific intervals based on the required accuracy, purpose, extent of use, stability characteristics, and other conditions affecting measurement control.
: c. Measuring and test equipment is calibrated against reference standards.
Records are maintained and equipment adequately identified to indicate calibration status and usage.
: d. When measuring and test equipment is found to be out of calibrations written procedures describe provisions for documenting and evaluating the validity of previous inspections and tests and, for repeating the original inspection or test using calibrated equipment where necessary to establish acceptability of suspect items.
: e. Supplier and contractor procedures specified in procurement documents are reviewed and approved prior to starting work.
17.1.1.13     Handling, Storage, and Shipping Measures are established to control the handling, storage, shipping, cleaning, and preservation of material and equipment to prevent damage or deterioration. Appropriate procedures are prepared in accordance with design specification requirements and manufacturers instructions to provide for special handling, storage, maintenance, cleaning, and preservation. These activities are accomplished in accordance with approved procedures or instructions.
Where required, procedures address requirements for special protective environments such as inert gas atmosphere, moisture content levels, and temperature levels and require that:
17.1-21

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998
: a.      Procurement documents establish requirements for handling, shipping, storage, preservation, and maintenance.
: b.      Items are stored in accordance with their classifications as delineated in Project instructions.
: c.      Storage areas are monitored to assure that the required storage integrity is maintained.
17.1.1.14      Inspection, Test, and Operating Status Measures are established to indicate that inspections and tests performed on structures, systems and components are known throughout fabrication, installation and test. Indicators such as tags, stamps, labels, travelers, or other suitable means are utilized to indicate the status of the item. Where required, structures, systems and components such as valves, switches, electrical, and rotating equipment are tagged or locked out to prevent inadvertant use.
Project organizations and contractors involved in inspection, test, and operation of equipment, components, and systems are required to prepare and implement procedures for the control of these items and activities. Procedures include requirements that specified inspections and tests are performed, that application and removal of status indicators are controlled, that bypassing of quality affecting tests and inspections are controlled, and that systems containing inoperative, malfunctioning or nonconforming items, structures, or components are identified and controlled to prevent inadvertant operation.
17.1.1.15      Nonconforming Materials, Parts, or Components Measures are established for the control of material, parts, components, or services that do not conform to specified requirements.
To prevent inadvertent use or installation, the QAPs of the Project organization, site contractors, subcontractors, and suppliers establish control for identification, documentation, segregation, review, disposition, and notification to affected organizations of non-conforming materials, parts, components, or services.
Written procedures contain provisions:
: a.      For the handling, processing and dispositioning of nonconforming materials, parts, components, or services,
: b.      For the identity of the individuals or groups with the authority and responsibility for the review, disposition and approval of nonconforming items, 17.1-22

COLUMBIA GENERATING STATION                          Amendment 54 FINAL SAFETY ANALYSIS REPORT                         April 2000
: c. That nonconforming items are identified as such, by the appropriate status indicator and are physically segregated where practical from acceptable items until dispositioned,
: d. That rework or repair of nonconforming items be subject to the same, or an equal test or inspection as was originally imposed, or an approved alternate, and the inspection, testing, rework and/or repair activities are documented,
: e. That nonconformance reports are reviewed for potential 10 CFR 50.55(e) and Part 21 reportability,
: f. For identification and control of conditional released items,
: g. That measures are established in procurement documents to require offsite vendors and suppliers to include their nonconformance reports, which deviate from procurement documents, as a part of their Quality Assurance records, and
: h. That site contractors and subcontractors document deviations from contract requirements, and nonconformances dispositioned use-as-is or repair are submitted to the project for review and/or concurrence.
Nonconformance documentation identifies the nonconforming item, describes the nonconformance and the disposition of the nonconformance, identifies any special inspection requirements and the completion of inspection, and contains required signatures/approvals.
Construction Management Contractor Quality Assurance is responsible for the review of these nonconformance reports to ascertain that they have been dispositioned, approved, and closed out.
Reviews include trend studies, corrective action adequacy, and reporting to appropriate levels of management.
The AE is responsible to provide acceptance of disposition for those conditions for which they have assigned technical responsibility. When technical responsibility has not been assigned to the AE, or another design contractor, or when technical requirements are not affected or technical responsibility has been assumed by Energy Northwest, Energy Northwest will provide acceptance of disposition.
17.1.1.16     Corrective Action Measures are established to provide for the prompt identification, evaluation, and correction of conditions adverse to quality such as nonconformances, failures, malfunctions, deficiencies, deviations, defective material, and equipment.
LDCN-99-000                                   17.1-23

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 The QAPs for the project organization and onsite contractors are required to establish provisions:
: a. That corrective action is implemented in accordance with procedures,
: b. That corrective action for significant conditions adverse to quality identify the cause and include actions to preclude recurrence,
: c. That follow-up is performed to verify implementation and close out of corrective action,
: d. That for significant conditions adverse to quality, the cause and the corrective action taken are reported to cognizant management levels, and
: e. That Corrective Action Reports are reviewed for potential 10 CFR 50.55(e) and Part 21 reportability.
17.1.1.17    Quality Assurance Records Measures are established to assure that sufficient records are maintained to provide documentary evidence of the quality of items and the activities affecting quality.
Quality Assurance records include:
: a.       Test logs,
: b.       Results of reviews of inspection, tests, audits, and material analysis,
: c.       Surveillance and audit documents,
: d.       Qualification of personnel, procedures and equipment,
: e.       Drawings, as-built drawings and specifications,
: f.       Procurement documents,
: g.       Calibration procedures and reports, and
: h.       Nonconformance and corrective action reports.
Inspection and test records contain as applicable:
: a. Type of inspection, test, or examination,
: b. Identity of inspector or data recorded,
: c. Date and results of inspection/test,
: d. Acceptability,
: e. Action taken relative to deficiencies noted, and
: f. Identification with the applicable item or activity.
17.1-24

COLUMBIA GENERATING STATION                          Amendment 54 FINAL SAFETY ANALYSIS REPORT                         April 2000 Suppliers, vendors, and contractors are required to furnish Quality Assurance records prior to or on delivery of equipment, supplies, structures, or systems, or retain them if required by contractual agreement.
Procedures are established and contain provisions for the identification of individuals or groups responsible for record transmittals, retention, and maintenance, and provisions for ensuring that records are identifiable and retrievable.
Record storage facilities are constructed, located and secured to prevent destruction by fire, flooding, theft, and deterioration by extremes in temperature and humidity.
17.1.1.18      Audits Measures are established to provide a system for conducting audits to verify compliance with all aspects of the QAP and to determine the effectiveness of the program. All aspects include activities associated with:
: a. Indoctrination and training programs,
: b. Interface control between Energy Northwest and the principal Contractors,
: c. Corrective action, calibrating, and nonconformance control systems, and
: d. SAR commitments.
The project organizations and principal contractors have established and implemented an audit system which includes objective evaluations of quality-related practices, procedures, activities, and records. The system ensures that the necessary audit functions are performed to preestablished written procedures or checklists, in a planned and systematic manner, and are conducted by trained and qualified personnel who do not have direct responsibility in the areas being audited.
The audit system provides for external audits to be performed, as appropriate, by the home office, project organization, and principal contractors on their suppliers, vendors, and contractors, and internal audits to be performed within each organization.
Audits are planned and scheduled on the basis of the status and safety importance of the activities being performed. They are initiated early enough and performed at regular intervals to ensure the QAP is effectively implemented during design, procurement, manufacture, construction, and installation.
Audits are documented and reviewed with the level of management responsible for the area audited and, where required, follow-up action including reaudit of the deficient areas is performed.
LDCN-99-000                                   17.1-25

COLUMBIA GENERATING STATION                        Amendment 54 FINAL SAFETY ANALYSIS REPORT                       April 2000 Audit data is evaluated to assure that the QAP is effective and properly implemented and the results are reported to management for review and assessment.
The Energy Northwest CGS quality affecting activities are audited on a scheduled basis by the Energy Northwest home office audit group.
17.1.2      THE BURNS AND ROE, INC. QUALITY ASSURANCE PROGRAM 17.1.2.1       Introduction The Burns and Roe, Inc. (B&R) QAP for the Energy Northwest Columbia Generating Station (CGS) has evolved during the design and construction of CGS. The original B&R QAP was described in the Atomic Energy Commission accepted Preliminary Safety Analysis Report (PSAR) for CGS, Appendix D.O. This QAP was implemented until February 1978, when Energy Northwest assumed responsibility for Construction Management, Site Quality Assurance, and Vendor Surveillance of selected prepurchased equipment contracts. The B&R QAP was implemented during this phase of the CGS PSAR Deviation Request No. 15 WP. In this phase, B&R was responsible for the AE scope of the engineering and design of CGS and provided experienced Quality Assurance personnel to carry out Energy Northwests assumed responsibilities. On June 1, 1981 B&R implemented their Quality Assurance Topical Report, B&ROE-COM4-1-NP-2A, approved by the Nuclear Regulatory Commission, with documented exceptions for the B&R engineering and design and procurement activities for CGS.
17.1.2.2       The Burns & Roe, Inc. Quality Assurance Topical Report The QAP for CGS was implemented by B&R on June 1, 1981 and is based on the B&R Quality Assurance Topical Report with documented exceptions, CGS Final Safety Analysis Report (FSAR) commitments, Energy Northwest direction and the B&R contractual responsibilities for the design and construction of CGS. The B&R responsibilities for the CGS Project are engineering and design, and procurement activities for assigned prepurchased equipment contracts. The exceptions to the Quality Assurance Topical Report are identified in the following subparagraphs.
17.1.2.3       Exceptions to the Burns & Roe, Inc. Quality Assurance Topical Report 17.1.2.3.1        Chapter I - Organization Paragraph 4.1.2 The B&R CGS Project Organization chart is shown as Figure 17.1-4.
LDCN-99-000                                 17.1-26

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 Paragraph 4.3 Construction Management is not within B&R scope of services.
17.1.2.3.2       Chapter II - Quality Assurance Program Paragraph 2.1 The US NRC Regulatory Guides applicable to CGS are identified in Section 1.8.3 of the CGS FSAR.
Paragraph 4.6 Under the B&R CGS QAP, satisfactory accomplishment of the following quality affecting functions shall be verified:
: a.      The design process is accomplished in accordance with established procedures.
: b.      Specifications contain appropriate quality requirements.
: c.      For those prepurchased equipment contracts for which Burns and Roe performs the vendor surveillance function:
: 1.      Contractors QAPs and procedures are adequate,
: 2.      Nonconformances are identified and dispositions provided, and
: 3.      Material receiving, inspection, and storage functions are performed in accordance with established procedures.
: d.      Surveillance of the activities performed by Contractors whose sole function is to provide engineering and design services.
: e.      Audits of the quality affecting activities described above are performed on a scheduled basis.
17.1.2.3.3       Chapter III - Design Control Paragraph 2.1 10 CFR 50, Appendix B and ANSI N45.2 are the basis for the B&R design control program.
17.1-27

COLUMBIA GENERATING STATION                         Amendment 54 FINAL SAFETY ANALYSIS REPORT                        April 2000 Paragraph 4.1 The detailed design effort is based only on an approved project criteria document.
Paragraph 5 Additional design reviews/verifications have been performed on a sampling of previously issued system designs by the performance of special design reviews in accordance with project procedure WNP-2-ED-013.
Burns & Roe, Inc. procedures for design control have been upgraded to verify that future issued designs and modifications comply with applicable codes, standards, and design requirements.
17.1.2.3.4       Chapter IV - Procurement Document Control Paragraph 3.4 Records to be retained, controlled and maintained by a supplier are not identified in the specification.
Paragraph 4 The appropriate commercial requirements are established by Energy Northwest and/or B&R and may be incorporated during the initial preparation of the technical specification. Energy Northwest prepares the potential bidders list.
Paragraph 5 Award is determined by Energy Northwest using the bid evaluation prepared by B&R.
Paragraph 6 Technical specifications are not normally conformed. When technical specifications are conformed, the changes are reviewed and approved in accordance with the same procedure used for the original technical specification.
Paragraph 7 Later procurement of spare or replacement parts shall be to the original or improved technical requirements. Impositions of Quality Assurance requirements will be in accordance with the Quality Assurance requirements of the existing specification for procurement of components LDCN-99-000                                   17.1-28

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998 which are added to existing contracts. The latest CGS Project Quality Programs are imposed on new procurements.
17.1.2.3.5     Chapter V - Instructions, Procedures, and Drawings Paragraph 2.2 Burns and Roe, Inc. review of Quality Assurance plans required by procurement documents is limited to those prepurchased contracts for which B&R performs the vendor surveillance function.
Paragraph 2.5 Burns and Roe verification of the implementation of instructions, procedures, and drawing programs is limited to those prepurchased contracts for which B&R performs the vendor surveillance function.
17.1.2.3.6     Chapter VI - Document Control Paragraph 2.1 The B&R CGS QAP, in regard to document control, does not govern the following:
: a. Procurement documents, except for prepurchased equipment contracts for which B&R performs the vendor surveillance function,
: b. Quality Assurance plans, except for the B&R Quality Assurance Plan and the quality assurance plans prepared by prepurchased equipment contracts for which B&R performs the vendor surveillance function,
: c. Contractor manufacturing, inspection, and testing procedures, except for those prepared by prepurchased equipment contracts for which B&R performs the vendor surveillance function,
: d. Construction and operational test procedures, and
: e. Nonconformance reports, except for those prepared by prepurchased equipment contracts for which B&R performs the vendor surveillance function.
17.1-29

COLUMBIA GENERATING STATION                       Amendment 54 FINAL SAFETY ANALYSIS REPORT                     April 2000 Paragraph 2.3 Changes to documents listed in Paragraph 2.1 may be made and implemented prior to the official revision of the document provided an advance change system exists and is controlled by approved project instruction and/or procedures.
Paragraphs 2.6 and 2.7 Burns and Roe verification of Contractors document control programs is limited to those prepurchased contracts for which B&R performs the vendor surveillance function.
17.1.2.3.7      Chapter VII - Control of Purchased Material, Equipment, and Services Paragraph 3 Recommended bidder lists are not prepared by B&R.
Paragraph 4.2 Quality Assurance audits are performed after contract award.
Paragraph 4.3 Recommendations for award are made by project management to Energy Northwest and Energy Northwest approves and makes the award.
Paragraph 4.4 Records of B&R bid evaluations and recommendation are only maintained by B&R for the supplier selection process.
Paragraphs 5 and 6 Surveillance plans are approved by the Manager of Vendor Surveillance and are subject to Project Quality Assurance review.
Paragraphs 6.3 and 7 Not applicable to B&R CGS QAP.
LDCN-99-000                                 17.1-30

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998 17.1.2.3.8      Chapter VIII - Identification and Control of Material Parts and Components Paragraph 2.1 Verification of identification of components, assemblies and subassemblies is performed by B&R only on prepurchased contracts for which B&R performs a final inspection prior to shipment.
17.1.2.3.9      Chapter IX - Control of Special Processes Paragraphs 2.5 and 2.6 Only when performing the function of vendor surveillance on prepurchased contracts does B&R evaluate and verify a Contractors special process control program.
17.1.2.3.10     Chapter X - Inspection Paragraph 2.1 The applicability of US NRC Regulatory Guides is as committed in Section 1.8.3 of the CGS FSAR. Mandatory hold points for prepurchased contracts are established after contract award and are contained in the Vendor Surveillance Plan for each Contract.
Paragraph 2.4 Verification that the contractors inspection program is being effectively implemented is accomplished by a series of surveillances and audits performed by quality assurance personnel for those prepurchase contracts which Burns and Roe has retained the vendor surveillance function.
17.1.2.3.11     Chapter XI - Test Control Paragraph 2.1 The applicability of US NRC Regulatory Guides are as committed in Section 1.8.3 of the CGS FSAR.
Paragraph 2.6 Verification of the implementation of a Prepurchase Contractors test control program is performed by B&R for prepurchased contracts when B&R performs the vendor surveillance function.
17.1-31

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 17.1.2.3.12     Chapter XII - Control of Measuring and Test Equipment Paragraph 2.3 Selected prepurchase contractor programs for the control of measuring and test equipment are subject to engineering review and approval by B&R.
Paragraph 2.4 Verification that the program for the control of measuring and test equipment is being effectively implemented is ensured by a series of surveillances and audits performed by quality assurance personnel for those prepurchase contracts which Burns and Roe has retained the vendor surveillance function.
17.1.2.3.13       Chapter XIII - Handling, Storage, and Shipping Paragraph 2.3 Only selected prepurchase contractor programs for the control of handling, preservation, storage, cleaning, packaging, and shipping of items are subject to review and approval by Burns and Roe, Inc. personnel. This procedurally controlled and documented review is the responsibility of the cognizant system or component engineer and includes review by a quality assurance engineer. Project management, based on comments generated during the review, makes an approval determination.
Paragraph 2.4 Not applicable to B&R CGS QAP.
Paragraphs 2.5, 2.6, and 2.7 These requirements are applicable to those prepurchased contracts for which B&R performs the vendor surveillance function.
Paragraph 2.8 Verification of the implementation of Contractor programs for handling, storage, and shipping is performed by B&R only for prepurchased contracts when B&R performs the vendor surveillance function.
17.1-32

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998 17.1.2.3.14     Chapter XIV - Inspection, Test, and Operating Status Paragraph 2.3 Not applicable to B&R CGS QAP.
Paragraph 2.4 Selected prepurchase contractor programs for inspection, test, and operating status are subject to engineering review and approval by B&R, for prepurchased contracts which B&R has retained by vendor surveillance function.
Paragraph 2.5 Verification that the inspection, test, and operating status program is being effectively implemented is ensured by a series of surveillances and audits performed by quality assurance personnel for prepurchased contracts which B&R has retained the vendor surveillance function.
17.1.2.3.15       Chapter XV - Nonconforming Materials, Parts, or Components Paragraph 2.2 Nonconformance reports are not included in final data packages forwarded to B&R.
Nonconformance reports on the CGS Project are not issued or analyzed for quality trends by B&R.
Paragraph 2.3 Selected prepurchase contractor nonconformance control programs are subject to engineering review and approval by B&R.
Paragraph 2.4 All nonconformance reports for those conditions for which B&R has the assigned technical responsibility require engineering review and approval by B&R. Such dispositioned nonconformance reports must be concurred in by the B&R Quality Assurance Manager or designated Quality Assurance Engineers.
Paragraph 2.5 Not applicable to the B&R CGS QAP.
17.1-33

COLUMBIA GENERATING STATION                        Amendment 54 FINAL SAFETY ANALYSIS REPORT                       April 2000 17.1.2.3.16     Chapter XVI - Corrective Action No deviations.
17.1.2.3.17     Chapter XVII - Quality Assurance Records No deviations.
17.1.2.3.18     Chapter XVIII - Audits Paragraph 2.10 Not applicable to B&R CGS QAP.
Paragraph 2.11 The audit program on material and equipment suppliers applies only to those prepurchased contracts for which B&R performs the vendor surveillance function.
17.1.3      GENERAL ELECTRIC COMPANY QUALITY ASSURANCE PROGRAM The applicable QAP and detailed procedures of the CGS NSSS and fuel have evolved during the design and construction phases of the CGS plant. The original GE program for CGS was implemented in 1968 and is described in the PSAR, Appendix D. The program at that time was in accordance with the Nuclear Energy Division (NED) quality objectives for safety and reliable systems and components as set forth in the Blue Book issued August 20, 1968. On October 1, 1969, the Blue Book was replaced with the Green Book, Revision 0, which incorporated the intent of the then Proposed Atomic Energy Commission (AEC) Quality Assurance (QA) Criteria. The Green Book has proceeded through several revisions since 1969. The latest revision is NEDO-11209-04A, dated October 1980. Table 17.1-1 is a matrix showing the entire evolutionary process which the GE program has undergone since August 1968 and identifies related NRC and industry standards that were applied. The actual version in effect at any point in time controlled the QA measures applied to CGS by GE for work when it was initiated, consistent with any necessary contractual adjustments to update from the 1970 base date of the contract with Energy Northwest. For example, any work initiated after March 1978, applies the criteria represented by Green Book (NEDO-11209-04A). Note that those portions dealing with the Standard Reactor Island (STRIDE) are not applicable to CGS in that CGS is not provided a STRIDE by GE.
In so far as the NSSS is concerned, GE positions and commitments to regulatory guides and ANSI Standards, as made in the applicable revisions of NEDO-11209, take precedence over the positions and commitments described in the FSAR Chapter 3.
LDCN-99-000                                   17.1-34

COLUMBIA GENERATING STATION                           Amendment 54 FINAL SAFETY ANALYSIS REPORT                          April 2000 17.1.4      BECHTEL POWER CORPORATION QUALITY ASSURANCE PROGRAM 17.1.4.1       Quality Assurance Topical Report The Bechtel QAP Plan for use by the Bechtel Power Corporation during Construction Management and System Completion of Energy Northwest Project CGS is described in the NRC-approved Bechtel Topical Report BQ-TOP-1, Revision 3A, Bechtel Quality Assurance Program for Nuclear Power Plants.
17.1.4.2       Scope of Responsibility This section describes Bechtel responsibilities for providing quality-related services in Construction Management and Systems Completion to Energy Northwest on the CGS Project.
The scope of responsibility differs from that indicated in BQ-TOP-1 in that Bechtel does no function as the responsible design engineering organization. Therefore, those provisions in BQ-TOP-1 associated with design engineering do not apply.
Bechtel will have an engineering management group under the direction of the Project Engineering Manager. This group will provide engineering management staff support capability to Energy Northwest. Engineering personnel will assist in developing the scope and relative priority of remaining engineering activities and will interface with Energy Northwest licensing personnel. Bechtel may perform engineering design assignments on a task basis.
Such design tasks will meet design requirements established by the AE (B&R) and will be performed to the applicable requirements of BQ-TOP-1.
Bechtel will perform construction in the completion of systems, structures, components as assigned by Energy Northwest, utilizing materials provided by Energy Northwest.
Construction Management provisions for quality-related services include:
: a.      Receiving, including receipt inspection of Energy Northwest purchased items,
: b.      Storage and maintenance of Energy Northwest purchased items,
: c.      Contractor/vendor QA documentation review, retention, and turnover to the Energy Northwest,
: d.      Review and approval of onsite contractor quality-related procedures and manuals,
: e.      QA/QC audit and surveillance inspection over onsite contractor activities,
: f.      Administration of the project program for controlling nonconforming items, LDCN-99-000                                   17.1-35

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998
: g. Administration of the project program for control of design documents, and
: h. Procurement services, including procurement supplier quality services, in support of construction activities.
17.1.4.3  Project-Unique Modification to BQ-TOP-1, Revision 3A
: a. Introduction, Page 3 - Replace Regulatory Guide 1.58 (August 1973) with Regulatory Guide 1.58, Revision 1 (September 1980).
: b. Introduction, Page 3 - Add Regulatory Guide 1.146 Qualification of Quality Assurance Program Audit Personnel for Nuclear Power Plants (Revision 0, 1978). See Section 1.8.3 for compliance statement.
: c. Introduction, Page 3 - Replace ANSI Standard N45.2.12-1974 with Regulatory Guide 1.144, Auditing of Quality Assurance Programs for Nuclear Power Plants (Revision 1, 1980). See Section 1.8.3 for compliance statement.
: d. Section 1, Organization, Subsection 1.5.1, Page 10 - Replace Subsection 1.5.1 with Attachment 1.
: e. Section 1, Organization, Subsection 1.5.2, Page 10 - Replace Subsection 1.5.2 with Attachment 2.
: f. Section 1, Organization, Subsection 1.5.4, Page 11- Replace Subsection 1.5.4 with Attachment 3.
: g. Section 2, Quality Assurance Program (Subparagraphs 2 and 4), Page 23 -
Change Regulatory Guide 1.58 (August 1973) to Regulatory Guide 1.58, Revision 1 (September 1980).
: h. Section 2, Quality Assurance Program (Subparagraph 3), Page 23 - Change ANSI N45.2.12 to ANSI N45.2.23.
: i. Change Project Engineer to Project Engineering Manager throughout.
: j. Table 1, Bechtel Quality Program Documents, Page 57 and 58 - Add to Table 1 the Project Documents shown on Attachment 4.
: k. Add Figure 15, Bechtel Projects Management Organization, Attachment 5.
: l. Add Figure 16, Quality Assurance/Quality Control Organization, Attachment 6.
17.1-36

COLUMBIA GENERATING STATION                        Amendment 53 FINAL SAFETY ANALYSIS REPORT                       November 1998
: m. Appendix A, Bechtel Position on QA NRC Regulatory Guides and ANSI Standards - Delete 5th paragraph (A-7) on Page A-1; Delete pages A-7 through A-13 entirely. Delete 11th paragraph (A-22) on Page A-1; delete Pages A-22 and A-23 entirely.
: n. Appendix B, Division Quality Policies, Scope, and Relationship to 10 CFR 50, Appendix B - Add Project Nuclear Quality Assurance Manual as shown by Attachment 7.
17.1-37

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 ATTACHMENT 1 The Manager of Projects (Attachment 5) is the senior Bechtel representative assigned to the CGS Project. The Manager of Projects reports to the Division Manager of Project Operations and is responsible for providing overall project direction to ensure the consistent and coordinated application of Bechtel policies and skills for the benefit of the CGS Project. The Manager of Projects staff includes a Deputy Manager of Projects and other managers to coordinate activities in labor relations, the quality program, and administrative services.
17.1-38

COLUMBIA GENERATING STATION                            Amendment 53 FINAL SAFETY ANALYSIS REPORT                           November 1998 ATTACHMENT 2 QUALITY ASSURANCE The SFPD QA Manager (SFHO) is independent of the other managers within the division and has the authority to carry out the responsibilities listed below in directing the Division QAP. He is assisted by a staff of Quality Assurance Managers (SFHO) assigned to functional areas of Program, Technical Services, Training, Project QA, and Audit. The SFPD QA Managers (SFHO) functions for the CGS Project include:
: a.      Provide technical guidance and concurrence for the CGS Project QAP for conformance with the requirements of 10 CFR 50, Appendix B;
: b.      Formulate and approve Division Quality Assurance Department Procedures which define responsibilities, authority, and functions of SFPD home office staff Quality Assurance Department personnel. Review and concur with the CGS PQAM and revisions;
: c.      Maintain an awareness of CGS project status, through management audit and day-to-day contact with the Manager of Quality, and provide assistance to the Manager of Quality to ensure timely and effective implementation of the CGS QAP;
: d.      Formulate and conduct management QA audits to assure compliance with the CGS Nuclear Quality Assurance Manual (NQAM) and implementing procedures, and identify quality problems; identify the need for corrective action and initiate, recommend, coordinate or provide solutions; and verify implementation of solutions and corrective actions;
: e.      Provide and maintain a qualified and suitably trained staff of Quality Assurance Engineers to carry out required project and staff functions. Assign Quality Assurance Engineer(s) to the CGS project and provide them with administrative direction through the QA Manager - Projects (SFHO);
: f.      Formulate and implement programs to provide indoctrination and training of Quality Assurance Department Personnel to ensure that suitable proficiency is maintained; and
: g.      From information supplied by the Manager of Quality, provide quarterly reports to the Division Manager and Manager of Quality Assurance, evaluating the status and adequacy of the WNP-BPC QAP, and advising of any problems requiring program revision or special attention including recommendations for corrective actions. At least annually, a meeting is held with the Division 17.1-39

COLUMBIA GENERATING STATION                           Amendment 54 FINAL SAFETY ANALYSIS REPORT                          April 2000 Manager (SFHO) and his staff on the subject of status and adequacy of the Division QAP. The Manager of Quality participates in this meeting to cover the status and adequacy of the CGS QAP.
MANAGER OF QUALITY The Manager of Quality receives administrative, technical, and project direction from the Manager of Projects, and is responsible for the project and technical direction of the CGS QAP. The Manager of Quality receives technical guidance for QA and QC from the SFPD QA Manager (SFHO) and Chief Construction Quality Control Engineer (SFHO) respectively. He is assisted by, and provides project and technical direction to the Project Quality Assurance Engineer and Project Construction Quality Control Engineer (Attachment 6). The Manager of Quality is independent of the other line managers within the Project Management organization and has the authority to carry out the responsibilities listed below in directing the QAP including authority to stop work or control further processing. The Manager of Qualitys functions include:
: a.      Provide technical and project direction to Quality Assurance Engineers assigned to the Energy Northwest projects;
: b.      Formulate and approve, after review and concurrence by the SFPD QA Manager (SFHO) the Energy Northwest Projects SAR and QAPs as defined in the Energy Northwest Projects NQAMs. The NQAMs shall be in conformance with the requirements of 10 CFR 50, Appendix B, the TPO Quality Program Policy Manual, and the appropriate Project SAR;
: c.      Formulate and approve, after review and concurrence by the SFPD QA Manager (SFHO) the revisions to the Energy Northwest Projects SARS and NQAMs. Coordinate revisions to implementing procedures to improve effectiveness of the QAP and update the program;
: d.      Formulate and approve, after review and concurrence by the SFPD QA Manager (SFHO) the Project Quality Assurance Department Procedures and revisions for Energy Northwest Projects which define responsibilities, authority, and functions of Energy Northwest Projects Quality Assurance personnel;
: e.      Review quality-related procedures and manuals prepared by centralized support functions outside of the Division (e.g., Procurement, C&S, M&QS) to verify conformance with requirements of the Energy Northwest Projects NQAMs and approve, through the Manager of Quality Assurance BPC, for use as part of the QAP on the Energy Northwest projects; LDCN-99-000                                   17.1-40

COLUMBIA GENERATING STATION                            Amendment 54 FINAL SAFETY ANALYSIS REPORT                           April 2000
: f. Maintain an awareness of project status, through contact with the Manager of Projects and ensure timely and effective implementation of the QAP;
: g. Direct the performance of project audits to ensure compliance with Energy Northwest projects NQAMs and implementing procedures, and to identify quality problems; identify the need for corrective action and initiate, recommend, coordinate or provide solutions; and verify implementation of solutions and corrective actions;
: h. Provide quarterly reports to the SFPD QA Manager (SFHO) evaluating the status and adequacy of the Energy Northwest projects QAP and advising of any problems requiring program revision or special attention, including recommendations for corrective actions;
: i. Review Division standard criteria for specifying QAP requirements applicable to contractors and subcontractors, and approve for use on the Energy Northwest projects; and
: j. Coordinate the Quality Assurance and Quality Control functions for the Energy Northwest Projects with the Division groups having quality functions, and with groups outside the Division having quality functions, e.g., M&QS, C&S, and PSQD.
LDCN-99-000                               17.1-41

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998 ATTACHMENT 3 DIVISION CONSTRUCTION The Manager of Division Construction provides technical and administrative direction of the Construction Department personnel. The Manager of Division Construction (SFHO) is assisted by CMs (SFHO), Chief Construction Engineers (SFHO), where assigned, and the Chief Construction Quality Control Engineer (SFHO). Construction Managers (SFHO) are responsible for the management and technical direction of assigned projects, and for ensuring that construction projects are provided with appropriate personnel and are following prescribed division practices and procedures for conduct of construction activities. Chief Construction Engineers (SFHO) are responsible for providing division standard work procedures to the projects.
Formal quality verification inspection and onsite contractor surveillance inspection activities performed by Bechtel are the responsibility of Construction Quality Control. The Chief Construction Quality Control Engineer (SFHO) is responsible for providing administrative direction to the Construction Quality Control Engineers assigned to the CGS Project. The Chief Construction Quality Control Engineers functions include:
: a.      Provide administrative direction to the Project Construction Quality Control Engineer,
: b.      Assign quality control engineers to the project,
: c.      Assist with the training and qualification of construction quality control engineers, and
: d.      Provide technical guidance to the Manager of Quality for the preparation of quality control procedures and instructions.
17.1-42

COLUMBIA GENERATING STATION                            Amendment 53 FINAL SAFETY ANALYSIS REPORT                           November 1998 ATTACHMENT 4 PROJECT QUALITY PROGRAM DOCUMENTS Review for QA Originating          Policy and         Authorizing Documents           Authority            Program            Approval             Contents Requirements Nuclear Quality     Project QA           SFPD QA Manager    Manager of Quality Quality program Assurance Manual    Engineer             (SFHO)                                policy. Based on (NQAM)                                                                         Division policy as contained in SFPD Standard NQAM Project QA manual   Project QA           SFPD QA Manager    Manager of Quality Procedures for (PQAM)              Engineer             (SFHO)                                conducting Project QA activities Construction        Project              Project QA         Manager of Quality Responsibilities and Quality Control     Construction         Engineer                              procedures for Manual (CQCM)                                                                  construction QC activities Construction        Project Field        Project QA         Chief Construction Responsibilities and Procedures          Engineer             Engineer           Engineer (SFHO)    requirements for construction site activities Bechtel Quality     Manager of Codes     Manager of Quality President - BPC    Policies and Assurance Manual    and Standards        and SFPD - QA      and appropriate    procedures for ASME Nuclear                             Manager (SFHO)     authorized code    overall Bechtel Components                                                  inspection agency  Program applicable to ASME work Engineering         Project Engineering  Project QA         SFPD Engineering   Responsibilities and Department Project  Manager              Engineer           Manager            requirements for Instructions                                                                   engineering departments activities Field Procurement   Project Field        Project QA         Manager of Field   Responsibilities and Procedures          Procurement          Engineer           Procurement        requirements for
[individual jobsite Manager                                                    field procurement instructions (IJI)]                                                            activities Procurement         Manager              Manager QA - BPC   Manager            Procedures for Supplier Quality    Procurement                             Procurement        procurement, Manual              Supplier Quality                        Supplier Quality   supplier quality activities Field Procurement   Manager Field        Manager QA - BPC   Manager Field      Procedures for field Procurement                             Procurement        procurement activities 17.1-43

COLUMBIA GENERATING STATION                                     Amendment 53 FINAL SAFETY ANALYSIS REPORT                                    November 1998 ATTACHMENT 5 DIVISION PROJECT OPERATIONS & SERVICES MANAGER SFPD HOME OFFICE PLANT PROJECT MANAGER OF PROJECTS PROJECT MANAGER PROJECT                                                      SITE                      PROJECT COST AND SCHEDULE                 MANAGER OF                 CONSTRUCTION                  ENGINEERING MANAGER                       QUALITY                      MANAGER                      MANAGER 17.1-44

QUALITY ASSURANCE/QUALITY CONTROL ORGANIZATION SFPD SFPD                                                                             Chief Construction QA MANAGER                                                                           Quality Control (SFHO)                                                                             Engineer (SFHO)
MANAGER COLUMBIA GENERATING STATION OF QUALITY 17.1-45                                                                                                                                         ATTACHMENT 6 FINAL SAFETY ANALYSIS REPORT PROJECT                                                                                  PROJECT QUALITY                                                                               CONSTRUCTION ASSURANCE                                                                             QUALITY CONTROL ENGINEER                                                                                  ENGINEER LEGEND AND NOTE                                                         NOTE:   The SFPD QA Manager (SFHO) is responsible for performing management QA audits of the Amendment 53
__________ PROJECT AND TECHNICAL DIRECTION                                       Plant Project Quality Assurance/Quality Control
_ _ _ _ _    TECHNICAL GUIDANCE AND COORDINATION                                 Organization November 1998 ADMINISTRATIVE DIRECTION

17.1-46 IX                 VI    I II XVI      XV   XIII   X XI                       III             10CFR50 XVII                 XII                VII   IV V
XIV                VIII                         APP. B XVIII CRIT.
ORGANIZATION QUALITY ASSURANCE PROGRAM DESIGN CONTROL PROCUREMENT DOCUMENT CONTROL INSTRUCTIONS, PROCEDURES, AND DRAWINGS DOCUMENT CONTROL CONTROL OF PURCHASED MATERIAL,                                                                                                    SAN FRANCISCO EQUIPMENT, AND SERVICES IDENTIFICATION AND CONTROL OF MATERIALS, PARTS AND COMPONENTS CONTROL OF SPECIAL PROCESSES INSPECTION TEST CONTROL                                                                 SUBJECT                                             POWER DIVISION CONTROL OF MEASURING AND TEST EQUIPMENT HANDLING, STORAGE AND SHIPPING INSPECTION, TEST, AND OPERATING STATUS NONCONFORMING MATERIAL, PARTS OR COMPONENTS CORRECTIVE ACTION QUALITY ASSURANCE RECORDS AUDITS Table of contents QA Program Applicability QA Program Definition Definitions Fire Protection QA Program Radwaste Management System QA Program Seismic II/I QA Program 1 2 3 4 5 6 7 8 1 2 3 4 5 6 7 8 9 10 11 1 2 3 4 5 Matrix Organization Charts SFPD Organization Project QA Team Project Management Team APPENDIX B Project Engineering Team Project Construction Team Project Organization Charts Procurement Department SECTION            SECTION            SECTION Materials & Quality Services Department DIVISION QUALITY POLICIES, SCOPE, AND RELATIONSHIP Bechtel Power Corporation Construction Department Design Control Procedures Design Process and Change Control Design Verification Design Interface TO 10 CFR 50, APPENDIX B 0                  I                  II Specialty Group Design Control Supplier Evaluation Field Procurement Supplier Control & Source Surveillance NUCLEAR QUALITY 1 2 3 4 1 2 3 4 5 6 7 8 Supplier Document Processing Construction Site Quality Program Mat'l Rec, Stor, Maint, Hand, & Cont.
Field Inspection and Test SECTION      SECTION                                Nonconforming Materials Control of Measuring and Test Equipment ASSURANCE MANUAL System T/O for Preoperational Testing III           IV                                  Field Contractor/Subcontractor Control Control of Special Processes NQAM Policies and Revisions Quality Assurance Procedures Indoctrination, Training & Qualification 1 2 3 4 5 6 7 8 9 Management Corrective Action Stop Work SECTION                                       Procedure Control Quality Assurance Records Quality Action Requests V
Status and Adequacy Review 1                  Quality Audit System SECTION VI ATTACHMENT 7 Amendment 53                                    COLUMBIA GENERATING STATION November 1998                                   FINAL SAFETY ANALYSIS REPORT

Table 17.1-1 General Electric Quality Assurance Evolutionary Process QA Related NED Quality                Intent of    Intent of                                                     Regulatory Objectives - Safe and      Proposed    10 CFR 50                                AEC                   Guide and Date of         Reliable Systems and       AEC QA      Appendix B   10 CFR 50    ANSI N45.2   Regulatory   ASME B&P     ANSI Effectiveness   Components                  Criteria   (proposed)   Appendix B                Guide 1.28     Code     Standards 8/20/68         Blue Book COLUMBIA GENERATING STATION 10/1/69         Green Book Rev. 0             X 5/1/70          Green Book Rev. 1             X 9/15/71         Green Book Rev. 2                          X 17.1-47 FINAL SAFETY ANALYSIS REPORT 6/1/72          Green Book Rev. 3                                       X            X 3/1/73          Green Book Rev. 4                                       X            X (NEDO-11209) 5/7/74          Green Book Rev. 5                                       X            X            X           X           X (NEDO-11209-01) 12/12/75        Green Book                                              X            X            X           X           X (NEDO-11209-02) 11/76           Green Book                                              X            X            X           X           X (NEDO-11209-03A)
Amendment 53 3/31/78         Green Book                                              X            X            X           X           X (NEDO-11209-04A) 10/80           Green Book                                              X            X            X           X           X November 1998 (NEDO-11209-04A)

Amendment 53 November 1998 Managing Director Deputy Managing Director Licensing                Operations                        Chief                  Support and                                                   Financial               Services Director Assurance                                                 Officer                Director Director Power                   Program                       Technology Generation                Director                        Director Director Energy Northwest Organization Chart Columbia Generating Station Final Safety Analysis Report Draw. No. 960222.79       Rev. Figure 17.1-1 Form No. 960690

Amendment 53 November 1998 Director Operations Director                           Program Power Generation                         Director Manager Technical           Regulatory Manager Specialist           Programs Construction Q.A.
Project Quality Assurance                             Licensing Manager                                   Manager Program Control Business Manager Manager Administration Manager Plant Manager        Test and Startup                         Engineering        Construction Manager                              Manager             Manager Engineer             C.M.
Burns & Roe            Bechtel Energy Northwest CGS Organization Chart Columbia Generating Station Final Safety Analysis Report Draw. No. 960222.80         Rev. Figure 17.1-2 Form No. 960690

Amendment 53 November 1998 Director Licensing and Assurance Manager                          Manager                                     Manager Nuclear Safety                   Construction                                   Audits and                       Quality Assurance Regulatory Programs Project                                     Procurement Quality Assurance Manager                                     Quality Assurance Manager CGS Project Management Organization Chart Columbia Generating Station Final Safety Analysis Report Draw. No. 960222.81          Rev.       Figure 17.1-3 Form No. 960690

Amendment 53 November 1998 Project Director/CGS Corporate Quality Assurance Emp. Relations                               Directorate Staff Project Engr. Mgr.          Engr. Mgr.          Manager Site                                        Quality Assurance Engr. Mgr. Site Woodbury                 Richland              Support                                            Richland/Site Engineer Quality Assurance Woodbury Engr.
Asst. Manager                   Proj. Administrator Design Drafting Legend:
admin. reporting chain functional reporting chain Burns and Roe, Inc. CGS Organization Chart Columbia Generating Station Final Safety Analysis Report Draw. No. 960222.82              Rev.         Figure  17.1-4 Form No. 960690

Amendment 53 November 1998 Bechtel CGS Project Manager Site                    Project                     Cost and                Quality Construction              Engineering                   Schedule              Assurance Quality Control Legend:
coordination Bechtel CGS Organization Chart Columbia Generating Station Final Safety Analysis Report Draw. No. 960222.83     Rev.      Figure 17.1-5 Form No. 960690

COLUMBIA GENERATING STATION                         Amendment 54 FINAL SAFETY ANALYSIS REPORT                        April 2000 17.2    QUALITY ASSURANCE DURING THE OPERATIONS PHASE The CGS program for quality assurance during the operations phase is provided separately in the Energy Northwest Operational Quality Assurance Program Description (EN-QA-004).
LDCN-99-000                               17.2-1

COLUMBIA GENERATING STATION                                Amendment 63 FINAL SAFETY ANALYSIS REPORT                               December 2015 Chapter 13 CONDUCT OF OPERATIONS TABLE OF CONTENTS Section                                                                                           Page 13.1 ORGANIZATION STRUCTURE ..................................................... 13.1-1 13.1.1 MANAGEMENT AND TECHNICAL SUPPORT ORGANIZATION ...... 13.1-1 13.1.1.1 Technical Support for Operations ................................................. 13.1-1 13.1.1.2 Organizational Arrangement ....................................................... 13.1-2 13.1.1.3 Qualifications ......................................................................... 13.1-3 13.1.2 OPERATING ORGANIZATION.................................................... 13.1-3 13.1.2.1 Plant Organization ................................................................... 13.1-3 13.1.2.2 Plant Personnel Responsibilities and Authorities ............................... 13.1-3 13.1.2.2.1 Plant Management ................................................................. 13.1-3 13.1.2.2.2 Operations Supervision ........................................................... 13.1-4 13.1.2.2.3 Operating Shift Crew Supervision .............................................. 13.1-5 13.1.2.2.4 Shift Technical Advisor........................................................... 13.1-6 13.1.2.2.5 Licensed Operators ................................................................ 13.1-6 13.1.2.2.6 Nonlicensed Operators ............................................................ 13.1-6 13.1.2.2.7 Engineering Management ........................................................ 13.1-7 13.1.2.2.7.1 System Engineering Manager ................................................. 13.1-7 13.1.2.2.7.2 Design Engineering Manager ................................................. 13.1-8 13.1.2.2.7.3 Reactor/Fuels Manager ........................................................ 13.1-8 13.1.2.2.7.4 Technical Services Manager .................................................. 13.1-9 13.1.2.2.7.5 Plant Support Engineering Manager ......................................... 13.1-9 13.1.2.2.7.6 DELETED ....................................................................... 13.1-9 13.1.2.2.7.7 Equipment Reliability and Planning Supervisor ........................... 13.1-9 13.1.2.2.8 Nuclear Engineering Supervision ............................................... 13.1-9 13.1.2.2.9 Radiological Services Supervision .............................................. 13.1-9 13.1.2.2.10 Chemistry Supervision .......................................................... 13.1-10 13.1.2.2.11 Maintenance Supervision ....................................................... 13.1-10 13.1.2.2.12 Planning, Scheduling and Outage Supervision .............................. 13.1-10 13.1.2.2.13 Quality Supervision .............................................................. 13.1-10 13.1.2.3 Operating Shift Crews ............................................................... 13.1-11 13.1.2.3.1 Shift Crew Composition .......................................................... 13.1-11 13.1.2.3.2 Shift Responsibility for Radiation Protection ................................. 13.1-11 13.1.2.3.3 Shift Maintenance Support ....................................................... 13.1-11 13.1.2.3.4 Shift Fire Brigade .................................................................. 13.1-12 13.1.2.3.5 Shift Chemistry Support .......................................................... 13.1-12 LDCN-14-019, 14-037, 13-067                      13-i

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 Chapter 13 CONDUCT OF OPERATIONS TABLE OF CONTENTS (Continued)
Section                                                                                            Page 13.1.3 QUALIFICATIONS OF NUCLEAR PLANT PERSONNEL .................. 13.1-12 13.1.3.1 Plant Management ................................................................... 13.1-12 13.1.3.2 Operations Department .............................................................. 13.1-13 13.1.3.2.1 Operations Manager ............................................................... 13.1-13 13.1.3.2.2 Shift Manager ...................................................................... 13.1-13 13.1.3.2.3 Control Room Supervisor ........................................................ 13.1-13 13.1.3.2.4 Shift Technical Advisor........................................................... 13.1-14 13.1.3.2.5 Shift Support Supervisor ......................................................... 13.1-14 13.1.3.2.6 Reactor Operator ................................................................... 13.1-14 13.1.3.2.7 Equipment Operator ............................................................... 13.1-14 13.1.3.3 Engineering............................................................................ 13.1-14 13.1.3.3.1 Vice President Engineering, Assistant Vice President Engineering, System Engineering Manager, Design Engineering Manager, Reactor/Fuels Manager, Technical Services Manager, and Plant Support Engineering Manager 13.1-14 13.1.3.3.2 Engineering Supervisors .......................................................... 13.1-15 13.1.3.3.3 Fire Protection Engineer ......................................................... 13.1-15 13.1.3.4 Maintenance ........................................................................... 13.1-15 13.1.3.4.1 Maintenance Managers ........................................................... 13.1-15 13.1.3.4.2 Maintenance Supervisors ......................................................... 13.1-15 13.1.3.5 Chemsitry and Radiological Services ............................................. 13.1-16 13.1.3.5.1 Chemistry and Radiological Safety Manager ................................ 13.1-16 13.1.3.5.2 Radiological Services Manager ................................................. 13.1-16 13.1.3.5.3 Radiation Protection Manager ................................................... 13.1-16 13.1.3.5.4 Radiological Services Supervisors .............................................. 13.1-16 13.1.3.5.5 Chemistry Supervisors ............................................................ 13.1-17 13.1.3.6 DELETED ............................................................................ 13.1-17 13.1.3.7 Quality ................................................................................. 13.1-17 13.2 TRAINING ................................................................................. 13.2-1 13.2.1 PLANT STAFF TRAINING PROGRAM ......................................... 13.2-1 13.2.2 INITIAL AND CONTINUING TRAINING ...................................... 13.2-2 13.2.2.1 Licensed Operators .................................................................. 13.2-2 13.2.2.1.1 Initial Training ..................................................................... 13.2-2 LDCN-14-037, 13-067, 13-061, 15-008                 13-ii

COLUMBIA GENERATING STATION                                  Amendment 62 FINAL SAFETY ANALYSIS REPORT                                 December 2013 Chapter 13 CONDUCT OF OPERATIONS TABLE OF CONTENTS (Continued)
Section                                                                                           Page 13.2.2.1.2 Continuing Training ............................................................... 13.2-3 13.2.2.2 Nonlicensed Operator Training .................................................... 13.2-3 13.2.2.2.1 Initial Training ..................................................................... 13.2-3 13.2.2.2.2 Continuing Training Program ................................................... 13.2-4 13.2.2.3 Shift Technical Advisor Training .................................................. 13.2-4 13.2.2.3.1 Initial Training ..................................................................... 13.2-4 13.2.2.3.2 Continuing Training ............................................................... 13.2-4 13.2.2.4 Other Plant Personnel (Maintenance, Health Physics, Chemistry) .......... 13.2-5 13.2.2.4.1 Initial Training ..................................................................... 13.2-5 13.2.2.4.2 Continuing Training ............................................................... 13.2-5 13.2.2.5 Fire Brigade ........................................................................... 13.2-5 13.2.2.5.1 Initial and Continuing Training ................................................. 13.2-5 13.2.2.5.2 Offsite Fire Department .......................................................... 13.2-6 13.2.3 TRAINING PROGRAM EFFECTIVENESS...................................... 13.2-7 13.2.4 PLANT TRAINING RECORDS .................................................... 13.2-7 13.2.5 OTHER TRAINING DOCUMENTS ............................................... 13.2-7 13.3 EMERGENCY PLANNING ............................................................ 13.3-1 13.4 REVIEW AND AUDIT .................................................................. 13.4-1 13.4.1 ONSITE REVIEW ..................................................................... 13.4-1 13.4.2 INDEPENDENT REVIEW ........................................................... 13.4-1 13.4.3 AUDIT PROGRAM ................................................................... 13.4-2 13.5 PLANT PROCEDURES ................................................................. 13.5-1 13.5.1 ADMINISTRATIVE PROCEDURES .............................................. 13.5-1 13.5.1.1 Conformance With Regulatory Guide 1.33, Revision 2 ....................... 13.5-1 13.5.1.2 Preparation of Procedures .......................................................... 13.5-1 13.5.1.3 Procedures ............................................................................. 13.5-1 13.5.2 OPERATING AND MAINTENANCE PROCEDURES ........................ 13.5-2 13.5.2.1 Control Room Operating Procedures ............................................. 13.5-2 13.5.2.2 Other Procedures ..................................................................... 13.5-3 13.6 INDUSTRIAL SECURITY ............................................................. 13.6-1 13-iii

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 Chapter 13 CONDUCT OF OPERATIONS LIST OF TABLES Number                                 Title                                               Page 13.1-1      Minimum Shift Crew Composition ............................................... 13.1-19 LDCN-10-002                                13-iv

COLUMBIA GENERATING STATION  Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 13 CONDUCT OF OPERATIONS LIST OF FIGURES Number                                 Title 13.1-1      Energy Northwest Organization 13.1-2      Nuclear Generation Organization 13.1-3      Plant General Manager Organization 13.1-4      Operational Support Organization 13.1-5      (Deleted) 13.1-6      Vice President Engineering Organization 13.1-7      Quality Organization 13.1-8      (Deleted) 13.1-9      Operations Organization 13.1-10     Operations Crew 13.1-11     Radiological Services Organization 13.1-12     Chemistry Organization 13.1-13     Plant Maintenance Organization LDCN-14-019                                13-v

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 Chapter 13 CONDUCT OF OPERATIONS 13.1     ORGANIZATION STRUCTURE The organizational structure of Energy Northwest and the line of responsibility for the operation of Columbia Generating Station (CGS) is in accordance with established administrative and quality standards that apply to this operation. The applicable organization charts are shown in Figures 13.1-1 through 13.1-13.
13.1.1       MANAGEMENT AND TECHNICAL SUPPORT ORGANIZATION Energy Northwest is a municipal corporation and a joint operating agency of the State of Washington. The management and control of Energy Northwest is vested in the Executive Board.
The Executive Board consists of five members of the Energy Northwest Board of Directors and six outside directors. Three outside directors are selected by the Board of Directors, and three directors are appointed by the Governor of the State of Washington.
The full Board of Directors has members representing each of Energy Northwests member utilities, and has the authority to select the inside members of the Executive Board and to terminate existing projects or authorize new projects.
Certain responsibilities for day-to-day management of Energy Northwest have been delegated to the Chief Executive Officer (the chief administrative officer).
The staff of Energy Northwest includes senior management level positions, which are responsible to the Chief Executive Officer for performance of specialized work by their respective groups. See Figure 13.1-1 for an organization chart. However, as specified in Technical Specifications, Section 5.2.1, the Chief Executive Officer retains corporate responsibility for overall plant nuclear safety.
13.1.1.1        Technical Support for Operations Technical support for the nuclear organization is the responsibility of the Chief Nuclear Officer, Plant General Manager, Vice President, Engineering, and Vice President, Operations.
The Plant General Manager is responsible for the safe, reliable, and efficient operation and maintenance of CGS and for providing major services which support plant operation.
LDCN-14-046                                      13.1-1

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 Reporting to the Chief Nuclear Officer includes the Vice President, Operations, Vice President, Engineering, and the Quality Manager. The Plant General Manager reports to the Vice President, Operations.
Reporting to the Chief Nuclear Officer are departments that provide support to CGS in the areas of Operations, Engineering, and Quality (see Figure 13.1-2).
Reporting to the Vice President, Engineering are departments which provide technical support in the areas of reactor fuels and engineering.
Reporting to the Vice President, Operations, are the Plant General Manager, the Emergency Services Manager, and the Training Manager. Security reports to the Emergency Services Manager. (see Figure 13.1-4).
The Quality Managers responsibilities are described in the Energy Northwest Operational Quality Assurance Program Description (OQAPD), EN-QA-004. An organization chart is provided in Figure 13.1-7.
The Vice President, Engineering is responsible for design control of all authorized plant modifications, technical expertise in the fundamental engineering disciplines such as mechanical, electrical, civil, chemical, fuels, as well as specialty areas such as materials, welding, and inservice inspection engineering. In addition, the Vice President, Engineering is responsible for providing technical support in the area of system engineering. An organization chart for Engineering is shown in Figure 13.1-6.
13.1.1.2         Organizational Arrangement Figures 13.1-1 through 13.1-7 provide the current corporate structure as applicable to CGS support organizations. The number of personnel to be assigned to each of the working level organizations will be determined based on workload and need for pertinent expertise. If the need arises, qualified outside contractors will be used to support the Energy Northwest staff.
LDCN-14-019, 14-046, 15-008                   13.1-2

COLUMBIA GENERATING STATION                            Amendment 62 FINAL SAFETY ANALYSIS REPORT                           December 2013 13.1.1.3       Qualifications Qualification requirements for key technical support personnel who fulfill the responsibilities identified in Section 13.1.1.1 shall meet the criteria of Regulatory Guide 1.8, Revision 1, 1977 (see the OQAPD). The personnel qualification and training programs are under continuing review and modification to reflect the changes following the TMI accident. The Vice President Engineering meets the definition and qualifications of Engineer in Charge.
Any Vice President or Manager listed in Section 13.1.1.1 may authorize deviations from the qualification requirements for subordinate positions when, in their judgment, the combined education, experience, and managerial competency of a particular individual are sufficient to ensure adequate performance of assigned responsibilities. Such exceptions will be documented in writing and will not be used as a means to degrade the overall qualifications of the support staff. Deviations are not authorized for those positions whose qualifications are described in the Technical Specifications and the OQAPD.
13.1.2      OPERATING ORGANIZATION 13.1.2.1       Plant Organization This section describes the structure, functions, and responsibilities of the onsite organization established to operate and maintain CGS. Figures 13.1-9 through 13.1-13 show the plant organizations that directly operate and maintain CGS. The principal departments that function directly under the supervision of the Plant General Manager are: Operations, Maintenance, Radiological Services, and Chemistry (see Figure 13.1-3).
The Security Force Lieutenant is responsible to the Plant General Manager for day-to-day operation of the Plant Security Program and receives functional supervision from Operations Support management.
Position titles, NRC licenses required, and lines of functional reporting, as well as direct lines of communications, are indicated on the organization charts.
13.1.2.2       Plant Personnel Responsibilities and Authorities 13.1.2.2.1       Plant Management The Plant General Manager has direct responsibility and authority for all plant activities. The Plant General Manager reports directly to the Vice President, Operations.
The Plant General Manager has the responsibility for management of the following plant departments: Operations, Chemistry, Radiological Services, Planning, Scheduling and Outage, and Maintenance.
LDCN-12-004                                   13.1-3

COLUMBIA GENERATING STATION                            Amendment 62 FINAL SAFETY ANALYSIS REPORT                           December 2013 A Security Force Lieutenant exercises supervision and authority over the onsite security personnel. The Security Force Lieutenant reports to the Plant General Manager or the designated representative on day shifts and to the Shift Manager during other than normal working hours (i.e., backshifts, weekends, and holidays).
In the event of incapacitation of key plant personnel or unexpected contingencies of a temporary nature, the line of succession of authority and responsibility for all plant activities is as follows:
: a. Plant General Manager,
: b. Operations Manager,
: c. One of the Assistant Operations Managers (see below),
: d. Duty Shift Manager.
13.1.2.2.2      Operations Supervision Operations is under the direction of the Operations Manager. The Operations Manager is responsible for overall plant operation. The Operations Manager directs and manages the activities of operations to ensure safe plant operation and control of plant systems in compliance with licensing documents.
The Operations Manager is responsible for being cognizant of and complying with the OQAPD.
The Operations Manager is responsible for the day-to-day routine as well as the abnormal or emergency operating situations that may arise. The Operations Manager is responsible to see that all operations are carried out in a safe, efficient manner and that the plant is operated in strict conformance to the Operating License, Technical Specifications, and in accordance with approved written procedures. Additionally, the Operations Manager is responsible for operating personnel schedules, development, and periodic review of plant operating procedures and instructions, and the preparation of operating records and reports.
The Operations Crew, Operations Support, Operations Work Control and Operations Training Managers (hereinafter referred to collectively as Assistant Operations Managers (AOMS))
support and assist the Operations Manager in the performance of these duties. The Operations Crew Manager is responsible to the Operations Manager for the immediate supervision of the Operations staff that supports work team and outage activities, and as such, he receives direction from the Operations Manager for the day-to-day routine and supervises implementation. The Operations Support Manager is responsible to the Operations Manager for the immediate supervision of the Operations staff that supplies miscellaneous support to the Operations Department.
LDCN-13-040                                     13.1-4

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 The AOMs may be required to maintain a current Senior Reactor Operator (SRO) license.
During periods of transition such as promotion, the individual with a current SRO, either the Operations Manager or one of the AOM will have the responsibility for immediate supervision of the Operations staff. In either case, the individual with the SRO may only be relieved by another individual possessing a current SRO. The Operations Manager will designate one of the assistants to assume total responsibility for the Operations Managers duties (as described in this section) during periods when the Operations Manager is temporarily absent from the plant. See Figure 13.1-9 for an organization chart of the Operations Department.
The plant Fire Marshall assists the Operations Manager in the implementation of the Fire Protection Program. Responsibilities include ensuring that the fire protection systems and components are maintained and that the Fire Brigade is adequately trained and staffed. More detailed information is contained in Section 13.2.2.5.2.
13.1.2.2.3      Operating Shift Crew Supervision Within the Operations Department are a minimum of five shift crews during normal operations. In some situations, such as refueling outages, these may be reduced to four shift crews. Plant management and technical support will be present or on call at all times to provide advice to the shift personnel.
The Shift Manager holds an SRO license and is directly responsible to the Operations Manager (see Figure 13.1-10 for typical Operations Crew organization chart). The Shift Manager is in charge of all plant operations on shift and is directly in charge of and responsible for the shift crew assigned to his specific shift. The Shift Manager has the authority to institute immediate action in any given situation to shut the plant down, or eliminate difficulties to preclude violation of the Operating License or Technical Specifications, or to avert possible injury or undue radiation exposure of personnel. Additionally, the Shift Manager may at times direct the activities of other personnel during tasks such as backshift maintenance, radiation protection, chemistry control, and security implementation. The Shift Manager also keeps plant management appraised of situations that may affect plant safety and/or constitute a hazard to the general public. During other than normal working hours, the Shift Manager assumes responsibility for all plant operations in the absence of senior plant management personnel.
The Control Room Supervisor holds an SRO license and assists the Shift Manager in the performance of duties and assumes those duties during periods when the Shift Manager is unavailable. The Control Room Supervisor is responsible for supervising the activities of the Control Room Reactor Operators and other assigned personnel (i.e., equipment operators and maintenance support personnel) required to operate the plant safely and efficiently. The Control Room Supervisor is directly responsible to the Shift Manager.
LDCN-14-019                                    13.1-5

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 If stationed, the Shift Support Supervisor assists the Shift Manager in the performance of his duties. The Shift Support Supervisor is responsible for the supervision and direction of personnel assigned to perform balance-of-plant (BOP) operating functions such as operations of makeup water treatment system, radwaste processing systems, and other plant support systems.
The individual is responsible for performing administrative duties as assigned.
All core alterations are observed and directly supervised by either a licensed SRO, or licensed SRO limited to fuel handling, who has no concurrent responsibilities during the performance of the core alterations.
13.1.2.2.4     Shift Technical Advisor A Shift Technical Advisor (STA) qualified individual provides engineering expertise on shift pursuant to safe and efficient operation of the plant. The STA function may be staffed by a dedicated individual (licensed or non-licensed), or by an individual filling a dual role as the Control Room Supervisor, Shift Manager or Shift Support Supervisor. The STA qualified individual monitors reactor core operations, and core management and reactivity controls. The STA normally reports to the Shift Manager.
13.1.2.2.5      Licensed Operators In addition to the licensed supervisors listed above, there are a minimum of two reactor operators on each shift. The reactor operator (RO) holds a reactor operator or senior reactor operator license and is responsible to the Control Room Supervisor for the safe and efficient operation of the plant from the main control room. The RO follows approved procedures in performing work and is responsible for taking the immediate action required to maintain or bring the plant to a safe condition during abnormal and/or emergency conditions. However, if a particular situation is not covered by a procedure, the individual may seek advice from the Control Room Supervisor, or if the situation is critical, may use his or her own judgment to prevent damage to equipment, injury to personnel, or undue radiation exposure of plant personnel and the general public. The RO directs and supports the activities of other operators in the performance of their duties and works cooperatively with all plant service groups that interface with plant operation.
13.1.2.2.6      Nonlicensed Operators The equipment operators (EO) are responsible to the Control Room Supervisor or Shift Support Supervisor for assisting in the plant operation and performing work assignments from local control stations and all other defined areas outside of the central control room. The EO follows approved procedures in doing work and does not deviate from those procedures except as authorized. The EO performs assigned routine inspections and manipulates equipment without close supervision. The EO also performs special assignments as directed.
LDCN-10-002                                    13.1-6

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 13.1.2.2.7        Engineering Management Reporting to the Vice President, Engineering is the Assistant Vice President Engineering, the System Engineering Manager, the Technical Services Manager, the Design Engineering Manager, the Plant Support Engineering Manager, and the Reactor Fuels Manager.
They are responsible for developing and implementing plant programs and procedures which provide proper management control in the above areas and thus ensure compliance with the conditions of the operating license and proper plant safety. They interface with other support organizations to support plant operations.
The engineering organizations are responsible for being cognizant of and complying with the Operational Quality Assurance Program Description.
13.1.2.2.7.1 System Engineering Manager. The System Engineering Manager is responsible for long-term management of and the health and reliability of systems and components, overall direction of the system engineering program in support of plant operation, maintenance, and chemistry, and developing long range plans for system improvement and performance in the areas of NSSS systems, control/electrical systems, and BOP systems.
The System Engineering Manager is responsible for the development, implementation, and execution of programs to monitor system performance, to conduct inspections, and to perform specialized testing. The objective is to identify potential component degradation, minimize threats to successful operation of systems and the plant, and to identify opportunities for improvement.
The System Engineering Manager is the primary interface with the Design Engineering Manager, Plant Support Engineering Manager, and Technical Services Manager in support of maintaining plant compliance with design and licensing requirements.
The System Engineering Manager is responsible for implementing performance monitoring of plant systems and critical plant programmatic processes. This includes providing recommendations to plant management for implementation of new program requirements, performing periodic assessments of existing programs, and recommending component or system improvements. The System Engineering Manager is responsible for daily plant support, responding to emergent issues, operability assessments, and providing troubleshooting expertise to operations and maintenance.
Reporting to the System Engineering Manager are Equipment Reliability and Planning Supervisor, and the System Engineering Supervisors for nuclear steam supply systems (NSSS),
BOP systems, and instrument and control and electrical systems. System Engineering Supervisors direct the activities of the System Engineering staff in support of plant operation in LDCN-14-019, 14-037                           13.1-7

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 the functional areas of mechanical engineering, instrumentation and control engineering, and electrical engineering. Activities include initiating engineering design changes, making recommendations for improved operation, and providing operating and maintenance support for instrumentation and control systems, mechanical systems, electrical systems, plant water systems, and waste handling systems.
13.1.2.2.7.2 Design Engineering Manager. The Design Engineering Manager is responsible to assist System Engineering for daily plant support, responding to emerging issues, and operability assessments. The Design Engineering Manager is responsible for maintenance of the plant design basis, performance of plant design changes, and design and drafting. This includes non-modification design related activities.
Reporting to the Design Engineering Manager are the Mechanical Design Supervisor, the Civil/Stress Design Supervisor, the Electrical Design Supervisor, and the Instrumentation &
Control Design Supervisor.
13.1.2.2.7.3 Reactor Fuels Manager. The Reactor Fuels Manager is responsible for fuel design, overall management of the reactor core, and monitoring of core parameters.
The Reactor Fuels Manager is responsible for providing technical support to Operations in management of refueling floor activities, support to Maintenance in resolving refueling equipment problems, providing technical resources for resolution of vessel hardware problems and concerns with interfacing systems which influence or monitor core reactivity, for maintaining involvement in applicable industry initiatives affecting core reactivity issues and new developments in core operation, providing recommendations to plant management on operating strategies in support of normal and off-normal operating situations, and planned shutdown and startup activities.
The Reactor Fuels Manager ensures sound fuel design philosophy is followed, fuel designs provide no unreasonable challenges to safe plant operation, and probabilistic safety assessments (PSA) are performed for CGS.
Reporting to the Reactor Fuels Manager are the Fuel Design/Reactor Engineering Supervisor, and the Safety Analysis/PSA Supervisor.
The Fuel Design/Reactor Engineering Supervisor and staff are responsible for performing periodic core physics evaluations to monitor the operation, burnup, and thermal/hydraulic performance of the reactor core. They provide and maintain plant operating curves and reactivity data for use by shift operation personnel and are responsible for the onsite accountability of nuclear fuel and special nuclear materials. The Fuel Design/Reactor LDCN-14-019                                    13.1-8

COLUMBIA GENERATING STATION                          Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 Engineering Supervisor and staff are responsible for core design, fuel planning, licensing support (e.g., COLR, accident/transient analysis), and analytical work necessary to support cycle operation (e.g., control rod pattern recommendations).
The Safety Analysis/PSA Supervisor and staff provide probabilistic safety assessments for CGS. They provide analytical support for radiation dose analysis, shielding, equipment qualification, ODCM, emergency procedures and primary and secondary containment analyses.
13.1.2.2.7.4 Technical Services Manager is responsible for plant, code, component programs.
Reporting to the Technical Services Manager are Plant Programs Supervisor, Code Programs Supervisor, and Plant Components Supervisor. The Technical Services personnel are responsible for Equipment Qualification (EQ), Fire Protection (FP), In Service Test (IST),
Thermal Performance (TP), ASME Section XI, ISI, BWRVIP, welding, Appendix J Local Leak Rate Testing (LLRT), pump, valve (AOVs, MOVs, and reliefs), large motor, circuit breaker, relay, and Component Condition Monitoring programs, including vibration analysis, oil analysis, and thermography.
13.1.2.2.7.5 Plant Support Engineering Manager is responsible for supporting the System Engineering Manager and the plant in responding to emergent issues, operability assessments, providing troubleshooting expertise to operations and maintenance and performing engineering needed for special procurement. Reporting to the Plant Support Engineering Manager are the engineering fix-it-now (EFIN) Supervisor, the Minor Modifications Supervisor and the Procurement Engineering Supervisor.
13.1.2.2.7.6 DELETED.
13.1.2.2.7.7 Equipment Reliability and Planning Supervisor is responsible for interface with System and Design Engineering managers and the Asset Management department for Equipment Reliability Initiatives and planning to support the long range plan. The Equipment Reliability and Planning Supervisor is also responsible for Maintenance Rule (MRule) implementation.
13.1.2.2.8        Nuclear Engineering Supervision See Section 13.1.2.2.7.3.
13.1.2.2.9        Radiological Services Supervision See Section 12.5.1 for a description of duties, responsibilities, and reporting relationships. See Figure 13.1-11 for an organization chart.
LDCN-14-019, 14-037                            13.1-9

COLUMBIA GENERATING STATION                          Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 13.1.2.2.10       Chemistry Supervision Chemistry is under the direction of the Chemistry and Radiological Safety Manager, who reports to the Plant General Manager. The group provides plant oversight for system chemistry optimization and control, gaseous, and liquid effluent releases, radwaste processing and chemical control, the Offsite Dose Calculation Manual, the Radiological Environmental Monitoring Program (REMP), and Radiological Effluent Report. See Figure 13.1-12 for an organization chart.
13.1.2.2.11       Maintenance Supervision Maintenance is under the direction of the Maintenance Manager. The Maintenance Manager is responsible for the Maintenance Program and for the development and implementation of maintenance processes and procedures which will ensure the safe and reliable operation of plant equipment. The Maintenance Manager is responsible for primary component level troubleshooting. The Maintenance Manager reports to the Plant General Manager. The organization is shown in Figure 13.1-13.
The Maintenance Manager, with the assistance of direct managerial reports, manages the following activities: Reactor and Major Maintenance, Maintenance Services, FIN Component Group, Mechanical Component Group, I & C Component Group, Electrical Component Group, and other teams that are formed to address specific maintenance or business needs.
Shops and/or teams may be combined as long as supervisory qualifications are maintained as described in Section 13.1.3.4.
All plant modifications are accomplished through this department either directly or through the actions of the Site Support Services contractor. Engineering, Training, and Support Services, as discussed in Section 13.1.1.1, provide support for this department. Other support is provided when needed in the form of vendor representatives for technical guidance on maintenance of major components of the plant.
Maintenance Supervisors are responsible for the day-to-day implementation of the Maintenance Program. They are responsible for maintaining plant electrical, instrumentation, and mechanical systems through preventive and corrective maintenance and surveillance programs.
13.1.2.2.12       Planning, Scheduling and Outage Supervision This organization is responsible for managing the work process and ensuring work schedule consistency. It is also responsible for the development and oversight of outage preparation and implementation and coordination of outage work.
13.1.2.2.13       Quality Supervision A description of duties and responsibilities for the Quality organization is contained in the OQAPD.
LDCN-13-061, 15-008                           13.1-10

COLUMBIA GENERATING STATION                            Amendment 61 FINAL SAFETY ANALYSIS REPORT                           December 2011 13.1.2.3       Operating Shift Crews 13.1.2.3.1      Shift Crew Composition Shift coverage is provided by using a rotating shift schedule depending on operating needs.
The schedules are based on a nominal 40-hr work week and shifts are normally of 8 or 12 hr duration (excluding shift turnover time).
During normal operations, a minimum of five crews provide 24 hr/day, 7 day/week coverage.
Table 13.1-1, as well as the Technical Specifications and the Emergency Plan, identify the minimum number and type of licensed and unlicensed personnel required to be onsite.
For those operations that involve core alterations, direct supervision of all fuel movements is provided by an individual holding an SRO license. This person has no other concurrent responsibilities during this assignment.
It is CGSs policy to maintain an adequate number of personnel in the Shift Manager, Control Room Supervisor, Shift Support Supervisor, STA (if required), Control Room Reactor Operator, and Equipment Operator positions such that the use of overtime is not routinely required to compensate for inadequate staffing.
13.1.2.3.2      Shift Responsibility for Radiation Protection A minimum of one Health Physics Technician is assigned to each operating shift to provide radiological surveillance/control (see Table 13.1-1).
All shift personnel are instructed in the fundamentals of health physics such as implementing radiation protection procedures, radiation and contamination surveys, use of protective barriers and signs, use of protective clothing and breathing apparatus, radiation monitoring, and accumulated dose.
Shift personnel are responsible for immediately informing the on-duty Shift Manager if conditions develop that exceed or are likely to exceed preestablished radiation levels or exposure limits or if they believe that unsafe or hazardous conditions exist. The Shift Manager will evaluate the situation and if a radiological condition exists that warrants attention and investigation, the appropriate Health Physics personnel will be called for assistance.
13.1.2.3.3      Shift Maintenance Support Craftsmen and technicians, as required, are available to provide maintenance support and surveillance testing in the areas of instrumentation and controls and mechanical and electrical equipment.
LDCN-10-002                                    13.1-11

COLUMBIA GENERATING STATION                            Amendment 62 FINAL SAFETY ANALYSIS REPORT                           December 2013 13.1.2.3.4      Shift Fire Brigade A Shift Fire Brigade, consisting of a minimum of five members of the nominal shift complement, shall have advanced fire training and be equipped for fire fighting. This select group on each operating shift will have primary response capabilities and will respond to emergencies involving fire and/or emergencies where life threatening danger exists.
The brigade shall not include the minimum shift crew complement required to safely shut down the unit. At a minimum the brigade leader and two brigade members shall have sufficient knowledge of plant fire safe shutdown systems. The balance of the fire brigade shall be composed of Fire Brigade trained support personnel. See Section 13.2.2.5 for the qualification requirements for fire brigade members.
13.1.2.3.5      Shift Chemistry Support At least one qualified chemistry technician is assigned to each operating shift for the purpose of providing chemistry support in the area of chemical surveillances while the plant is in Modes 1, 2, or 3.
13.1.3      QUALIFICATIONS OF NUCLEAR PLANT PERSONNEL The minimum educational and experience qualifications for the onsite plant personnel are based on Regulatory Guide 1.8, Revision 1-R, 1977. If an individual who does not meet the minimum qualification criteria is placed in a discipline, it will be specifically pointed out and justification or explanation provided. See Section 13.1.1.3. Personnel qualification and training programs are under continual review and modification to reflect the changes following TMI. The minimum qualification requirements identified in Section 13.1.3.1 will be revised accordingly. The licensed ROs and SROs meet or exceed the minimum qualifications of the supplemental requirements specified in Sections A and C of Enclosure 1 of the March 28, 1980, NRC letter to all licensees, as modified by NUREG-0737, November 1980, Clarification of TMI Action Plan Requirements, Enclosure 1, Section 1.A.2.1, Immediate Upgrading of Reactor Operator and Senior Reactor Operator Training and Qualifications.
13.1.3.1       Plant Management The Plant General Manager shall have 10 years of responsible power plant experience of which a minimum of 3 years shall be nuclear power plant experience. A maximum of 4 years of the remaining 7 years of experience may be fulfilled by academic training on a one-for-one time basis. This academic training shall be in an engineering or scientific field generally associated with power production. The Plant General Manager shall have acquired the experience and training normally required for examination by the NRC for an SRO license, whether or not the LDCN-13-040                                  13.1-12

COLUMBIA GENERATING STATION                          Amendment 62 FINAL SAFETY ANALYSIS REPORT                        December 2013 examination is taken. The Plant General Manager should have a recognized baccalaureate or higher degree in an engineering or scientific field generally associated with power production.
13.1.3.2       Operations Department 13.1.3.2.1      Operations Manager The Operations Manager shall have a minimum of 8 years of responsible power plant experience of which a minimum of 3 years shall be nuclear power plant experience.
A maximum of 2 years of the remaining 5 years of power plant experience may be fulfilled by satisfactory completion of academic or related technical training on a one-for-one time basis.
The Operations Crew Manager shall have qualifications similar to those of the Operations Manager. The Operations Manager or Operations Crew Manager shall hold an SRO license.
13.1.3.2.2      Shift Manager The Shift Manager shall have a minimum of a high school diploma or equivalent and 4 years of responsible power plant experience of which a minimum of 1 year shall be nuclear power plant experience. At least 6 months of nuclear plant experience will be at CGS. A maximum of 2 years of power plant experience may be fulfilled by academic or related technical training on a one-for-one time basis. The Shift Manager shall hold an SRO license. For NRC license eligibility guidelines (experience, training, and education) for an SRO license, see NUREG-1021, section ES-202.
13.1.3.2.3      Control Room Supervisor The Control Room Supervisor shall have a minimum of a high school diploma or equivalent and 4 years of responsible power plant experience, of which a minimum of 1 year shall be nuclear power plant experience. At least 6 months of nuclear plant experience will be at CGS.
A maximum of 2 years of power plant experience may be fulfilled by academic or related technical training on a one-for-one time basis. The Control Room Supervisor shall hold an SRO license. For NRC license eligibility guidelines (experience, training, and education) for an SRO license, see NUREG-1021, section ES-202.
LDCN-13-040                                    13.1-13

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 13.1.3.2.4        Shift Technical Advisor The STA possesses a bachelors degree in engineering or science with sufficient courses to provide a sound background for understanding the design and operation of a BWR power plant. The STA shall have a minimum of 2 years of power plant experience with at least 6 months of nuclear plant experience at CGS.
13.1.3.2.5        Shift Support Supervisor The Shift Support Supervisor shall have a high school diploma or equivalent. The individual shall have 4 years of power plant experience of which 1 year shall be nuclear power plant experience. This position does not require an RO license.
13.1.3.2.6        Reactor Operator The RO shall have a minimum of a high school diploma or equivalent and two years of power plant experience of which a minimum of 1 year shall be nuclear power plant experience. At least 6 months of the nuclear experience shall be at CGS unless the incumbent has an equal amount of nuclear experience acquired on a similar unit. The individual shall hold an RO license. For NRC license eligibility guidelines (experience, training, and education) for an RO license, see NUREG-1021, section ES-202.
13.1.3.2.7        Equipment Operator Before assuming the full responsibilities of the position in the plant, the Equipment Operator shall have a minimum of a high school diploma or equivalent and shall have completed the Energy Northwest training program for Equipment Operators. This position does not require an RO license.
13.1.3.3         Engineering 13.1.3.3.1        Vice President Engineering, Assistant Vice President Engineering, System Engineering Manager, Design Engineering Manager, Reactor Fuels Manager, Technical Services Manager, and Plant Support Engineering Manager Vice President Engineering, Assistant Vice President Engineering, System Engineering Manager, Design Engineering Manager, Reactor Fuels Manager, Technical Services Manager, and Plant Support Engineering Manager shall have a minimum of 8 years of related technical experience of which 1 year should be nuclear power plant experience. A maximum of 4 years of the remaining 7 years may be fulfilled by satisfactory completion of academic training.
LDCN-14-037, 15-008                           13.1-14

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 A bachelor of science degree in engineering or physical sciences suitable to the nuclear power field is required. The Reactor Fuels Manager shall have a minimum of 2 years of experience in areas such as reactor/core physics, measurements, heat transfer, and physics testing. The Engineer in Charge described in Section 13.1.1.3 shall have (in addition to any applicable requirements listed above) a minimum of a Bachelors Degree in Engineering or the Physical Sciences and have a minimum of three years of professional level experience in nuclear services, nuclear plant operation, or nuclear engineering, and the necessary overall nuclear background to determine when to call consultants and contractors for dealing with complex problems beyond the scope of owner-organization expertise.
13.1.3.3.2      Engineering Supervisors The Engineering Supervisors in System Engineering, Design Engineering, Plant Support Engineering, and Technical Services shall have a minimum of 5 years of related technical experience of which 1 year shall be nuclear power plant experience. A maximum of 4 years of the required 5 years may be fulfilled by satisfactory completion of academic training. The Reactor Engineering/Fuel Design Supervisor(s) shall have a minimum of 2 years experience in areas such as reactor/core physics, measurements, heat transfer, and physics testing. A Bachelor of Science degree in engineering or physical sciences or the equivalent is required.
13.1.3.3.3      Fire Protection Engineer The qualified Fire Protection Engineer meets the qualifications of member grade in the Society of Fire Protection Engineers or is a registered Fire Protection Engineer.
13.1.3.4       Maintenance 13.1.3.4.1      Maintenance Managers The Maintenance Manager shall have a minimum of 7 years of responsible power plant experience or applicable industrial experience, a minimum of 1 year of which shall be nuclear power plant experience. A maximum of 2 years of the remaining 6 years of power plant or industrial experience may be fulfilled by satisfactory completion of academic or related technical training on a one-for-one time basis. He further should have nondestructive testing familiarity, craft knowledge, and an understanding of electrical, pressure vessel, and piping codes.
13.1.3.4.2      Maintenance Supervisors Maintenance Supervisors shall each have a high school diploma or equivalent and should have a minimum of 4 years experience in the craft or discipline that they supervise in accordance with ANSI 18.1, 1971. In cases where a supervisor does not have a minimum of 4 years of 13.1-15

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 experience in the discipline of the craft being supervised, technical direction for the craft will be given by a qualified supervisor.
13.1.3.5       Chemistry and Radiological Services 13.1.3.5.1      Chemistry and Radiological Safety Manager The Chemistry and Radiological Safety Manager shall, in accordance with ANSI N18.1-1971, have a minimum of 8 years in responsible positions, of which 1 year shall be nuclear power plant experience. A maximum of 4 years of the remaining seven years of experience should be fulfilled by satisfactory completion of academic training.
13.1.3.5.2      Radiological Services Manager The Radiological Services Manager shall meet the qualification requirements of ANSI N18.1-1971, section 4.2.4. This includes a minimum of 8 years of responsible positions, of which a minimum of 1 year shall be nuclear power plant experience.
A maximum of 4 years of the remaining 7 years of experience should be fulfilled by satisfactory completion of academic training.
13.1.3.5.3      Radiation Protection Manager The Radiological Services Manager functions as the Radiation Protection Manager and shall, at a minimum, meet the qualifications defined in Regulatory Guide 1.8, Revision 1-R, May 1977.
This individual shall have a bachelors degree or the equivalent in a science or engineering subject including some formal training in radiation protection. The Radiation Protection Manager shall have at least 5 years of professional experience in applied radiation protection.
A masters degree may be considered equivalent to 1 year of professional experience and a doctors degree may be considered equivalent to 2 years of professional experience where course work related to radiation protection is involved. At least 3 years of this professional experience shall be in applied radiation protection work in a nuclear facility dealing with radiological problems similar to those encountered in nuclear power stations, preferably in an actual nuclear power station. The Radiation Protection Manager is an assigned duty and not a defined position in the organization (see Section 12.5.1).
13.1.3.5.4      Radiological Services Supervisors Radiological Services Supervisors shall, in accordance with ANSI 18.1-1971, have a high school diploma or equivalent and a minimum of 4 years of related experience.
LDCN-13-061                                   13.1-16

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 13.1.3.5.5     Chemistry Supervisors Chemistry Supervisors who are responsible for directing the actions of technicians shall, in accordance with ANSI N18.1-1971, have a high school diploma or equivalent and a minimum of 4 years related experience.
1.3.1.3.6      Deleted 13.1.3.7      Quality See the OQAPD for a description of qualification requirements.
LDCN-13-061                                13.1-17

COLUMBIA GENERATING STATION                            Amendment 61 FINAL SAFETY ANALYSIS REPORT                           December 2011 Table 13.1-1 Minimum Shift Crew Composition Minimum Number of Personnel per Position per Shift Position Titleb     Type of License          Modes 1, 2, and 3c          Modes 4 and 5c SM                 SRO                             1                      1 CRS                SRO                             1                      None RO                 RO                              2                      1 EO                 None                            2                      1 STA                None                          1d,e                     Notef HP                 None                            1                      1 a
This table represents the minimum number of personnel required to fill any particular position. It does not provide a total staffing level for an operating shift. Additional staff for safe shutdown and fire brigade must also be satisfied.
Technical Specifications paragraph 5.3.2 was added in LAR 182 to clarify compliance with 10 CFR 55.53 requirements. Energy Northwest may take credit for more than the minimum number of watchstanders required by 10 CFR 50.54(m). However, fulfillment of 10 CFR 55.53(e) and (f) requirements of active performance of operator or senior operator functions requires that Energy Northwest implement administrative controls to assure functions and duties are divided and rotated in a manner which provides each watchstander meaningful and significant opportunity to maintain proficiency in the performance of the functions of an RO and/or SRO.
b Position title abbreviations are as follows:
SM      Shift Manager with SRO on Columbia Generating Station CRS     Control Room Supervisor with SRO on Columbia Generating Station RO      Reactor Operator with RO or SRO on Columbia Generating Station EO      Equipment Operator STA     Shift Technical Advisor HP      Health Physics Technician 13.1-19

COLUMBIA GENERATING STATION                         Amendment 61 FINAL SAFETY ANALYSIS REPORT                       December 2011 Table 13.1-1 Minimum Shift Crew Composition (Continued) c Modes
: 1.      Power operation
: 2.      Startup
: 3.      Hot shutdown
: 4.      Cold shutdown
: 5.      Refueling d
An STA qualified individual shall be on-shift in Modes 1, 2 and 3. The STA qualified individual may be a dedicated individual (licensed or non-licensed) or an individual filling a dual role position as the Control Room Supervisor, Shift Manager or Shift Support Supervisor.
e When the STA qualified individual is filling a dual role as the Control Room Supervisor or Shift Manager, another SRO is required to be on-shift to provide independent oversight and emergency response support to the Shift Manager.
f Refer to the Emergency Plan for emergency response staffing requirements in Modes 4, 5.
The shift crew composition may be one less than the minimum requirements for a period not to exceed 2 hr to accommodate unexpected absence of on-duty shift crew members provided immediate action is taken to restore the shift crew composition to within the minimum requirements. This provision does not permit any shift crew position to be unmanned on shift change due to an oncoming shift crewman being late or absent.
During any absence of the Shift Manager from the control room while the unit is in Operational Condition 1, 2, or 3, an Operations Department individual with a valid SRO license shall be designated to assume the control room command function. During any absence of the Shift Manager from the control room while the unit is in Operational Condition 4 or 5, an individual with a valid SRO license or RO license shall be designated to assume the control room command function.
13.1-20

Amendment 63 December 2015 Chief Executive Officer Chief Nuclear Officer Quality Manager Legend:
Administrative and Functional Reporting Communications Lines Energy Northwest Organization Columbia Generating Station Final Safety Analysis Report Draw. No. 970187.02     Rev. Figure 13.1-1 Form No. 960690FH LDCN-14-011, 14-019, 14-046

Amendment 63 December 2015 Chief Nuclear Officer Quality              Vice President                    Vice President Manager                Operations                         Engineering Nuclear Generation Organization Columbia Generating Station Final Safety Analysis Report Draw. No. 970187.03    Rev.        Figure 13.1-2 Form No. 960690FH LDCN-14-019, 14-046

Amendment 63 December 2015 Plant General Manager Chemistry and                                                            Planning Operations              Maintenance Radiological              Manager                  Manager            Scheduling, Safety                                                            and Outage Manager**                                                             Manager Radiological Services Manager*
Security Force Lieutenant
* Also fulfills Radiation Protection Manager function
                  ** Also fulfills the Chemistry Manager function Plant General Manager Organization Columbia Generating Station Final Safety Analysis Report Draw. No. 970187.41      Rev. 2      Figure 13.1-3 Form No. 960690FH LDCN-13-061

Amendment 63 December 2015 Vice President Operations Emergency Services           Plant                      Training Manager                General                     Manager Manager Operational Support Organization Columbia Generating Station Final Safety Analysis Report Draw. No. 970187.05      Rev. 4    Figure 13.1-4 Form No. 960690FH LDCN-14-019,15-008

Amendment 63 December 2015 DELETED Training Organization Columbia Generating Station Final Safety Analysis Report Draw. No. 970187.06       Rev. 1   Figure 13.1-5 Form No. 960690FH LDCN-14-019

Amendment 63 December 2015 Vice President Engineering Assistant Vice President Engineering Design                      Reactor                      Plant Support Engineering                     Fuels                        Engineering Manager                     Manager                           Manager Technical                      System Services                     Engineering Manager                       Manager Columbia Generating Station                     Vice President Engineering Organization Final Safety Analysis Report Draw. No. 970187.07      Rev.       Figure 13.1-6 Form No. 960690FH LDCN-14-019

Amendment 61 December 2011 Quality Manager Quality Services        Supplier Quality                Quality Services Supervisor             Supervisor                    Supervisor/Plant Maintenance/Engineering/                                         Support Quality Control (Audits)                               (Continuous Monitoring)
Quality Organization Columbia Generating Station Final Safety Analysis Report Draw. No. 970187.08       Rev. 1      Figure 13.1-7 Form No. 960690FH LDCN-10-002

Amendment 62 December 2013 DELETED Columbia Generating Station Final Safety Analysis Report Draw. No. 970187.04 Rev. 1 Figure 13.1-8 Form No. 960690FH LDCN-12-004

Amendment 62 December 2013 Operations Manager Operations           Operations Support       Assistant Operations        Assistant Operations Crew Manager                Manager               Manager - Training              Manager -
Work Control Operations Organization Columbia Generating Station Final Safety Analysis Report Draw. No. 970187.09       Rev. 2       Figure 13.1-9 Form No. 960690FH LDCN-13-040

Amendment 62 December 2013 Operations Manager Operations Crew Manager Shift Managers (SRO)
                                 *Shift Technical                                         Incident Advisor                                              Advisor Control Room                                         If Required Supervisor                                         Shift Support (SRO)                                                      Supervisor Control Room Equipment Reactor Operators Operators (RO)(SRO)
Equipment                                         HP***/Chemistry Operators                                          Technicians Maintenance Legend:                                                                                 Support**
Functional StructureRather than Organizational Structure NRC License             Position Required (SRO)
* An assigned duty, not an organizational title
              ** To be provided from Maintenance Department as required
             *** To be provided from HP/Chemistry Department as required Operations Crew Columbia Generating Station Final Safety Analysis Report Draw. No. 970187.10         Rev. 1     Figure 13.1-10 Form No. 960690FH LDCN-12-020

Amendment 63 December 2015 Chemistry and Radiological Safety Manager Radiological Services Manager*
Radiological                  Radiological Operations                     Support Supervisor                  Supervisor Rad-Material HP Craft Control / Rad-Waste            Supervisors Supervisor
            *Also fulfills Radiation Protection Manager function Columbia Generating Station                                  Radiological Services Organization Final Safety Analysis Report Draw. No. 970187.11         Rev. 3 Figure 13.1-11 Form No. 960690FH LDCN-13-061

Amendment 63 December 2015 Chemistry and Radiological Safety Manager**
Chemistry                               Chemistry                          Environmental/
Technical                              Operations                       Analytical Support Supervisor                             Supervisors                           Supervisor*
* Dashed line indicates a functional rather than an organizational structure.
                     ** Also fulfills the Chemistry Manager function Columbia Generating Station                                      Chemistry Organization Final Safety Analysis Report Draw. No. 970187.12     Rev. 1      Figure 13.1-12 Form No. 960690FH LDCN-13-061

Amendment 63 December 2015 Maintenance Manager FIN Component             Maintenance                Reactor and Group                  Services              Major Maintenance Manager                Manager                     Manager Mechanical                   I&C                      Electrical Component                Component                   Component Group Manager            Group Manager               Group Manager Columbia Generating Station                          Plant Maintenance Organization Final Safety Analysis Report Draw. No. 970187.13       Rev. 3       Figure 13.1-13 Form No. 960690FH LDCN-13-040, 15-008

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 13.2     TRAINING 13.2.1       PLANT STAFF TRAINING PROGRAM In accordance with applicable federal guidelines, the Columbia Generating Station (CGS) training program has been designed to provide plant personnel with sufficient knowledge, training, and experience to enable them to safely and efficiently operate and maintain the plant and to protect the health and safety of the public.
The overall training program has been developed and coordinated by Energy Northwest, utilizing courses and programs produced by the nuclear steam supply system (NSSS) supplier, training consultant organizations, the training staff, and other employees of Energy Northwest possessing expertise in related disciplines.
The training program will provide sufficient qualified reactor operators, senior reactor operators, equipment operators, shift technical advisors, maintenance, health physics, chemistry, and engineering support personnel to fully staff CGS.
Initial training programs provide qualified replacement personnel and continuing training programs provide ongoing training for all plant staff commensurate with their area of responsibility and knowledge level.
The Chief Nuclear Officer is responsible for overall conduct and administration of the CGS training program. The development and implementation of that program may be delegated to the Training Organization or other members of the plant staff.
: a.      General Employee Training - Program Description All personnel granted unescorted access to the station will be trained in the following areas:
: 1. Appropriate plant security and emergency procedures,
: 2. General radiological protection,
: 3. Industrial safety,
: 4. Fire protection, and
: 5. Quality assurance program.
Written or oral exams will be required for selected classes to determine successful completion.
LDCN-14-046                                   13.2-1

COLUMBIA GENERATING STATION                            Amendment 58 FINAL SAFETY ANALYSIS REPORT                           December 2005
: b. General Employee Training - Fire Protection Program
: 1.       Plant employees Employees receiving an unescorted security clearance will be provided training to include orientation to the fire protection plans, evacuation signals and procedures, and the procedure for reporting a fire.
: 2.       Contractor personnel Training will be provided to contractors as part of their access status--
escorted or unescorted.
: c. Security Personnel Training - Fire Protection Program Training will be provided to plant security personnel that addresses
: 1.       Entry procedures for offsite fire department,
: 2.       Personnel control during emergency evacuation, and
: 3.       Basic fire hazard recognition.
13.2.2      INITIAL AND CONTINUING TRAINING 13.2.2.1       Licensed Operators 13.2.2.1.1      Initial Training Under the normal progression of an individual through the various levels of operator qualification, much of the material and experience will have been previously obtained, and hence, the licensed operator replacement training program will emphasize topics pertinent to the control room operator job function and requirements necessary for fulfilling the NRC operator licensing qualifications. Replacement for licensed operators normally come from the ranks of qualified nonlicensed operators; however, personnel from other departments or from outside the utility may be trained as control room operators if they meet all requirements for the position.
The CGS Operations Training Manager shall have the responsibility for establishing, supervising, and scheduling the initial licensed operator training program.
In accordance with 10 CFR 55.31(a)(4) the CGS licensed operator initial training program has been reviewed and approved by the Commission and was developed using a systems approach to training.
LDCN-03-077                                      13.2-2

COLUMBIA GENERATING STATION                          Amendment 58 FINAL SAFETY ANALYSIS REPORT                         December 2005 The licensed operator initial training program has been accredited by the National Academy for Nuclear Training. The accreditation is renewed every 4 years. Accreditation is maintained in accordance with Institute of Nuclear Power Operation (INPO) Guidelines 02-001, The Objectives and Criteria for Accreditation of Training in the Nuclear Power Industry, and 02-002, The Process for Accreditation of Training in the Nuclear Power Industry.
13.2.2.1.2      Continuing Training A requalification training program implementing the requirements of 10 CFR 55.59, will be conducted to maintain the knowledge level and operating proficiency of licensed personnel.
The retraining program will be based on a 2-year cycle.
The CGS Operations Training Manager shall have the responsibility for establishing, supervising, and scheduling the retraining program.
In accordance with 10 CFR 55.59(c) the CGS licensed operator requalification training program has been reviewed and approved by the NRC and was developed using a systems approach to training.
The requalification program has been accredited by the National Academy for Nuclear Training. The accreditation is maintained in accordance with INPO Guidelines 02-001, The Objectives and Criteria for Accreditation of Training in the Nuclear Power Industry, and 02-002, The Process for Accreditation of Training in the Nuclear Power Industry.
The retraining and replacement program for the unit staff meets the requirements of Section 5.5 of ANSI/ANS N18.1-1971, Appendix A of 10 CFR Part 55, and the supplemental requirements specified in Sections A and C of Enclosure 1 of the March 28, 1980, NRC letter to all licensees, and includes familiarization with relevant industry operational experience.
13.2.2.2       Nonlicensed Operator Training 13.2.2.2.1      Initial Training Normally replacements will be required to complete the following training prior to being placed into the equipment operator qualification sequence:
: a. Basic fundamentals,
: b. Basic boiling water reactor (BWR) systems,
: c. Reactor plant equipment and component theory, and
: d. Administrative procedures.
The training will emphasize topics pertinent to the equipment operator job function and requirements necessary for qualification.
LDCN-03-077                                    13.2-3

COLUMBIA GENERATING STATION                          Amendment 58 FINAL SAFETY ANALYSIS REPORT                         December 2005 13.2.2.2.2      Continuing Training Program Continuing training of nonlicensed operators may be conducted in conjunction with the licensed operator requalification program. Nonlicensed operators shall be required to attend specific lecture topics that pertain to their job level requirements. At a minimum, nonlicensed operators shall participate in periodic reviews of systems and operating procedures for which continuous familiarization is important for safe and efficient operation of the plant.
Specifically, the equipment operator retraining program consists of
: a.      Preplanned lecture series,
: b.      Update lecture series,
: c.      Normal/abnormal procedure review, and
: d.      Examinations/evaluations.
The CGS Operations Training Manager has the responsibility for establishing, supervising, and scheduling the equipment operator training program.
The equipment operator training program has been accredited by the National Academy for Nuclear Training. The accreditation is renewed every 4 years. Accreditation is maintained in accordance with INPO Guidelines 02-001, The Objectives and Criteria for Accreditation of Training in the Nuclear Power Industry, and 02-002, The Process of Accreditation of Training in the Nuclear Power Industry.
13.2.2.3       Shift Technical Advisor Training 13.2.2.3.1      Initial Training The initial shift technical advisor (STA) training program content will normally include training and qualification in the following subject areas:
: a.      Completion of the SRO replacement operator training program or equivalent
: b.      Plant transient/accident analysis, and
: c.      STA job specific training.
13.2.2.3.2      Continuing Training Continuing training of the STAs is normally conducted in conjunction with the licensed operator requalification training program. The STAs shall be required to attend specific lecture topics that pertain to their job level requirements. At a minimum, STAs shall participate in periodic reviews of systems and operating procedures for which continuous LDCN-03-077                                     13.2-4

COLUMBIA GENERATING STATION                        Amendment 58 FINAL SAFETY ANALYSIS REPORT                       December 2005 familiarization is important for safe and efficient operation of the plant. Specifically, the STA retraining program consists of
: a.        Preplanned lecture series,
: b.        Update lecture series,
: c.        Normal/abnormal procedure review, and
: d.        Examinations/evaluations.
The CGS Operations Training Manager has the responsibility for establishing, supervising, and scheduling the STA training program.
The STA training program has been accredited by the National Academy for Nuclear Training.
The accreditation is renewed every 4 years. Accreditation is maintained in accordance with INPO Guidelines 02-001, The Objectives and Criteria for Accreditation of Training in the Nuclear Power Industry, and 02-002, The Process for Accreditation of Training in the Nuclear Power Industry.
13.2.2.4         Other Plant Personnel (Maintenance, Health Physics, Chemistry) 13.2.2.4.1        Initial Training Replacement personnel, when hired, will be given training commensurate with their job responsibilities as determined necessary by the respective Department Manager and the appropriate Training Supervisor after a review of past experience and training.
13.2.2.4.2        Continuing Training Continuing training is conducted on a regular basis and consists of pertinent operating experience and designated requalification topics. The continuing training will be commensurate with their assigned job responsibilities as determined necessary by their respective Department Manager and Training Coordinator.
13.2.2.5         Fire Brigade 13.2.2.5.1        Initial and Continuing Training Each assigned member of the Fire Brigade will complete initial and continuing Fire Brigade training courses to provide the knowledge and skills necessary to accomplish the expected fire fighting activities. The scope of this training will be described and implemented by plant procedures.
LDCN-03-059, 03-077                             13.2-5

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 One assigned member will be designated as the Fire Brigade leader to direct the actual fire fighting forces. This individual will receive the training necessary to effectively carry out this function.
The Fire Brigade leader and two additional members will be knowledgeable of plant fire safe shutdown equipment.
: a.      Planned meetings Regular planned meetings for each Fire Brigade member will be held each quarter to review changes in the program and other subjects, as necessary.
During these planned meetings, the initial training program content will be reviewed for all Fire Brigade members over a 2-year period.
: b.      Practice sessions Practice sessions will be held for each Fire Brigade member annually on the proper methods of fighting the various types of fires that could occur in a nuclear power plant.
: c.      Drills Planned drills will be conducted for practice in responding as a team to areas of the plant site where the Fire Brigade may be required to respond. Each Fire Brigade member will be required to participate in at least two drills per year.
Each shift Fire Brigade will be required to participate in quarterly fire drills.
One drill for each shift Fire Brigade per year will be unannounced and one drill for each shift Fire Brigade per year will be on a back shift. The back shift and unannounced drill requirements can be satisfied concurrently for each shift.
13.2.2.5.2      Offsite Fire Department The offsite fire department that supplements the Fire Brigade will attend familiarization training associated with the CGS plant layout, operational precautions, radiation protection, and special hazards associated with fires at a nuclear power plant. This offsite fire department will participate in at least one fire drill each year.
LDCN-01-075                                      13.2-6

COLUMBIA GENERATING STATION                          Amendment 56 FINAL SAFETY ANALYSIS REPORT                        December 2001 13.2.3      TRAINING PROGRAM EFFECTIVENESS The effectiveness of the Training Program will be evaluated by the following methods:
: a.      Satisfactory job performance as determined by periodic line management evaluations and observations,
: b.      Satisfactory performance of plant personnel on various oral and or written examinations administered by Energy Northwest or NRC, and
: c.      Periodic reviews of instructors, programs, and training material as conducted by the Training Department.
13.2.4      PLANT TRAINING RECORDS The Training Manager maintains complete qualification records on each member of the plant staff.
All records necessary to support requests for NRC reactor operator and senior reactor operator licenses are included in these files. Records to be maintained are as follows:
: a.      Lecture series attendance,
: b.      Lecture examinations and answers by the licensees,
: c.      Annual examinations and answers by the licensees,
: d.      Simulator performance evaluation results,
: e.      Control Manipulations Tracking System Form, and
: f.      Additional training for deficiencies.
13.2.5      OTHER TRAINING DOCUMENTS For compliance with other applicable documents see Sections 1.8 and 12.5.3.8.
LDCN-01-047                                    13.2-7

COLUMBIA GENERATING STATION                      Amendment 53 FINAL SAFETY ANALYSIS REPORT                     November 1998 13.3    EMERGENCY PLANNING The detailed emergency plan is included as a separate volume in the Columbia Generating Station Emergency Plan.
13.3-1

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 13.4    REVIEW AND AUDIT The following sections describe the conduct of reviews and audits of operating activities that are important to safety. The review and audit program is consistent with the requirements of ANSI N18.7-1976, Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants.
Periodic reviews of plant operations are performed by the plant operating staff. In addition, Energy Northwest uses a formal onsite committee (see Section 13.4.1) and an independent group (see Section 13.4.2) for review.
The Quality staff has formulated and executed an audit program for the plant activities as defined in the Operational Quality Assurance Program Description (OQAPD).
The organization for review and audit and its relationship to other organizations is shown in Figures 13.1-1, 13.1-2, and 13.1-7.
13.4.1      ONSITE REVIEW Onsite reviews are consistent with Regulatory Guide 1.33 (see Section 1.8). The plant operating staff provides, as part of the normal duties of plant supervisory personnel, timely and continuing monitoring of operating activities to assist the Plant General Manager in keeping abreast of general plant conditions and to verify that the day-to-day operating activities are conducted safely and in accordance with applicable administrative controls. These continuing monitoring activities are an integral part of the routine supervisory function and are important to the safety of plant operation.
13.4.2      INDEPENDENT REVIEW In accordance with the OQAPD, the Plant Operations Committee (POC) serves as a review and advisory organization to the Plant General Manager on all matters related to nuclear safety. The Senior Site ALARA Committee (SSAC) serves as a review and advisory organization to the Plant General Manager on radiological safety matters. A specific function of the POC is to implement an independent review program as it relates to all proposed Technical Specification changes, License Amendment Requests, and Emergency Plan changes.
Written administrative procedures describe the responsibility and authority of the POC and SSAC. The POC activities and review are described in the OQAPD. The results of POC and SSAC review activities are documented.
LDCN-15-028                                   13.4-1

COLUMBIA GENERATING STATION                          Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 Additionally, in accordance with the OQAPD, the Corporate Nuclear Safety Review Board (CNSRB) is responsible for oversight of the POC and SSAC, which entails evaluating the effectiveness of POC and SSAC reviews, collectively, with regard to nuclear and radiological safety. The CNSRB reports to and advises the Chief Executive Officer on the adequacy and implementation of Energy Northwest nuclear and radiological safety policies and programs.
Documentation defining CNSRB membership, responsibilities, authority, and method of operation is contained in a Site Wide Procedure. Significant organizational features and review responsibilities are also described in the OQAPD. Conclusions of the independent reviews are transmitted to the appropriate members of management.
Independent technical reviews are performed by Quality in accordance with the OQAPD.
The objectivity of Quality is maintained based on a charter and reporting relationship independent of plant line management, without precluding participation in plant activities and tasks.
13.4.3      AUDIT PROGRAM A comprehensive program of audits is carried out to verify compliance to the OQAPD. These audits are performed by or under the direct cognizance of the Quality staff. Written reports of such audits are reviewed by the CNSRB, Plant General Manager, and other management as appropriate. Timely resolution of any deficiencies noted during audits is required by those organizations having responsibility for the area audited. Details of those areas to be audited are described in the OQAPD.
LDCN-15-028                                   13.4-2

COLUMBIA GENERATING STATION                           Amendment 62 FINAL SAFETY ANALYSIS REPORT                          December 2013 13.5    PLANT PROCEDURES The administrative controls and quality assurance program for plant operation are carried out in accordance with approved written procedures. All activities affecting nuclear safety are conducted by written and approved procedures of a type appropriate to the circumstances, and these activities are accomplished in accordance with these procedures.
13.5.1      ADMINISTRATIVE PROCEDURES 13.5.1.1       Conformance With Regulatory Guide 1.33, Revision 2 ANSI N18.7-1976 and Regulatory Guide 1.33 including Appendix A are followed in accordance with the Energy Northwest position discussed in the Operational Quality Assurance Program Description (OQAPD).
13.5.1.2       Preparation of Procedures The Procedure Program provides the administrative controls necessary to prepare, review, and approve the procedures required for plant operating activities.
The Chief Nuclear Officer has the overall responsibility for the Procedure Program and its implementing procedures. The Plant General Manager is responsible for the procedures that are required by ANSI N18.7-1976 and Regulatory Guide 1.33 and Appendix A. The preparation and review of the procedures are the responsibility of various plant staff personnel.
All procedures are approved according to the Procedure Program and the OQAPD.
13.5.1.3       Procedures The Procedure Program for Administrative Procedures defines the responsibility, methods used, and procedural action required to help ensure that the plant will be managed in a safe and dependable manner.
Administrative Procedures establish rules and instructions pertaining to activities such as procedure preparation, records management, plant reporting requirements, plant personnel responsibilities and authorities, plant modification, corrective and preventive maintenance, clearance orders, temporary changes to approved procedures, reviews of plant documents, surveillance testing and inservice inspection, equipment control, and material control.
Administrative Procedures governing standing orders to shift operations include the reactor operators authority and responsibilities; the senior reactor operators authority and responsibilities; the logbook use and control; issuance and updating of special orders; and the plans for meeting the requirements of 10 CFR 50.54(i), (j), (k), (1), and (m). This includes a diagram of the control room that illustrates the area designated as at the controls.
LDCN-12-022                                    13.5-1

COLUMBIA GENERATING STATION                            Amendment 55 FINAL SAFETY ANALYSIS REPORT                          May 2001 13.5.2       OPERATING AND MAINTENANCE PROCEDURES 13.5.2.1       Control Room Operating Procedures Detailed procedures used by the control room operators ensure plant safety and reliability.
These procedures are categorized and described as follows:
System Operating Procedures The System Operating Procedures provide instructions pertinent to the various normal operating modes of startup, operation, and shutdown of each system or subsystem. Checkoff lists are included, where appropriate, with each procedure to delineate the proper equipment lineup that is required.
General Operating Procedures General Operating Procedures provide the instructions for the integrated operation of plant systems during startup, shutdown, power operations, and power changes. Checkoff lists, as appropriate, are included to ensure that necessary prerequisites to integrated operation have been completed. Checklists may also be used to confirm completion of major steps in the proper sequence.
Abnormal Condition Procedures Abnormal Condition Procedures specify operator actions for restoring selected equipment or systems to their normal controlled status on a failure or to restore normal operating conditions following a perturbation. These procedures are not emergency procedures but are written to aid the operator in determining if a true emergency exists.
Abnormal Condition Procedures also contain response instructions for annunciator alarms and for abnormal conditions within the major systems covered in System Operating Procedures.
Each safety-related annunciator is addressed in a written procedure which contains (1) meaning of annunciator, (2) the source of the signal, (3) the immediate action that is to occur automatically, (4) immediate operator actions, and (5) subsequent operator actions. Those procedures that require the Immediate Operator Action steps to be memorized are given adequate identification.
Emergency Operating Procedures/Severe Accident Guidelines Emergency Operating Procedures/Severe Accident Guidelines are provided to guide operations during potential emergencies. These procedures specify actions, including manipulation of 13.5-2

COLUMBIA GENERATING STATION                          Amendment 62 FINAL SAFETY ANALYSIS REPORT                         December 2013 controls, to avoid further degradation of abnormal conditions or to reduce the consequences of an accident or hazardous condition that has already occurred.
13.5.2.2       Other Procedures Other safety-related activities conducted in accordance with approved procedures are categorized and described as follows (radioactive waste system operating procedures are covered by System Operating Procedures and the other aspects of radioactive waste management are covered by Health Physics and Chemistry Procedures).
Fuel Handling and Refueling Activities Procedures Fuel Handling and Refueling Activities Procedures provide instructions for fuel and core component accountability, new fuel handling, refueling operations, defective fuel handling, reactor core component handling, and irradiated fuel shipment.
Surveillance Procedures (both Operational Surveillance and Instrument and Electrical Surveillance)
Surveillance Procedures provide instructions for performing periodic tests to verify and document that safety-related structures, systems, and components continue to function properly to remain in a state of readiness to perform their intended safety functions. Surveillance Procedures cover systems operability tests, logic system functional tests, and instrument and/or electrical functional tests and calibrations for the various surveillance requirements listed in the Technical Specifications.
Operating and Test Procedures Operating and Test Procedures provide instructions for performing special tests on both safety and non-safety-related systems and components. These procedures contain tests such as power ascension, turbine efficiency, system hydrostatic tests, and reactor steam quality.
Nuclear Performance Evaluation Procedures The Nuclear Performance Evaluation Procedures provide instructions for Engineering and Operations in the performance of the following types of evaluations: core thermal power evaluations, core thermal-hydraulic evaluations, intermediate range monitor, local power range monitor, and average power range monitor calibration and criticality predictions.
LDCN-12-004                                     13.5-3

COLUMBIA GENERATING STATION                         Amendment 55 FINAL SAFETY ANALYSIS REPORT                        May 2001 Maintenance Programs and Procedures Maintenance Procedures provide instructions for performance of maintenance on safety-related equipment or systems and selected non-safety-related equipment and systems. Maintenance procedures cover mechanical, electrical, instrument and control, coatings, and refueling activities.
Health Physics Procedures Health Physics Procedures establish the administrative and technical controls for the Radiation Protection Program and the implementing procedures for accomplishing the program.
Descriptions of the activities covered by these procedures are included in Chapter 12.
Chemistry Procedures Chemistry Procedures establish the administrative and technical controls for water quality analysis. Chemical and radiochemical determination procedures and associated instrument operation and calibration procedures are provided.
Emergency Plan Implementing Procedures Detailed procedures prescribe the appropriate course of action necessary to limit or mitigate the consequences for each classification of incidents described in the Emergency Plan. An index of the Emergency Plan Implementing Procedures is included in Appendix II to the Emergency Plan.
Security Programs Implementing Procedures Detailed security procedures prescribe the course of action necessary for compliance with the policies of the Security Plan. The Security Plan and associated implementing procedures that contain safeguards information are withheld from public disclosure (see Section 13.6).
Fire Protection Procedures Fire Protection Procedures provide instructions for performing tests, inspections, and scheduled maintenance on fire protection equipment and systems and actions required for degraded systems.
ODCM Implementing Procedures The ODCM Implementing Procedures prescribe the action necessary to implement the requirements of the Offsite Dose Calculation Manual (ODCM), including effluent monitoring, instrument calibration, and reporting requirements.
13.5-4

COLUMBIA GENERATING STATION                       Amendment 55 FINAL SAFETY ANALYSIS REPORT                      May 2001 Environmental Compliance Procedures Environmental Compliance Procedures establish the administrative and technical controls for environmental compliance. These procedures provide instructions for the management of solid wastes, pollution prevention and waste minimization, chemical storage and use, and hazardous substance spills and cleanup.
13.5-5

COLUMBIA GENERATING STATION                        Amendment 53 FINAL SAFETY ANALYSIS REPORT                       November 1998 13.6    INDUSTRIAL SECURITY The Columbia Generating Station Physical Security Plan contains a description of the physical protection program for the facility as required by 10 CFR 50.54(p) and 10 CFR 73.55. The contents of this plan are safeguards information and are withheld from public disclosure pursuant to Section 2.790(a)(3) of 10 CFR Part 2.
13.6-1

COLUMBIA GENERATING STATION                                      Amendment 54 FINAL SAFETY ANALYSIS REPORT                                     April 2000 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS Section                                                                                             Page 14.1 SPECIFIC INFORMATION INCLUDED IN PRELIMINARY SAFETY ANALYSIS REPORTS..................................................... 14.1-1 14.2 SYSTEM LINEUP, PREOPERATIONAL, AND INITIAL STARTUP TEST PROGRAM ....................................................................... 14.2-1 14.2.1 

==SUMMARY==
OF TEST PROGRAM AND OBJECTIVES ......................... 14.2-1 14.2.1.1 Initial Test Program Objectives .................................................. 14.2-1 14.2.1.2 Initial Test Program Summaries.................................................. 14.2-1 14.2.1.3 Description of System Lineup Tests .............................................. 14.2-2 14.2.1.4 Description of Preoperational Tests ............................................. 14.2-3 14.2.1.5 Description of Startup Tests....................................................... 14.2-3 14.2.2 ORGANIZATION AND STAFFING................................................. 14.2-4 14.2.2.1 General ............................................................................... 14.2-4 14.2.2.2 Definitions............................................................................ 14.2-5 14.2.2.3 Test and Startup Program Organization and the System Lineup and Preoperational Test Program...................................................... 14.2-6 14.2.2.3.1 General............................................................................. 14.2-6 14.2.2.3.2 Responsibilities of CGS Test and Startup Division ......................... 14.2-6 14.2.2.3.3 CGS Test and Startup Department Position Responsibilities ............. 14.2-6 14.2.2.3.3.1 CGS Test and Startup Manager ............................................. 14.2-6 14.2.2.3.3.2 CGS Test Group Manager.................................................... 14.2-7 14.2.2.3.3.3 CGS Test Group Supervisor.................................................. 14.2-7 14.2.2.3.3.4 CGS Test Engineers ........................................................... 14.2-8 14.2.2.4 Plant Operations Organization and the Power Ascension Test Program ............................................................................... 14.2-8 14.2.2.5 Test Working Group ................................................................ 14.2-9 14.2.2.5.1 System Lineup and Preoperational Test Program .......................... 14.2-9 14.2.2.5.2 Membership and Responsibility of the Test Working Group .............. 14.2-9 14.2.2.6 Plant Organization Functions and Responsibilities During All Testing and Plant Operations...................................................... 14.2-10 14.2.2.7 Energy Northwest Support of the Test and Startup Program ................ 14.2-10 14.2.2.7.1 Plant Organization ............................................................... 14.2-10 14.2.2.7.1.1 Support During Test and Startup Program Development ............... 14.2-10 14.2.2.7.1.2 Support During Testing ....................................................... 14.2-11 14.2.2.7.2 CGS Program ..................................................................... 14.2-11 LDCN-99-000                                          14-i

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                            Page 14.2.2.7.3 Plant Quality Assurance......................................................... 14.2-11 14.2.2.8 Architect-Engineer Support of the Test and Startup Program............... 14.2-11 14.2.2.9 General Electric Support of the Test and Startup Program.................. 14.2-12 14.2.2.9.1 Staff Responsibilities ............................................................. 14.2-12 14.2.2.9.1.1 General Electric Operations Manager ..................................... 14.2-12 14.2.2.9.1.2 General Electric Operations Superintendent .............................. 14.2-12 14.2.2.9.1.3 General Electric Shift Superintendents ..................................... 14.2-12 14.2.2.9.1.4 General Electric Lead Engineer - Startup Test, Design, and Analysis .......................................................................... 14.2-13 14.2.2.10 Qualifications of Personnel Supporting the Test and Startup Program ............................................................................. 14.2-13 14.2.2.10.1 Test and Startup Program Department Personnel Qualifications ...... 14.2-13 14.2.2.10.2 Plant Organization Personnel Qualifications .............................. 14.2-14 14.2.3 TEST PROCEDURES................................................................. 14.2-14 14.2.3.1 Development of Test Procedures ................................................. 14.2-14 14.2.3.1.1 Incorporation of Plant Procedures ............................................ 14.2-15 14.2.3.1.2 Format of Test Procedures...................................................... 14.2-15 14.2.3.1.2.1 Preoperational Test Phase ................................................... 14.2-15 14.2.3.1.2.2 Power Ascension Test Phase ................................................. 14.2-17 14.2.3.2 Review of Test Procedures ........................................................ 14.2-17 14.2.3.3 Approval of Test Procedures ...................................................... 14.2-18 14.2.4 CONDUCT OF TEST PROGRAM.................................................. 14.2-18 14.2.4.1 Administrative Procedures for Preoperational Testing ....................... 14.2-18 14.2.4.1.1 Test Performance Authorization ............................................... 14.2-18 14.2.4.1.2 Preoperational Test Prerequisites ............................................. 14.2-19 14.2.4.1.3 Conduct of Preoperational Testing ............................................ 14.2-19 14.2.4.1.4 Deficiency Reporting............................................................. 14.2-20 14.2.4.1.5 Equipment Maintenance and Modifications During Preoperational Testing.............................................................................. 14.2-20 14.2.4.1.6 Preoperational Test Summary .................................................. 14.2-21 14.2.4.1.7 Evaluation of Preoperational Test Data ...................................... 14.2-21 14.2.4.1.8 Preoperational Test Records ................................................... 14.2-21 14.2.4.2 Administrative Procedures for Power Ascension Testing .................... 14.2-21 14.2.4.2.1 Plant Operation During Power Ascension Testing ......................... 14.2-21 14.2.4.2.2 Power Ascension Test Scheduling and Sequencing ......................... 14.2-22 LDCN-02-000                                        14-ii

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                            Page 14.2.4.2.3 Power Ascension Test Performance ........................................... 14.2-22 14.2.4.3 Control of Test Prerequisites...................................................... 14.2-23 14.2.4.4 Modification of Test Procedures During Testing .............................. 14.2-23 14.2.4.4.1 System Lineup and Preoperational Test Phase .............................. 14.2-23 14.2.4.4.2 Power Ascension Test Phase ................................................... 14.2-24 14.2.5 REVIEW, EVALUATION, AND APPROVAL OF TEST RESULTS ........... 14.2-24 14.2.5.1 Control of Test Results Review ................................................... 14.2-24 14.2.5.2 Design Organization Participation in Problem Resolution .................. 14.2-24 14.2.5.3 Results Analysis Prerequisites to Continuation of Startup Testing ......... 14.2-25 14.2.6 TEST RECORDS....................................................................... 14.2-25 14.2.6.1 System Lineup and Preoperational Test Phase ................................ 14.2-25 14.2.6.1.1 General............................................................................. 14.2-25 14.2.6.1.2 Test Record Responsibilities .................................................... 14.2-26 14.2.6.1.3 Types of Documents and Records Requiring Test Record File Retention ........................................................................... 14.2-26 14.2.6.2 Power Ascension Test Phase ...................................................... 14.2-26 14.2.7 CONFORMANCE OF TEST PROGRAMS WITH REGULATORY GUIDES ................................................................................. 14.2-26 14.2.7.1 Conformance with Regulatory Guide 1.68...................................... 14.2-26 14.2.7.2 Exceptions to Regulatory Guide 1.68............................................ 14.2-27 14.2.7.3 Conformance With or Exceptions to Regulatory Guides Other Than 1.68 ............................................................................ 14.2-27 14.2.8 UTILIZATION OF REACTOR OPERATING AND TESTING EXPERIENCES IN THE DEVELOPMENT OF THE TEST PROGRAM...... 14.2-27 14.2.9 TRIAL USE OF PLANT OPERATING AND EMERGENCY PROCEDURES ......................................................................... 14.2-28 14.2.10 INITIAL FUEL LOADING AND INITIAL CRITICALITY ..................... 14.2-28 14.2.10.1 Fuel Loading and Shutdown Power Level Tests.............................. 14.2-28 14.2.10.1.1 Loss of Power Demonstration - Standby Core Cooling Required ...... 14.2-28 14.2.10.1.2 Cold Functional Testing ....................................................... 14.2-28 14.2.10.1.3 Routine Surveillance Testing .................................................. 14.2-29 14.2.10.1.4 Master Startup Checklist....................................................... 14.2-29 14.2.10.1.5 Initial Fuel Loading ............................................................ 14.2-29 14.2.10.1.6 Zero Power Level Tests ........................................................ 14.2-30 14.2.10.2 Initial Heatup to Rated Temperature and Pressure.......................... 14.2-30 LDCN-02-000                                        14-iii

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                           Page 14.2.10.3 Power Testing From 25% to 100% of Rated Output ........................ 14.2-30 14.2.11 TEST PROGRAM SCHEDULE .................................................... 14.2-32 14.2.12 INDIVIDUAL TEST DESCRIPTIONS ............................................ 14.2-32 14.2.12.1 Preoperational Test Procedures ................................................ 14.2-32 14.2.12.1.1 Reactor Feedwater System Preoperational Test ........................... 14.2-33 14.2.12.1.2 Condensate System Preoperational Test .................................... 14.2-33 14.2.12.1.3 Fire Protection System Preoperational Test ................................ 14.2-34 14.2.12.1.4 Reactor Water Cleanup System Preoperational Test...................... 14.2-35 14.2.12.1.5 Standby Liquid Control System Preoperational Test...................... 14.2-35 14.2.12.1.6 Nuclear Boiler System Preoperational Test ................................ 14.2-36 14.2.12.1.7 Residual Heat Removal System Preoperational Test...................... 14.2-37 14.2.12.1.8 Reactor Core Isolation Cooling System Preoperational Test ............ 14.2-37 14.2.12.1.9 Reactor Recirculation System and Control Preoperational Test ........ 14.2-38 14.2.12.1.10 Reactor Manual Control System Preoperational Test ................... 14.2-39 14.2.12.1.11 Control Rod Drive Hydraulic System Preoperational Test ............. 14.2-39 14.2.12.1.12 Fuel Handling and Vessel Servicing Equipment Preoperational Test ............................................................................... 14.2-40 14.2.12.1.13 Low-Pressure Core Spray System Preoperational Test ................. 14.2-41 14.2.12.1.14 High-Pressure Core Spray System Preoperational Test ................ 14.2-42 14.2.12.1.15 Fuel Pool Cooling and Cleanup System Preoperational Test .......... 14.2-43 14.2.12.1.16 Leak Detection System Preoperational Test............................... 14.2-43 14.2.12.1.17 Liquid and Solid Radwaste System Preoperational Test ................ 14.2-44 14.2.12.1.18 Reactor Protection System Preoperational Test .......................... 14.2-45 14.2.12.1.19 Neutron Monitoring System Preoperational Test......................... 14.2-46 14.2.12.1.20 Traversing In-Core Probe System Preoperational Test ................. 14.2-47 14.2.12.1.21 Rod Worth Minimizer System Preoperational Test ...................... 14.2-47 14.2.12.1.22 Process Radiation Monitoring System Preoperational Test ............ 14.2-48 14.2.12.1.23 Area Radiation Monitoring System Preoperational Test................ 14.2-49 14.2.12.1.24 Process Computer Interface System Preoperational Test............... 14.2-50 14.2.12.1.25 Rod Sequence Control System Preoperational Test...................... 14.2-50 14.2.12.1.26 Remote Shutdown Preoperational Test .................................... 14.2-51 14.2.12.1.27 Offgas System Preoperational Test ......................................... 14.2-52 14.2.12.1.28 Environs Radiation Monitoring Preoperational Test .................... 14.2-53 14.2.12.1.29 Main Steam System Preoperational Test .................................. 14.2-53 LDCN-02-000                                       14-iv

COLUMBIA GENERATING STATION                                      Amendment 61 FINAL SAFETY ANALYSIS REPORT                                     December 2011 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                           Page 14.2.12.1.30 Radwaste Building Heating, Ventilating, and Air Conditioning System Preoperational Test................................................... 14.2-54 14.2.12.1.31 Closed Cooling Water System Preoperational Test ...................... 14.2-55 14.2.12.1.32 Primary Containment Atmospheric Control System Preoperational Test (SYSTEM DEACTIVATED) ......................... 14.2-55 14.2.12.1.33 Primary Containment Cooling System Preoperational Test ............ 14.2-56 14.2.12.1.34 Primary Containment Instrument Air Preoperational Test ............. 14.2-57 14.2.12.1.35 Primary Containment Atmospheric Monitoring System Preoperational Test ............................................................ 14.2-57 14.2.12.1.36 Standby Gas Treatment System Preoperational Test .................... 14.2-58 14.2.12.1.37 Loss of Power and Safety Testing Preoperational Test ................. 14.2-59 14.2.12.1.38 Instrument Power Preoperational Test .................................... 14.2-61 14.2.12.1.39 Emergency Lighting System Preoperational Test ........................ 14.2-61 14.2.12.1.40 Standby Alternating Current Power System Preoperational Test ..... 14.2-62 14.2.12.1.41 250-V Direct Current Power System Preoperational Test .............. 14.2-63 14.2.12.1.42 125-V Direct Current Power System Preoperational Test .............. 14.2-64 14.2.12.1.43 24-V Direct Current Power System Preoperational Test ............... 14.2-64 14.2.12.1.44 Plant Service Water System Preoperational Test ........................ 14.2-65 14.2.12.1.45 Standby Service Water System Preoperational Test ..................... 14.2-66 14.2.12.1.46 Plant Communications System Preoperational Test ..................... 14.2-67 14.2.12.1.47 Reactor Building Emergency Cooling System Preoperational Test ............................................................................... 14.2-67 14.2.12.1.48 Control, Cable, and Critical Switchgear Rooms Heating, Ventilating and Air Conditioning System Preoperational Test ......... 14.2-68 14.2.12.1.49 Standby Service Water Pump House Heating and Ventilating System Preoperational Test................................................... 14.2-68 14.2.12.1.50 Reactor Building Crane Preoperational Test ............................. 14.2-69 14.2.12.1.51 Primary Containment Integrated Leak Rate Preoperational Test ..... 14.2-70 14.2.12.1.52 Secondary Containment Integrated Leak Rate Preoperational Test ............................................................................... 14.2-71 14.2.12.1.53 Diesel Generator Building Heating and Ventilating System Preoperational Test ............................................................ 14.2-71 14.2.12.1.54 Seismic Monitoring System Preoperational Test ......................... 14.2-72 14.2.12.2 General Discussion of Startup Tests ........................................... 14.2-72 LDCN-11-000                                        14-v

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                          Page 14.2.12.3 Startup Test Procedures .......................................................... 14.2-73 14.2.12.3.1 Test Number 1 - Chemical and Radiochemical ............................ 14.2-73 14.2.12.3.1.1 Purpose ........................................................................ 14.2-73 14.2.12.3.1.2 Prerequisites .................................................................. 14.2-73 14.2.12.3.1.3 Description .................................................................... 14.2-73 14.2.12.3.1.4 Criteria ......................................................................... 14.2-74 14.2.12.3.2 Test Number 2 - Radiation Measurements .................................. 14.2-74 14.2.12.3.2.1 Purpose ........................................................................ 14.2-74 14.2.12.3.2.2 Prerequisites .................................................................. 14.2-74 14.2.12.3.2.3 Description .................................................................... 14.2-74 14.2.12.3.2.4 Criteria ......................................................................... 14.2-75 14.2.12.3.3 Test Number 3 - Fuel Loading ................................................ 14.2-75 14.2.12.3.3.1 Purpose ........................................................................ 14.2-75 14.2.12.3.3.2 Prerequisites .................................................................. 14.2-75 14.2.12.3.3.3 Description .................................................................... 14.2-76 14.2.12.3.3.4 Criteria ......................................................................... 14.2-76 14.2.12.3.4 Test Number 4 - Full Core Shutdown Margin.............................. 14.2-76 14.2.12.3.4.1 Purpose ........................................................................ 14.2-76 14.2.12.3.4.2 Prerequisites .................................................................. 14.2-76 14.2.12.3.4.3 Description .................................................................... 14.2-77 14.2.12.3.4.4 Criteria ......................................................................... 14.2-77 14.2.12.3.5 Test Number 5 - Control Rod Drive System ................................ 14.2-77 14.2.12.3.5.1 Purpose ........................................................................ 14.2-77 14.2.12.3.5.2 Prerequisites .................................................................. 14.2-77 14.2.12.3.5.3 Description .................................................................... 14.2-78 14.2.12.3.5.4 Criteria ......................................................................... 14.2-79 14.2.12.3.6 Test Number 6 - Source Range Monitor Performance and Control Rod Sequence .......................................................... 14.2-80 14.2.12.3.6.1 Purpose ........................................................................ 14.2-80 14.2.12.3.6.2 Prerequisites .................................................................. 14.2-80 14.2.12.3.6.3 Description .................................................................... 14.2-80 14.2.12.3.6.4 Criteria ......................................................................... 14.2-80 14.2.12.3.7 Test Number 7 ................................................................... 14.2-81 14.2.12.3.8 Test Number 8 ................................................................... 14.2-81 14.2.12.3.9 Test Number 9 ................................................................... 14.2-81 LDCN-02-000                                      14-vi

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                         Page 14.2.12.3.10 Test Number 10 - Intermediate Range Monitor System Performance.................................................................... 14.2-81 14.2.12.3.10.1 Purpose ....................................................................... 14.2-81 14.2.12.3.10.2 Prerequisites ................................................................. 14.2-81 14.2.12.3.10.3 Description................................................................... 14.2-81 14.2.12.3.10.4 Criteria ....................................................................... 14.2-81 14.2.12.3.11 Test Number 11 - Local Power Range Monitor Calibration ........... 14.2-82 14.2.12.3.11.1 Purpose ....................................................................... 14.2-82 14.2.12.3.11.2 Prerequisites ................................................................. 14.2-82 14.2.12.3.11.3 Description................................................................... 14.2-82 14.2.12.3.11.4 Criteria ....................................................................... 14.2-82 14.2.12.3.12 Test Number 12 - Average Power Range Monitor Calibration ........ 14.2-82 14.2.12.3.12.1 Purpose ....................................................................... 14.2-82 14.2.12.3.12.2 Prerequisites ................................................................. 14.2-82 14.2.12.3.12.3 Description................................................................... 14.2-82 14.2.12.3.12.4 Criteria ....................................................................... 14.2-83 14.2.12.3.13 Test Number 13 - Process Computer....................................... 14.2-83 14.2.12.3.13.1 Purpose ....................................................................... 14.2-83 14.2.12.3.13.2 Prerequisites ................................................................. 14.2-83 14.2.12.3.13.3 Description................................................................... 14.2-83 14.2.12.3.13.4 Criteria ....................................................................... 14.2-84 14.2.12.3.14 Test Number 14 - Reactor Core Isolation Cooling System ............. 14.2-85 14.2.12.3.14.1 Purpose ....................................................................... 14.2-85 14.2.12.3.14.2 Prerequisites ................................................................. 14.2-85 14.2.12.3.14.3 Description................................................................... 14.2-85 14.2.12.3.14.4 Criteria ....................................................................... 14.2-86 14.2.12.3.15 Test Number 15 ................................................................ 14.2-86 14.2.12.3.16 Test Numbers 16A and 16B.................................................. 14.2-86 14.2.12.3.16.1 Test Number 16A - Selected Process Temperatures................... 14.2-86 14.2.12.3.16.1.1 Purpose .................................................................... 14.2-86 14.2.12.3.16.1.2 Prerequisites .............................................................. 14.2-87 14.2.12.3.16.1.3 Description ................................................................ 14.2-87 14.2.12.3.16.1.4 Criteria..................................................................... 14.2-87 LDCN-02-000                                     14-vii

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                         Page 14.2.12.3.16.2 Test Number 16B - Water Level Reference Leg Temperature Measurement ................................................................. 14.2-88 14.2.12.3.16.2.1 Purpose .................................................................... 14.2-88 14.2.12.3.16.2.2 Prerequisites .............................................................. 14.2-88 14.2.12.3.16.2.3 Description ................................................................ 14.2-88 14.2.12.3.16.2.4 Criteria..................................................................... 14.2-89 14.2.12.3.17 Test Number 17 - System Expansion ....................................... 14.2-89 14.2.12.3.17.1 Purpose ....................................................................... 14.2-89 14.2.12.3.17.2 Prerequisites ................................................................. 14.2-89 14.2.12.3.17.3 Description................................................................... 14.2-89 14.2.12.3.17.4 Criteria ....................................................................... 14.2-92 14.2.12.3.18 Test Number 18 - Core Power Distribution............................... 14.2-92 14.2.12.3.18.1 Purpose ....................................................................... 14.2-92 14.2.12.3.18.2 Prerequisites ................................................................. 14.2-92 14.2.12.3.18.3 Description................................................................... 14.2-92 14.2.12.3.18.4 Criteria ....................................................................... 14.2-93 14.2.12.3.19 Test Number 19 - Core Performance....................................... 14.2-93 14.2.12.3.19.1 Purpose ....................................................................... 14.2-93 14.2.12.3.19.2 Prerequisites ................................................................. 14.2-93 14.2.12.3.19.3 Description................................................................... 14.2-94 14.2.12.3.19.4 Criteria ....................................................................... 14.2-94 14.2.12.3.20 Test Number 20 - Steam Production ....................................... 14.2-94 14.2.12.3.20.1 Purpose ....................................................................... 14.2-94 14.2.12.3.20.2 Prerequisites ................................................................. 14.2-95 14.2.12.3.20.3 Description................................................................... 14.2-95 14.2.12.3.20.4 Criteria ....................................................................... 14.2-95 14.2.12.3.21 Test Number 21 - Core Power-Void Mode ................................ 14.2-96 14.2.12.3.21.1 Purpose ....................................................................... 14.2-96 14.2.12.3.21.2 Prerequisites ................................................................. 14.2-96 14.2.12.3.21.3 Description................................................................... 14.2-96 14.2.12.3.21.4 Criteria ....................................................................... 14.2-96 14.2.12.3.22 Test Number 22 - Pressure Regulator ..................................... 14.2-96 14.2.12.3.22.1 Purpose ....................................................................... 14.2-96 14.2.12.3.22.2 Prerequisites ................................................................. 14.2-96 14.2.12.3.22.3 Description................................................................... 14.2-97 LDCN-02-000                                    14-viii

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                         Page 14.2.12.3.22.4 Criteria ....................................................................... 14.2-97 14.2.12.3.23 Test Number 23 - Feedwater System ....................................... 14.2-98 14.2.12.3.23.1 23A - Water Level Setpoint and Manual Flow Changes.............. 14.2-98 14.2.12.3.23.1.1 Purpose .................................................................... 14.2-98 14.2.12.3.23.1.2 Prerequisites .............................................................. 14.2-98 14.2.12.3.23.1.3 Description ................................................................ 14.2-98 14.2.12.3.23.1.4 Criteria..................................................................... 14.2-98 14.2.12.3.23.2 23B - Loss of Feedwater Heating ........................................ 14.2-100 14.2.12.3.23.2.1 Purpose .................................................................... 14.2-100 14.2.12.3.23.2.2 Prerequisites .............................................................. 14.2-100 14.2.12.3.23.2.3 Description ................................................................ 14.2-100 14.2.12.3.23.2.4 Criteria..................................................................... 14.2-100 14.2.12.3.23.3 22C - Feedwater Pump Trip .............................................. 14.2-101 14.2.12.3.23.3.1 Purpose .................................................................... 14.2-101 14.2.12.3.23.3.2 Prerequisites .............................................................. 14.2-101 14.2.12.3.23.3.3 Description ................................................................ 14.2-101 14.2.12.3.23.3.4 Criteria..................................................................... 14.2-101 14.2.12.3.23.4 23D - Maximum Feedwater Runout Capability ....................... 14.2-101 14.2.12.3.23.4.1 Purpose .................................................................... 14.2-101 14.2.12.3.23.4.2 Prerequisites .............................................................. 14.2-101 14.2.12.3.23.4.3 Description ................................................................ 14.2-101 14.2.12.3.23.4.4 Criteria..................................................................... 14.2-102 14.2.12.3.24 Test Number 24 - Turbine Valve Surveillance ............................ 14.2-103 14.2.12.3.24.1 Purpose ....................................................................... 14.2-103 14.2.12.3.24.2 Prerequisites ................................................................. 14.2-103 14.2.12.3.24.3 Description................................................................... 14.2-103 14.2.12.3.24.4 Criteria ....................................................................... 14.2-103 14.2.12.3.25 Test Number 25 - Main Steam Isolation Valves .......................... 14.2-104 14.2.12.3.25.1 25A - Main Steam Isolation Valve Function Tests..................... 14.2-104 14.2.12.3.25.1.1 Purpose .................................................................... 14.2-104 14.2.12.3.25.1.2 Prerequisites .............................................................. 14.2-104 14.2.12.3.25.1.3 Description ................................................................ 14.2-104 14.2.12.3.25.1.4 Criteria..................................................................... 14.2-104 14.2.12.3.25.2 25B - Full Reactor Isolation .............................................. 14.2-105 14.2.12.3.25.2.1 Purpose .................................................................... 14.2-105 14-ix

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                         Page 14.2.12.3.25.2.2 Prerequisites .............................................................. 14.2-105 14.2.12.3.25.2.3 Description ................................................................ 14.2-105 14.2.12.3.25.2.4 Criteria..................................................................... 14.2-105 14.2.12.3.26 Test Number 26 - Relief Valves ............................................. 14.2-106 14.2.12.3.26.1 Purpose ....................................................................... 14.2-106 14.2.12.3.26.2 Prerequisites ................................................................. 14.2-106 14.2.12.3.26.3 Description................................................................... 14.2-106 14.2.12.3.26.4 Criteria ....................................................................... 14.2-106 14.2.12.3.27 Test Number 27 - Turbine Trip and Generator Load Rejection ....... 14.2-107 14.2.12.3.27.1 Purpose ....................................................................... 14.2-107 14.2.12.3.27.2 Prerequisites ................................................................. 14.2-107 14.2.12.3.27.3 Description................................................................... 14.2-107 14.2.12.3.27.4 Criteria ....................................................................... 14.2-108 14.2.12.3.28 Test Number 28 - Shutdown From Outside the Main Control Room ............................................................................ 14.2-109 14.2.12.3.28.1 Purpose ....................................................................... 14.2-109 14.2.12.3.28.2 Prerequisites ................................................................. 14.2-110 14.2.12.3.28.3 Description................................................................... 14.2-110 14.2.12.3.28.4 Criteria ....................................................................... 14.2-110 14.2.12.3.29 Test Number 29 - Recirculation Flow Control ........................... 14.2-110 14.2.12.3.29.1 29A - Valve Position Control ............................................. 14.2-110 14.2.12.3.29.1.1 Purpose .................................................................... 14.2-110 14.2.12.3.29.1.2 Prerequisites .............................................................. 14.2-110 14.2.12.3.29.1.3 Description ................................................................ 14.2-110 14.2.12.3.29.1.4 Criteria..................................................................... 14.2-111 14.2.12.3.29.2 29B - Recirculation Flow Loop Control................................. 14.2-112 14.2.12.3.29.2.1 Purpose .................................................................... 14.2-112 14.2.12.3.29.2.2 Prerequisites .............................................................. 14.2-112 14.2.12.3.29.2.3 Description ................................................................ 14.2-112 14.2.12.3.29.2.4 Criteria..................................................................... 14.2-113 14.2.12.3.30 Test Number 30 - Recirculation System ................................... 14.2-115 14.2.12.3.30.1 30A - One Pump Trip ...................................................... 14.2-115 14.2.12.3.30.1.1 Purpose .................................................................... 14.2-115 14.2.12.3.30.1.2 Prerequisites .............................................................. 14.2-115 14.2.12.3.30.1.3 Description ................................................................ 14.2-115 14-x

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                         Page 14.2.12.3.30.1.4 Criteria..................................................................... 14.2-115 14.2.12.3.30.2 30B - Recirculation Trip of Two Pumps ................................ 14.2-116 14.2.12.3.30.2.1 Purpose .................................................................... 14.2-116 14.2.12.3.30.2.2 Prerequisites .............................................................. 14.2-116 14.2.12.3.30.2.3 Description ................................................................ 14.2-116 14.2.12.3.30.2.4 Criteria..................................................................... 14.2-116 14.2.12.3.30.3 30C - System Performance ................................................ 14.2-117 14.2.12.3.30.3.1 Purpose .................................................................... 14.2-117 14.2.12.3.30.3.2 Prerequisites .............................................................. 14.2-117 14.2.12.3.30.3.3 Description ................................................................ 14.2-117 14.2.12.3.30.3.4 Criteria..................................................................... 14.2-117 14.2.12.3.30.4 30D - Recirculation Pump Runback ..................................... 14.2-118 14.2.12.3.30.4.1 Purpose .................................................................... 14.2-118 14.2.12.3.30.4.2 Prerequisites .............................................................. 14.2-118 14.2.12.3.30.4.3 Description ................................................................ 14.2-118 14.2.12.3.30.4.4 Criteria..................................................................... 14.2-118 14.2.12.3.30.5 30E - Recirculation System Cavitation .................................. 14.2-118 14.2.12.3.30.5.1 Purpose .................................................................... 14.2-118 14.2.12.3.30.5.2 Prerequisites .............................................................. 14.2-118 14.2.12.3.30.5.3 Description ................................................................ 14.2-118 14.2.12.3.30.5.4 Criteria..................................................................... 14.2-119 14.2.12.3.31 Test Number 31 - Loss of Turbine-Generator and Offsite Power ..... 14.2-119 14.2.12.3.31.1 Purpose ....................................................................... 14.2-119 14.2.12.3.31.2 Prerequisites ................................................................. 14.2-119 14.2.12.3.31.3 Description................................................................... 14.2-119 14.2.12.3.31.4 Criteria ....................................................................... 14.2-119 14.2.12.3.32 Not Applicable ................................................................. 14.2-120 14.2.12.3.33 Test Number 33 - Piping Vibration......................................... 14.2-120 14.2.12.3.33.1 Purpose ....................................................................... 14.2-120 14.2.12.3.33.2 Prerequisites ................................................................. 14.2-120 14.2.12.3.33.3 Description................................................................... 14.2-120 14.2.12.3.33.4 Criteria ....................................................................... 14.2-120 14.2.12.3.34 Test Number 34 - Reactor Pressure Vessel Internals Vibration ....... 14.2-121 14.2.12.3.34.1 Purpose ....................................................................... 14.2-121 14.2.12.3.34.2 Prerequisites ................................................................. 14.2-121 14-xi

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 14 INITIAL TEST PROGRAM TABLE OF CONTENTS (Continued)
Section                                                                                         Page 14.2.12.3.34.3 Description................................................................... 14.2-121 14.2.12.3.34.4 Criteria ....................................................................... 14.2-122 14.2.12.3.35 Test Number 35 - Recirculation System Flow Calibration.............. 14.2-122 14.2.12.3.35.1 Purpose ....................................................................... 14.2-122 14.2.12.3.35.2 Prerequisites ................................................................. 14.2-122 14.2.12.3.35.3 Description................................................................... 14.2-122 14.2.12.3.35.4 Criteria ....................................................................... 14.2-123 14.2.12.3.36 Test Number 70 - Reactor Water Cleanup System ....................... 14.2-123 14.2.12.3.36.1 Purpose ....................................................................... 14.2-123 14.2.12.3.36.2 Prerequisites ................................................................. 14.2-123 14.2.12.3.36.3 Description................................................................... 14.2-123 14.2.12.3.36.4 Criteria ....................................................................... 14.2-123 14.2.12.3.37 Test Number 71 - Residual Heat Removal System ....................... 14.2-124 14.2.12.3.37.1 Purpose ....................................................................... 14.2-124 14.2.12.3.37.2 Prerequisites ................................................................. 14.2-124 14.2.12.3.37.3 Description................................................................... 14.2-124 14.2.12.3.37.4 Criteria ....................................................................... 14.2-124 14.2.12.3.38 Test Number 72 - Drywell Atmosphere Cooling System ................ 14.2-125 14.2.12.3.38.1 Purpose ....................................................................... 14.2-125 14.2.12.3.38.2 Prerequisites ................................................................. 14.2-125 14.2.12.3.38.3 Description................................................................... 14.2-125 14.2.12.3.38.4 Criteria ....................................................................... 14.2-125 14.2.12.3.39 Test Number 73 - Cooling Water Systems................................. 14.2-125 14.2.12.3.39.1 Purpose ....................................................................... 14.2-125 14.2.12.3.39.2 Prerequisites ................................................................. 14.2-125 14.2.12.3.39.3 Description................................................................... 14.2-125 14.2.12.3.39.4 Criteria ....................................................................... 14.2-126 14.2.12.3.40 Test Number 74 - Offgas System ............................................ 14.2-126 14.2.12.3.40.1 Purpose ....................................................................... 14.2-126 14.2.12.3.40.2 Prerequisites ................................................................. 14.2-126 14.2.12.3.40.3 Description................................................................... 14.2-126 14.2.12.3.40.4 Criteria ....................................................................... 14.2-127 14-xii

COLUMBIA GENERATING STATION                                      Amendment 53 FINAL SAFETY ANALYSIS REPORT                                     November 1998 Chapter 14 INITIAL TEST PROGRAM LIST OF TABLES Number                                  Title                                               Page 14.2-1 Preoperational Tests............................................................ 14.2-129 14.2-2 Major Plant Transients......................................................... 14.2-132 14.2-3 Stability Tests .................................................................... 14.2-133 14.2-4 Power Ascension Test Program............................................... 14.2-134 14-xiii

COLUMBIA GENERATING STATION                      Amendment 54 FINAL SAFETY ANALYSIS REPORT                     April 2000 Chapter 14 INITIAL TEST PROGRAM LIST OF FIGURES Number                                 Title 14.2-1      Test Condition Region Definition 14.2-2      Test and Startup Relation to Other Energy Northwest Departments 14.2-3      CGS Startup Organization 14.2-4      Preoperational Test Schedule 14.2-5      RCIC Acceptance Criteria Curves for Capacity and Actuation Time 14.2-6      Maximum Acceptable Drive Flow Response LDCN-99-000                               14-xiv

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998 Chapter 14 INITIAL TEST PROGRAM 14.1     SPECIFIC INFORMATION INCLUDED IN PRELIMINARY SAFETY ANALYSIS REPORTS The initial test program overall test objectives and general prerequisites were previously provided in the Preliminary Safety Analysis Report (PSAR). The technical aspects of the initial test program are described in Section 14.2 in sufficient detail to show that the test program adequately verifies the functional requirements of plant structures, systems, and components such that the safety of the plant will not be dependent on untested structures, systems, or components.
14.1-1

COLUMBIA GENERATING STATION                            Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998 14.2    SYSTEM LINEUP, PREOPERATIONAL, AND INITIAL STARTUP TEST PROGRAM The italicized information is historical and was provided to support the application for an operating license.
The initial test program consisted of a series of tests categorized as system lineup testing, preoperational, and initial startup tests. The system lineup testing determines correct installation and functional operability of equipment. Preoperational tests are those tests normally conducted prior to fuel loading to demonstrate the capability of plant systems to meet performance requirements. Initial startup tests began with fuel loading and demonstrated the capability of the integrated plant to meet performance requirements.
14.2.1      

==SUMMARY==
OF TEST PROGRAM AND OBJECTIVES 14.2.1.1       Initial Test Program Objectives The objectives of the initial test program are to
: a.       Ensure that the construction is complete and acceptable,
: b.       Demonstrate the capability of structures, components, and systems to meet performance requirements,
: c.       Effect fuel loading in a safe manner,
: d.       Demonstrate, where practical, that the plant is capable of withstanding anticipated transients and postulated accidents,
: e.       Evaluate and demonstrate, to the extent possible, plant operating procedures to provide assurance that the operating group is knowledgeable about the plant and procedures and fully prepared to operate the facility in a safe manner, and
: f.       Bring the plant to rated capacity and sustained power operation.
14.2.1.2       Initial Test Program Summaries The three categories of tests in the initial test program are summarized below:
: a.       System lineup tests such as pump and valve tests, mechanical actuation to verify proper installation, and electrical continuity verifications, are those tests which demonstrate that components are correctly installed and operational.
14.2-1

COLUMBIA GENERATING STATION                            Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998
: b. Preoperational tests conducted prior to fuel loading to demonstrate that the plant systems have been properly designed and that they meet performance requirements.
: c. Startup tests consist of fuel loading, precritical tests, low power tests, and power ascension tests that ensure fuel loading in a safe manner, confirm the design bases, demonstrate where practical that the plant is capable of withstanding the anticipated transients and postulated accidents, and ensure that the plant is safely brought to rated capacity and sustained power operation.
14.2.1.3      Description of System Lineup Tests Typical system lineup tests generally include but are not limited to the following:
: a.      Chemical cleaning and flushing of systems, tanks, and vessels,
: b. Electrical equipment to test and/or energize, e.g., grounding, relays, circuit breaker operation and controls, continuity, megger, phasing, high potential measurements, and buses,
: c. Initial adjustment, bumping, and running of rotating equipment,
: d.      Checking control and interlock functions of instruments, relays, and control devices,
: e. Calibrating instruments and checking or setting initial trip setpoints,
: f. Pneumatic testing of instruments and service air system and cleanout of lines,
: g.      Checking and adjusting relief and safety valves,
: h. Complete tests of safety-related motor-operated valves including adjusting torque switches and limit switches, checking all interlocks and controls, measuring motor current and operating speed, and checking leaktightness of stem packing and valve seat during hydrotests; and complete tests of the nuclear steam supply system (NSSS) control systems including checking all interlocks and controls, adjusting limit switches, measuring operating speed, checking leaktightness of pneumatic operators, and checking for proper operation of controllers, pilot solenoids, etc., and
: i. Other tests and verifications such as structural, leaktightness, and vibration.
14.2-2

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998 14.2.1.4       Description of Preoperational Tests A listing of the preoperational tests is provided in Table 14.2-1. The general objectives of the preoperational test phase are as follows:
: a.      Ensure that test acceptance criteria are met,
: b.      Provide documentation of the performance and safety of equipment and systems,
: c.      Provide baseline test and operating data on equipment and systems for future reference,
: d.      Run-in of a system for a sufficient period so that any design, manufacturing, or installation defects can be detected and corrected,
: e.      Ensure that plant systems operate together on an integrated basis to the extent possible,
: f.      Give maximum opportunity to the permanent plant operating staff to obtain practical experience in the operation and maintenance of equipment and systems,
: g.      Establish safe and efficient normal, abnormal, and emergency operating procedures, to the extent possible,
: h.      Establish and evaluate surveillance testing procedures, and
: i.      Demonstrate that systems and safety equipment are operational and that it is possible to proceed to fuel loading and to the Startup Phase.
14.2.1.5       Description of Startup Tests The Power Ascension Test Phase (PATP) begins after the Preoperational Test Phase has been completed. The Power Ascension Test Phase begins with fuel loading and extends to commercial operation. This phase is subdivided into the following four parts:
: a.      Open vessel testing (fuel loading and shutdown power level tests),
: b.      Initial heatup,
: c.      Power testing, and
: d.      Warranty demonstration.
The tests conducted during the Power Ascension Test Phase consist of major plant transients (Table 14.2-2), stability tests (Table 14.2-3), and a remainder of tests which are directed 14.2-3

COLUMBIA GENERATING STATION                          Amendment 54 FINAL SAFETY ANALYSIS REPORT                         April 2000 towards demonstrating correct performance of the nuclear boiler and numerous auxiliary plant systems while at power. Certain tests may be identified with more than one class of test.
Table 14.2-4 shows the complete Power Ascension Test Program. Figure 14.2-1 provides test conditions region definition.
The general objectives of the Power Ascension Test Phase are as follows:
: a.      Achieve an orderly and safe initial core loading,
: b.      Accomplish all testing and measurements necessary to determine that the approach to initial criticality and subsequent power ascension is safe and orderly,
: c.      Conduct low power physics tests sufficient to ensure that test acceptance criteria have been met,
: d.      Conduct initial heatup and hot functional testing so that hot integrated operation of all systems is shown to meet test acceptance criteria,
: e.      Conduct an orderly and safe power ascension program, with requisite physics and systems testing, to ensure that the plant operating at power meets test acceptance criteria, and
: f.      Conduct a successful warranty demonstration program.
14.2.2      ORGANIZATION AND STAFFING 14.2.2.1       General The Energy Northwest Test and Startup Program is administered by two entities with distinct levels of responsibility and two distinct organizations.
For the system lineup test phase and the preoperational test phase, the Test Working Group (TWG) provides review, approval, and planning of general Test and Startup Program activities and the results of those activities. The Test and Startup organization and qualified members of other organizations represented on the TWG provide the necessary development, implementation, and analysis of Test and Startup Program activities at the working level.
For the Power Ascension Test Phase, the Plant Operations Committee (POC) provides review and planning of the test program and evaluates the test results. The Plant Manager approves the procedures and final test reports. The implementation of the PATP is achieved with the normal plant operations crew operating the plant and test engineers under the direction of the Reactor Engineering Supervisor coordinating the test activities.
LDCN-99-000                                     14.2-4

COLUMBIA GENERATING STATION                           Amendment 54 FINAL SAFETY ANALYSIS REPORT                          April 2000 14.2.2.2      Definitions The definitions of phrases used in this section and throughout this chapter are as follows:
: a. Test Working Group (TWG) - a project onsite administrative body whose membership consists of personnel representing organizations directly responsible for preparation and performance of testing and startup during the system lineup and preoperational test phases. This group provides review and approval of test preparation and performance activities.
: b. Power Generation - an Energy Northwest organization within the Operations Directorate with responsibility for development and implementation of the Test and Startup Program.
: c. Columbia Generating Station (CGS) Test and Startup - a Power Generation division with responsibility for development and implementation of the CGS Test and Startup Program.
: d. CGS Plant Organization - a Power Generation division with responsibility to startup, operate, and maintain CGS in compliance with Federal, State, local, and owner requirements.
: e. CGS Plant Operations Committee (POC) - refer to definition in Section 13.4.1.
The POC reviews the activities of the Power Ascension Test Phase.
: f. Test and Startup Manager - the Power Generation Division Manager with responsibility for implementation of the CGS Test and Startup Program.
: g. Test and Startup Program - the program that encompasses the transition from construction to commercial operation and consists of system lineup testing, preoperational testing, and power ascension testing.
: h. Test and Startup Program Manual - the manual that defines generic administrative policy and procedures for the initial testing and startup of Energy Northwest nuclear facilities.
: i. Test and Startup Instructions - the specific instructions required to implement the Test and Startup Program for an individual project.
: j. Plant Procedure Manual (PPM) - the Plant Manager approved procedures for operating the plant. The PPMs include the test procedures for the PATP.
LDCN-99-000                                    14.2-5

COLUMBIA GENERATING STATION                          Amendment 54 FINAL SAFETY ANALYSIS REPORT                         April 2000 14.2.2.3       Test and Startup Program Organization and the System Lineup and Preoperational Test Program 14.2.2.3.1          General Power Generation is an organization within the Energy Northwest Operations Directorate.
Relative to the Program, Power Generation is responsible for development and administration of plans, policies, and administrative procedures; procurement of test equipment and other test-related resources, and assignment of the CGS Test and Startup Manager. The Power Generation organization and its relationship to other Energy Northwest organizations is shown in Figure 14.2-2.
14.2.2.3.2          Responsibilities of CGS Test and Startup Division CGS Test and Startup is a Division of the Power Generation organization. The CGS Test and Startup Manager manages an organization comprised of Energy Northwest test engineers and test technicians augmented by test personnel from the architect-engineer, the NSSS supplier, and others as contractually established. The CGS Test and Startup Manager is responsible for the development and implementation of the CGS Test and Startup program and those responsibilities are described in Section 14.2.2.3.3. The CGS Test and Startup staff organization is shown in Figure 14.2-3.
14.2.2.3.3          CGS Test and Startup Department Position Responsibilities 14.2.2.3.3.1 CGS Test and Startup Manager.
: a.      Chairman, TWG;
: b.      Develop plans, schedules, methods, procedures, and data systems for the testing and evaluation of all plant equipment and systems to permit acceptance and licensing;
: c.      Administer and coordinate the testing activities with other organizations involved in the Test and Startup Program;
: d.      Manage and direct assigned test personnel in activities relating to the attainment of Test and Startup Program objectives;
: e.      Manage and direct assigned test personnel to establish qualitative and quantitative acceptance criteria and develop test procedures to direct and guide performance of testing, and LDCN-99-000                                   14.2-6

COLUMBIA GENERATING STATION                         Amendment 54 FINAL SAFETY ANALYSIS REPORT                        April 2000
: f.      Provide recommendations and effect actions to eliminate equipment or system deficiencies as determined by Test and Startup Program criteria which could adversely affect performance of safety-related functions.
14.2.2.3.3.2 CGS Test Group Manager.
: a.      Represent Test and Startup on the TWG;
: b.      Coordinate the activities of Test Group Supervisors and test engineers during the Test and Startup Program;
: c.      Develop, monitor, and coordinate the preparation and implementation of plans, schedules, methods, and procedures for testing and evaluation of plant systems and components for verification of performance and acceptance;
: d.      Maintain surveillance over testing performed by Energy Northwest and others, including system and equipment tests, and calibration of instrumentation;
: e.      Identify problem areas and recommend actions where deficiencies could adversely affect the performance, safety-related functions, or operating efficiency;
: f.      Assist in preparation of program status and other Test and Startup Program related reports, and
: g.      Assume the responsibilities of the Test and Startup Manager as described in the Test and Startup Program Manual (TSPM) during his absence and all other responsibilities specifically delegated.
14.2.2.3.3.3 CGS Test Group Supervisor. Test Group Supervisors are assigned lead technical responsibility for testing. General Test Group Supervisors duties are as follows:
: a.      Supervise the activities of assigned test engineers;
: b.      Review and, where appropriate, approve test procedures, field changes to procedures and test results, and make recommendations to the Test Group Managers or Startup Manager, as appropriate;
: c.      Set schedules and priorities for assigned Test Engineers and assist them with problem resolution; LDCN-99-000                                     14.2-7

COLUMBIA GENERATING STATION                          Amendment 54 FINAL SAFETY ANALYSIS REPORT                         April 2000
: d. With other Test Group Supervisors and the Test Group Manager or Startup Manager, as appropriate, plan and coordinate startup activities and provide assistance;
: e. Advise the Test Group Manager or Test and Startup, as appropriate, on all matters concerning testing within their group and if required, attend TWG meetings for this purpose;
: f. Act for the Test Group Manager or Test and Startup Manager, as appropriate, when so delegated;
: g. Prepare for and perform testing as required to support the Test and Startup Program;
: h. Coordinate the identification and documentation of design problems and their resolution, and
: i. Advise the Test Group Manager or Test and Startup Manager, as appropriate, regarding current and future manpower requirements impacting the testing effort.
14.2.2.3.3.4 CGS Test Engineers. Test engineers provide for the routine development and implementation of testing. General test engineer duties are as follows:
: a. Prepare assigned test procedures,
: b. Review tests and inspections prepared by others for application to assigned testing responsibilities,
: c. Provide direction during performance of system and component testing, and
: d. Identify problem areas and recommend actions where deficiencies could adversely affect performance of safety-related functions or operating efficiency.
14.2.2.4      Plant Operations Organization and the Power Ascension Test Program The PATP will be carried out by the plant operations organization using test procedures developed and approved according to the requirements of the PPM. The PATP procedures were prepared by members of the plant technical department under the supervision of the Reactor Engineering Supervisor. Technical expertise from other Energy Northwest organizations and from the General Electric Company (GE), the NSSS vendor, was used whenever necessary. Review of these procedures and scheduling of the test activities will be carried out by the POC and approved by the Plant Manager. The Reactor Engineering LDCN-99-000                                  14.2-8

COLUMBIA GENERATING STATION                       Amendment 53 FINAL SAFETY ANALYSIS REPORT                      November 1998 Supervisor will direct the PATP test engineers in the completion of testing according to the POC schedule.
14.2.2.5        Test Working Group 14.2.2.5.1       System Lineup and Preoperational Test Program The purpose of the TWG, a composite of representatives from organizations directly responsible for preparation, performance, and review of Test and Startup Program activities, is to provide a means for a coordinated review of all testing concerns and ensuring all obligations to the Test and Startup Program are met by the organizations represented.
The TWG provides review and approval of all activities proposed and the results thereof as appropriate. All decisions and approvals or recommendations of the group are included in the minutes of the meetings. Matters requiring approval by the TWG includes, but are not limited to
: a.      System lineup procedures,
: b.      Preoperational test procedures,
: c.      Changes to test procedures, and
: d.      Results of testing.
14.2.2.5.2           Membership and Responsibility of the Test Working Group The TWG membership consist of organizations that have a direct support function for conduct or development of testing.
The CGS Test and Startup Manager is Chairman of the TWG and is responsible for convening and conducting TWG meetings on the administrative and technical content of program activities.
The Test Group Manager is responsible for providing a technical review of the proposed activities, technical documents, and their results. The Test Group Manager serves as Chairman during the absence of the Test and Startup Manager.
The CGS Plant Manager is responsible for providing an operational review of test documents and for submitting safety-related documents to the POC for review and for communicating the committees decisions to the TWG. The Plant Manager provides detailed plant operating procedures and surveillance procedures to be used for plant operation and testing during the Test and Startup Program system lineup and preoperational test phase.
14.2-9

COLUMBIA GENERATING STATION                           Amendment 54 FINAL SAFETY ANALYSIS REPORT                          April 2000 The plant quality assurance representative to the TWG shall be responsible for review of proposed activities, test procedures, and test results as required by the Operational Quality Assurance Program Description (OQAPD).
The project engineering representative is responsible for obtaining a technical review of proposed activities and test documents by assigned project engineers and for providing a working relationship with Energy Northwest and architect-engineering organizations to aid resolution of testing concerns.
Conditional Members are representative of any organization having responsibility and/or expertise in the area of the TWG meeting agenda. In this situation the representative will be requested to attend the meeting by the TWG chairman.
14.2.2.6       Plant Organization Functions and Responsibilities During All Testing and Plant Operations The plant organization has overall responsibility for the safe and efficient operation of plant systems and equipment, from provisional acceptance through commercial operation including responsibility for maintenance and operational control. Plant organization responsibilities in supporting the Test and Startup Program are discussed in Section 14.2.2.7.1.
The responsibility of the plant organization representative to the TWG is defined in Section 14.2.2.5.2.
14.2.2.7       Energy Northwest Support of the Test and Startup Program 14.2.2.7.1          Plant Organization In addition to the responsibilities described in Section 14.2.2.6, the plant operating, technical, and maintenance sections provide manpower for development, implementation, and review of testing.
14.2.2.7.1.1 Support During Test and Startup Program Development. Assistance during the development of the Test and Startup Program is provided formally through the plant organizations TWG representative and through the POC. Input to test procedures and other testing documentation by the plant staff ensures that
: a. The operational requirements of the test procedures are based on the knowledge and experience of the operating staff,
: b. The technical considerations receive the review of the Plant Technical Staff, and LDCN-99-000                                   14.2-10

COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                           December 2003
: c.      Important nuclear and operational safety considerations receive attention by the plant organization.
14.2.2.7.1.2 Support During Testing. Detailed review and analysis of system lineup and preoperational test results will be performed by the plant technical section and/or plant operations section where their particular expertise is deemed necessary by the plant representative to the TWG to support approvals of completed system lineup and preoperational tests.
Detailed review and analysis of PATP test results will be carried out by the test engineers of the plant operations technical department and will receive final review through the POC and final approval by the Plant Manager.
14.2.2.7.2          CGS Program The CGS Program Director is responsible for the performance of the organizations involved in the design, procurement, and construction of generating projects. The Program Director supports the Test and Startup Program by providing and implementing project control systems, project engineering services, and engineering support services.
The CGS Program Director supports the Test and Startup Program by maintaining a high level of current status information available to the startup program organizations to ensure that all startup program scheduling and preparation is based on an accurate assessment of the condition of systems and equipment being readied for testing. The Program Director provides liaison with Construction Management for the provision of construction craft support for the implementation of various system lineup and preoperational tests.
14.2.2.7.3          Plant Quality Assurance The functions of the plant Quality Assurance organization during the Test and Startup Program will be to survey ongoing efforts to determine that the controls required by various regulations, guides, and standards are effectively implemented. The activities of the TWG will be monitored to ensure that the proper degrees of control for safety-related activities are being maintained and that required activities are completed when they are prerequisite to another testing activity.
14.2.2.8       Architect-Engineer Support of the Test and Startup Program Burns and Roe, Inc., is responsible for providing engineering services required to ensure timely completion of construction testing and equipment turnover for provisional acceptance and system turnover. Burns and Roe also provides system-oriented engineers to assist the CGS Test and Startup Divisions, as requested by Energy Northwest technical direction and/or advice and consultation during system and component testing through preoperational testing.
LDCN-02-000                                  14.2-11

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 14.2.2.9       General Electric Support of the Test and Startup Program General Electric is the supplier of the boiling water reactor (BWR) NSSS for the CGS plant.
General Electric is responsible for generic and specific CGS designs and for the supply of the NSSS. During the construction phase of the plant cycle, the GE Resident Site Manager is responsible for all NSSS equipment disposition. When the startup testing phase of the project begins after fuel load, the responsibility of GE-NSSS activities are assigned to the Preoperational and Startup group. The GE Preoperational and Startup staff responsibilities are outlined below.
14.2.2.9.1          Staff Responsibilities 14.2.2.9.1.1 General Electric Operations Manager. The GE Operations Manager is the senior NSSS vendor representative onsite at or near official fuel loading, and is the official site spokesman for GE for preoperational and startup testing concerns and requirements. The Operations Manager coordinates with the Startup Superintendent for the performance of his duties, which are as follows:
: a.      Reviewing all NSSS test procedures, including changes to test procedures, and test results as a conditional member of TWG and POC,
: b.      Providing technical direction to the station staff,
: c.      Managing the activities of the GE site personnel in providing technical direction to CGS personnel in the testing and operation of GE-supplied systems,
: d.      Providing liaison between the site and the GE San Jose home office to provide rapid and effective solution to problems that cannot be solved onsite,
: e.      Participating as a conditional member of the TWG when required, and
: f.      Reviewing test procedures for the POC.
14.2.2.9.1.2 General Electric Operations Superintendent. The GE Operations Superintendent is responsible to the GE Operations Manager for supervising the activities of GE Shift Superintendents. He works directly with the CGS Operations Manager in providing GE technical direction to the operating organization.
14.2.2.9.1.3 General Electric Shift Superintendents. The GE shift superintendents provide technical direction to CGS shift personnel in the testing and operation of GE-supplied systems.
They provide 24-hr per day shift coverage as required beginning with fuel loading. They report to the GE Operations Superintendent.
14.2-12

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 14.2.2.9.1.4 General Electric Lead Engineer - Startup Test, Design, and Analysis. The GE lead engineer - Startup Test, Design, and Analysis, is responsible to the GE Operations Manager for supervising the GE shift engineers and for verifying core physics parameters and characteristics and documenting that performance of the NSSS and components conform to test acceptance criteria.
The lead engineer works with the CGS technical department to coordinate and effect implementation of the PATP instrumentation including special test equipment required to confirm these acceptance criteria.
14.2.2.10      Qualifications of Personnel Supporting the Test and Startup Program The qualifications described in this section are for those persons having authority to direct testing, review and approve test documentation and results, or otherwise have direct influence on the conduct of testing and quality of acquired data. Although other personnel, specifically GE, Burns and Roe, and Energy Northwest technical specialists, are also involved in these processes, they are under the direction of individuals whose qualifications are described herein and who review and approve all Test and Startup Program activities.
14.2.2.10.1         Test and Startup Program Department Personnel Qualifications
: a.      At the time of appointment to the active position, the CGS Test and Startup Manager shall have 10 years of responsible thermal power plant experience such as, but not limited to, managerial, technical, or administrative positions, of which a minimum of 3 years shall be nuclear power plant experience.
A maximum of 4 years of the remaining 7 years of experience may be fulfilled by academic training on a one-to-one basis. This academic training shall be in engineering or the individual shall have acquired the experience and training normally required for examination by the NRC for a senior operator license whether or not the examination is taken.
: b.      Minimum qualifications for Test Group Manager are a B.S. degree in engineering or related field and 6 years of applicable experience, at least 3 of which are in testing or operation of nuclear power generation, propulsion, or similar scale test or production facilities. Related experience may be substituted for academic requirements when the candidates professional background and level of achievement clearly demonstrate capabilities to fill the position.
Previous preoperational testing experience is required. A good understanding of quality assurance and regulatory requirements and an ability to effectively communicate with others are necessities. A demonstrated technical leadership in his discipline and necessary work experience at the Test Group Supervisor or equivalent level is evidence of required proficiency.
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COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003
: c.      Minimum qualifications for Test Group Supervisor are a B.S. degree in engineering or related field and 5 years of applicable experience, at least 2 of which are in testing or operation of nuclear power generation, propulsion, or similar scale test or production facilities. Related experience may be substituted for academic requirements when the candidates professional background and level of achievement clearly demonstrate capabilities to fill the position.
Previous preoperational testing experience is required. A good understanding of quality assurance and regulatory requirements and an ability to effectively communicate with others are necessities. A demonstrated technical leadership in his discipline and necessary work experience at the Senior Test Engineer or equivalent level is evidence of required proficiency.
: d.      Minimum qualifications for a Test Engineer directing preoperational tests are a B.S. degree in engineering or related field or a graduate of a technical or vocational school in an engineering or related field and 2 years of related experience. Related experience above the required minimum may be substituted for academic requirements when the candidates record for performance clearly indicates the ability to fill the position without question. A good understanding of engineering principles and the ability to understand new concepts and to effectively communicate with others is a necessity.
Minimum requirements for a Test Engineer directing startup tests are a B.S.
degree in engineering or related field and 2 years of related experience or a graduate of a technical or vocational school in an engineering or related field, and 3 years of related experience. Related experience above the required minimum may be substituted for academic requirements when the candidates record for performance clearly indicates the ability to fill the position without question. A good understanding of engineering principles and the ability to understand new concepts and to effectively communicate with others is a necessity.
14.2.2.10.2        Plant Organization Personnel Qualifications Qualifications of some plant personnel are discussed in Section 13.1.3.
14.2.3     TEST PROCEDURES 14.2.3.1      Development of Test Procedures Test Procedures are developed by the CGS Test and Startup or Plant Operations Department to provide a detailed method to demonstrate the capability of the system to perform its design function under anticipated operating and accident condition.
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COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 General Electric Company as supplier of the NSSS provides test program specifications and instructions from which Energy Northwest prepares the preoperational and initial startup test procedures for systems supplied by GE.
Architect-Engineer and Vendors Technical assistance is provided by Burns and Roe and vendor technical representatives as deemed necessary.
14.2.3.1.1          Incorporation of Plant Procedures The following program will be implemented at CGS to utilize and qualify plant operating procedures during testing.
: a.      Plant procedures required to support testing will have been prepared and approved before preoperational testing begins on the system using the best information available from the principal designer and responsible equipment suppliers.
: b.      Preoperational test procedures will use plant operating and emergency procedures as nearly as possible.
: c.      Using the results of preoperational testing, including the use-testing of plant procedures where practical, the plant procedures required to support startup testing will be updated and revised before startup testing of applicable systems.
Exceptions to this program will be those approved plant procedures required to be verified during the startup phase.
: d.      Startup test procedures will be developed using the results of preoperational testing and updated plant procedures.
14.2.3.1.2          Format of Test Procedures 14.2.3.1.2.1 Preoperational Test Phase. The minimum content requirements for CGS Preoperational test procedures are specified in the Energy Northwest TSPM. The format for CGS test procedures is specified in the CGS TSPM. The resulting format and content is the following:
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COLUMBIA GENERATING STATION                              Amendment 57 FINAL SAFETY ANALYSIS REPORT                            December 2003
: a. Preoperational Test Procedure Format
: 1. Purpose A concise description of the objectives of the test, including such test requirements as component functions to be checked and testing under normal or simulated conditions to verify readiness for system startup and operation, and system tests to confirm that the performance of the system is in compliance with all applicable design requirements.
: 2. Prerequisites Provisions necessary for performance of the test. Conditions that should exist prior to start of the test. Instructions given to identify required operational status of the plant and interfacing systems, environmental conditions, and individual component status requirements, including verification of the following:
(a)      Components and systems being tested have been turned over and open deficiencies will not affect the performance of the test, (b)      System lineup testing on components, included in the test, is complete, (c)      Necessary support systems are available, and (d)      For control system testing, the other principal control systems are in appropriate operating modes for the given test conditions.
: 3. Limits and Precautions Special precautions required for safety of personnel and equipment or needed to ensure a meaningful test and satisfactory performance of testing.
: 4. Special Equipment A list of special material and equipment for the performance of the test.
: 5. Procedure A step by step procedure for performing the test. Plant operating procedures will be utilized whenever practicable for the operation of 14.2-16

COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                           December 2003 systems and equipment during testing and for returning the system to normal after completion of testing. Abnormal procedures will be utilized as required to supplement normal plant operating procedures. Data collection will be part of the procedure steps.
: 6. Restoration Includes those steps necessary to return the system to a normal operating or tagged status. This may include removal of special test instruments, temporary equipment, electrical jumpers, valve lineups, etc.
: 7. Acceptance Criteria The criteria against which the success or failure of the test will be judged must be identified. In some instances, these will be qualitative criteria, e.g., given event does or does not occur. In other cases, quantitative values can be designated as acceptance criteria.
(a)     All quantitative acceptance criteria shall include suitable tolerances, and (b)     A readily apparent correlation should exist to cross-reference among procedure steps, data, and acceptance criteria.
: 8. References A listing of all material required for the preparation and performance of the test. This should include piping and instrumentation drawings, electrical elementary drawings, vendor instruction manuals, applicable FSAR sections, contract specifications, and applicable codes, standards or guides, and applicable plant procedures.
14.2.3.1.2.2 Power Ascension Test Phase. All PATP procedures will be formatted according to the PPM.
14.2.3.2     Review of Test Procedures Each member of the TWG ensures test procedures will provide for review with respect to that members organizational area of responsibility. Power ascension test procedures will be reviewed by the POC.
Comments submitted by TWG members will be evaluated by the TWG and the test procedure revised accordingly. After discussion of the resulting version, the decision to reject, accept, or 14.2-17

COLUMBIA GENERATING STATION                        Amendment 57 FINAL SAFETY ANALYSIS REPORT                       December 2003 accept with modification, will be obtained by consensus of the membership of the TWG. In the event the TWG cannot reach a consensus, the Chairman shall provide resolution or a method for resolving the issue to the appropriate division management for review and concurrence.
The results of the POC review of PATP will be approved by the Plant Manager.
The qualifications of the individuals or organization representatives reviewing test procedures are described in Section 14.2.2.10.
The administrative procedures governing the test procedure review process are contained in the CGS TSPM. These procedures cover the mechanism for review and comment resolution, documentation of this review, and method of indication for the review status of a test procedure.
14.2.3.3       Approval of Test Procedures Test procedures will be approved by the TWG Chairman by means of consensus of the TWG membership after review of the test procedure as described in Section 14.2.3.2. Power ascension test procedures will be reviewed by the POC in a similar manner.
Individual test procedures will be approved by the chairman of the TWG or POC/Plant Manager, as appropriate. The consensus of the two committees were contained in the meeting minutes.
The administrative procedures governing the exercise of approval of test procedures are contained in the CGS TSPM or the PPM.
14.2.4      CONDUCT OF TEST PROGRAM 14.2.4.1       Administrative Procedures for Preoperational Testing 14.2.4.1.1           Test Performance Authorization A significant period of time may have elapsed between the time a preoperational test procedure was approved and the time a test is performed. The test procedure is therefore reviewed just prior to initiating the test. Any changes in the system since original approval of the test procedure will be thoroughly researched and the test procedure revised and approved in accordance with Sections 14.2.3.2 and 14.2.3.3. The CGS Test and Startup Manager will then approve the test procedure for performance of the test.
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COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                           December 2003 14.2.4.1.2          Preoperational Test Prerequisites Approval by the Test and Startup Manager to perform a preoperational test also requires consideration of the prerequisite testing required to qualify components and systems for operation. In general, completion of the system lineup testing (see Section 14.2.1.3) will qualify the system for preoperational testing. System lineup testing, as a prerequisite to preoperational testing, includes the following:
: a.      Instrumentation and protective relay checks, including calibration, setpoint adjustments, logic verification, and line checks;
: b.      Component operability checks, including valve stroking, motor rotation, ventilation system balancing, rotating equipment run-in and pipe support inspection and adjustment;
: c.      Flushing, including proof flushes, flow instrumentation response, and pump performance and capacity checks;
: d.      Electric component and system checks, including breaker trip setpoints; and
: e.      Hydrostatic or pneumatic pressure tests and systems where dynamic testing, such as pump runs, are required to allow performance of pressure tests.
Pressure integrity tests are otherwise performed during construction testing.
Verification that required system lineup tests have been or can be successfully completed prior to preoperational testing is performed by the respective test group manager prior to recommending turnover of a system or component from a contractor to Energy Northwest.
Verification that the system is actually ready for preoperational testing will be performed as described in Section 14.2.4.3.
14.2.4.1.3          Conduct of Preoperational Testing
: a.      Implementation responsibilities for scheduling all tests are assigned to the CGS Test and Startup Manager. The TWG will be kept informed of the scheduled activities.
: b.      The satisfaction of prerequisites to commencement of the test, as indicated in the test procedure, will be verified by the test engineer prior to performance of the test.
: c.      The assigned test engineer is responsible for directing the performance of each test. Testing is performed in direct coordination between the test engineer and shift supervision.
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COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003
: d. All testing will be conducted in accordance with approved test procedures. If, during the performance of a test the procedure is unacceptable, the test engineer can propose changes by use of a Test Change Notice (see Section 14.2.4.4).
This provided both documentation of the change and confirmation by the TWG.
: e. All test data will be entered on or attached to the record copy of the test procedure.
14.2.4.1.4          Deficiency Reporting Deficiencies or discrepancies identified during testing will be reported individually as described in Section 14.2.5.2.
Corrective action or satisfactory disposition shall be taken on all deficiencies and discrepancies in equipment and procedures prior to final approval of the preoperational test results. All deficiencies or discrepancies identified during the test, or which have not been resolved on completion of the test, will be recorded in the record copy of the preoperational test.
14.2.4.1.5          Equipment Maintenance and Modifications During Preoperational Testing Modifications or repair to safety-related systems will be implemented as a result of a formal system of problem and deviation reporting. Disposition of problems requiring mechanical or electrical changes or repairs by contractors will be implemented by work requests.
: a. Startup Problem Reports (SPR), Startup Deficiency Reports (SDR), and Startup Work Requests (SWR) are administered through closed-loop procedural controls to ensure resolutions. A completed SPR, SDR, and SWR is approved for closure by the respective Test Group Manager.
: b. Startup Problem Reports are used to report design deficiencies and are coordinated by the Energy Northwest project engineering organization for resolution by the responsible design organization or qualified alternate. The SPRs are reviewed by engineering and a Project Engineering Directive (PED) is issued to define plant modifications or changes that are required. An SWR is then issued to perform the plant modification by contractor personnel or an SDR is issued to defer the work or have it performed by startup personnel.
: c. Startup Deficiency Reports (SDR) are used to report and track non-design-related deficiencies. If required, an SWR will be issued to perform the repair work to resolve the non-design-related deficiency by contractor personnel. Work accomplished by startup personnel can be accomplished by the SDR without issuing an SWR.
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COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003
: d.      Retest requirements will be identified on the SWR or SDR and attached to, or referenced by the work request number in test files.
: e.      Startup Problem Reports, SDR, SWR, design change documentation, retest results, and procurement records for safety-related systems will be filed in assembled packages or with appropriate cross-referencing for retrievability.
14.2.4.1.6          Preoperational Test Summary During the preoperational test, the test engineer will prepare a test report which includes a summary of the conduct of the test, evaluation of the test results with reference to the acceptance criteria, and a description of problems encountered and corrective actions taken or proposed. This report will be attached to the record copy of the test.
14.2.4.1.7          Evaluation of Preoperational Test Data On completion of the test, a copy of the official test procedure, data, the test summary, and other applicable attachments will be transmitted to each member of the TWG responsible for review.
14.2.4.1.8          Preoperational Test Records The Test and Startup Manager will maintain all official test records (the copy of the test procedure containing the original test data and signatures and all attachments) until completion of the test program. See Section 14.2.6 for details of the test records handling and retention program.
14.2.4.2       Administrative Procedures for Power Ascension Testing 14.2.4.2.1          Plant Operation During Power Ascension Testing During initial startup tests and operations, the plant procedures are followed except as specifically modified by approved test procedures. In addition, special safety precautions and limitations are included in the test procedures. Approved test procedures will be used to control test conditions outside of the Technical Specifications limits where allowed for test purposes.
Certain individual tests or power escalations may require authorization by both the POC and the Plant Manager immediately prior to implementation and will be so identified in the applicable test procedure.
14.2-21

COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                           December 2003 The final authority to start or continue a test is the responsibility of the Shift Manager after all previous approvals have been exercised. Testing is performed in direct coordination between the test engineer and Shift Manager.
14.2.4.2.2           Power Ascension Test Scheduling and Sequencing Scheduling and sequencing of testing during startup is performed under the direction of the Plant Manager by POC.
The startup or power ascension test sequence is described in terms of individual test evolutions and specific power plateaus due to interfaces with other simultaneous tests, requirements for continuous data review, and plant administrative requirements for authorization to proceed or continue. The test sequence identifies hold points for data review and authorization to proceed and establishes the general plant conditions for each group of tests.
14.2.4.2.3           Power Ascension Test Performance Before starting each test, the assigned shift test engineer will review the test procedure to ensure that prerequisite activities of conditions have been satisfied as described in Section 14.2.4.3.
The test will be stopped or curtailed if it cannot be performed safely or in accordance with the approved test procedure. Required test procedure deviations or changes may be effected in accordance with PPM 1.2.3, Use of Plant Procedures, as described in Section 14.2.4.4.2.
Should apparent deviations of test results from performance requirements or acceptance criteria be revealed, or should other apparent anomalies develop, the plant will be placed in a safe condition and relevant test data will be reviewed by the test engineer and Shift Manager.
If the apparent discrepancy or anomaly is substantiated, the situation will be reviewed by the POC to ascertain if a plant safety question is involved. Control of any identified nonconformance or noncompliance will be in accordance with the plant administrative procedures.
Evaluation of the effect of the discrepancy or anomaly on plant safety will be performed at the appropriate level of review, and appropriate corrective actions will be taken before resumption of the test or test conditions at which the problem was revealed.
At the completion of an entire test procedure, the test engineer will assemble all of the data and supporting information, nonconformance documentation, and test results evaluations for review by the POC. Any data reduction or analysis required will be done as soon after the data is available as is practical so that the results of the analysis may be included in the complete test package.
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COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 Test records will be maintained as described in Section 14.2.6.
14.2.4.3       Control of Test Prerequisites Conditions and activities prerequisite to a given test will be identified in the applicable test procedure. Prior to commencement of the particular test, the test engineer will verify that the identified prerequisites have been satisfied. The verifications will be recorded and retained as part of the test record.
The test engineer will verify that
: a.      The test procedure has been approved by the appropriate committee and Plant Manager, Test and Startup Manager, or Startup Superintendent as required.
The test procedure is compatible with the latest versions of material referenced in the test procedure;
: b.      The record copy of the test procedure is identical to that contained in the master file or PPM, including the latest TWG/POC approved revisions or test procedure field changes (see Section 14.2.4.4);
: c.      Prerequisite tests have been completed. If TWG and/or Plant Manager approval of a completed test is also a prerequisite, that approval will have been obtained;
: d.      The test procedure has been made available for shift operator review and familiarization. Operator support has been scheduled, as necessary;
: e.      Test equipment is available or in place as required. Calibration or other readiness requirements have been completed. System instrumentation to be used in the test has been calibrated within the required time period established for surveillance testing and/or preventative maintenance; and
: f.      Test and operating personnel involved in the performance of the test have been briefed immediately prior to starting the test.
14.2.4.4       Modification of Test Procedures During Testing 14.2.4.4.1           System Lineup and Preoperational Test Phase The TSPM provides a means of controlling modifications to TWG-approved test procedures during testing. This administrative procedure, contained in the CGS TSPM, applies to changes made to an approved test procedure during preoperational and startup testing. The procedure does not apply to revisions made during the preparation of test procedures.
14.2-23

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 The procedure provides control of revisions which change the intent or the acceptance criteria of the test procedure.
The required changes, when identified by the responsible test engineer, are described on a special form (Test Change Notice/Procedure Deviation Form) which identifies the affected test procedure or plant procedure, justifies the change, and contains spaces for the appropriate approvals. The Test Change Notice forms became a permanent part of the test record.
A Test Change Notice for a preoperational test is reviewed by the TWG and approved by the Test and Startup Manger, TWG Chairman.
14.2.4.4.2          Power Ascension Test Phase All test procedure details or changes must be made in accordance with PPM 1.2.3, Use of Plant Procedures. This process requires documentation on the required forms, signatures of authorized individuals, and subsequent full POC review. The PPM 1.2.3 forms became a permanent part of the test record.
14.2.5      REVIEW, EVALUATION, AND APPROVAL OF TEST RESULTS 14.2.5.1       Control of Test Results Review The individuals responsible for reviewing the results of particular tests will be designated by the POC or the Test and Startup Manager. These reviews will be obtained through TWG or POC members in accordance with their represented areas of responsibility. TWG members will provide names of individuals in their represented organizations who meet the requirements of Regulatory Guide 1.58, Revision 0, for evaluation of inspection and test results.
Based on the recommendations of the qualified reviewers, the completed preoperational test will be approved by the TWG. Plant Operating Committee review and Plant Manager approval of power ascension test results is required.
14.2.5.2       Design Organization Participation in Problem Resolution Failures of tests to meet acceptance criteria and other problems discovered in the course of testing will be documented as deficiencies in accordance with the requirements of the TSPM for System Lineup and Preoperational Tests and in accordance with PPM 1.3.12, Plant Nonconformances, for the power ascension tests. Reports of such deficiencies will indicate the parties or organizations deemed responsible for providing an acceptable resolution of the deficiency. The responsible organization will be requested to provide a resolution of the defined problem.
14.2-24

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 Documentation of the final resolution will include the recommendation of the responsible organization and a description of the measures implemented in accordance with that recommendation. Design problems will require resolution by the appropriate Energy Northwest Technical Division Department, Project Engineering, Plant Technical Staff, or original design organization, depending on the technical nature of the problem.
14.2.5.3       Results Analysis Prerequisites to Continuation of Startup Testing The POC will establish prerequisites for various tests, test conditions, and test phases in consideration of system or component qualification for subsequent testing. The control or prerequisites to an individual test will be as described in Section 14.2.4.3.
The POC will also require an evaluation of the data acquired during a particular test phase or plateau. The items considered in this evaluation will include, but are not limited to the following:
: a.      The need for additional testing or retesting to improve assurance that a particular system or component will perform as required in subsequent testing, especially under more demanding conditions such as higher power levels,
: b.      The need for analysis of certain data to qualify measured variables or parameters for use in subsequent measurements,
: c.      The completeness of testing up to the point in question as evidenced by the documentation of the completed tests, and
: d.      The need for specific reviews and approvals of particular sets of data to satisfy the above.
14.2.6      TEST RECORDS 14.2.6.1       System Lineup and Preoperational Test Phase 14.2.6.1.1          General The TSPM contains a generic procedure regarding filing and recordkeeping to be applied to testing documentation. This procedure is intended to ensure compliance of Energy Northwest project startup programs with the applicable provisions of ANS N45.2.9-1974, Requirements for Collection, Storage, and Maintenance of Nuclear Power Plant Quality Assurance Records, as required by Regulatory Guide 1.88, Revision 1, December 1975.
The following sections describe the provisions of the aforementioned procedure, which will be contained in specific detail in the CGS Test and Startup Instructions.
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COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 14.2.6.1.2          Test Record Responsibilities The Test and Startup Manager is responsible for identifying the responsibilities, controls, and requirements for establishing and implementing a Test and Startup Program filing and recordkeeping system, in accordance with 10 CFR 50 Appendix B, ANSI N45.2.9, and the Energy Northwest Quality Assurance Program Manual. The Test and Startup Manager will ensure that adequate procedures are prepared and maintained within the Test and Startup Instructions. The Test and Startup Manager will ensure that trained and qualified personnel maintain the Test and Startup Program files.
14.2.6.1.3          Types of Documents and Records Requiring Test Record File Retention Documentation and records that will be maintained within Test and Startup Program files are:
: a. Test and Startup program records as specified by ANSI N45.2.9, and
: b. All records and documents as specified by the Test and Startup Program and instruction manuals.
Other records, documents, correspondence, etc., may be maintained at the discretion and approval of the Startup Program Manager, provided their access requirements do not compromise the security of the mandatory files.
14.2.6.2       Power Ascension Test Phase All test records and data shall be kept and filed in accordance with the PPM 1.6 series of procedures which detail the requirements for all plant recordkeeping.
14.2.7      CONFORMANCE OF TEST PROGRAMS WITH REGULATORY GUIDES 14.2.7.1       Conformance with Regulatory Guide 1.68 The CGS Test and Startup Program conforms to the requirements of Regulatory Guide 1.68, Revision 0, Preoperational and Initial Startup Test Programs for Water-Cooled Power Reactors, except where specifically noted otherwise. The Regulatory Guide has been reviewed by Energy Northwest for applicability of individual items in the guide to CGS and its systems. The applicability to this plant has determined the nature and scope of testing to be performed. Actual exceptions to the testing required by this guide have been specifically addressed and are discussed in Section 14.2.7.2. Areas where the guide does not apply are not considered to be exceptions.
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COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 14.2.7.2        Exceptions to Regulatory Guide 1.68 The exceptions to Regulatory Guide 1.68 are listed below with an explanation of the justification for the exception.
: a.      Exception to Format of Test Procedures The format of the test procedures is different from that found in Appendix C of Regulatory Guide 1.68, but the format difference is not considered an exception to the regulatory guide since the guide specifies required elements of a test procedure while merely implying but not requiring a format.
: b.      See Section 1.8.2 for a delineation of specific exceptions to the requirements of Regulatory Guide 1.68.
14.2.7.3        Conformance With or Exceptions to Regulatory Guides Other Than 1.68
: a.      Regulatory Guide 1.70, Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants will be complied with for the section that pertains to the Test and Startup Program,
: b.      Regulatory Guide 1.33, Quality Assurance Program Requirements will be complied with in Quality Assurance During the Operations Phase, Section 17.2, of the FSAR for the Test and Startup Program,
: c.      All other regulatory guides pertaining to individual testing will be complied with unless noted otherwise in Section 14.2.12, and
: d.      Regulatory Guide 1.58 Qualifications of Nuclear Power Plant Inspection, Examination, and Testing Personnel. Energy Northwest Test and Startup personnel involved in testing meet the requirements of Regulatory Guide 1.58.
14.2.8      UTILIZATION OF REACTOR OPERATING AND TESTING EXPERIENCES IN THE DEVELOPMENT OF THE TEST PROGRAM As a matter of Energy Northwest policy, a continuous program of review of reactor operating experience is coordinated by the Operations Division of Energy Northwest. The sources of information reviewed in compliance with this policy are NRC Information Notices and Bulletins, operating experience reports, preoperational test summaries and startup reports from other plants, administrative and test procedures from other plants startup programs, personal contacts with other nuclear plant licensees or applicants, and additional information supplied by Energy Northwest Technical and Operations Division members. All available sources are 14.2-27

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 utilized; relevance to particular Energy Northwest nuclear projects is determined in the review process.
The information is reviewed by CGS Startup Program personnel for applicability to the CGS Test and Startup Program, for incorporation into test procedures, or for consideration in the administrative control of testing.
14.2.9      TRIAL USE OF PLANT OPERATING AND EMERGENCY PROCEDURES To the extent practical throughout the preoperational and initial PATP, test procedures utilize operating, emergency, and abnormal procedures where applicable in the performance of tests.
The use of these procedures is intended to do the following:
: a.      Prove the specific procedure or illustrate changes which may be required,
: b.      Provide training of plant personnel in the use of these procedures, and
: c.      Increase the level of knowledge of plant personnel on the systems being tested.
Test procedures may use operating, emergency, and abnormal procedures in several ways: the test procedure may reference the procedure directly; the test procedure may extract a series of steps from the procedure; the test procedure may use a combination of the first two methods; or the test procedure may require system and plant conditions that will be obtained by the use of plant operating or emergency procedures.
14.2.10     INITIAL FUEL LOADING AND INITIAL CRITICALITY 14.2.10.1      Fuel Loading and Shutdown Power Level Tests Fuel loading and initial criticality is conducted in accordance with written procedures after all prerequisite tests are satisfactorily completed and an operating license has been issued. Prior to approving fuel loading, the plant must be verified as ready to load fuel. This verification is accomplished by the following steps, which are performed at the completion of a majority of the preoperational testing.
14.2.10.1.1         Loss of Power Demonstration-Standby Core Cooling Required This test demonstrates the capability of each emergency diesel generator to start automatically and assumes all of its emergency core cooling loads in a loss of normal auxiliary power.
14.2.10.1.2         Cold Functional Testing The cold functional testing defined here is an integrated system operation of various plant systems that can be operated as systems prior to fuel loading. The intent is to observe any unexpected operational problems from either an equipment or a procedural source and to 14.2-28

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 provide an opportunity for operator familiarizations with the system-operating procedures under operating conditions.
Some of the cold functional testing will be accomplished during the preoperational test program. For example, integrated and simultaneous operation of the following systems may take place during the flush of the total system: condensate system, condensate demineralizer system, low-pressure coolant injection (LPCI) system, core spray system, reactor water cleanup (RWCU) system, service water system, closed cooling water (RCC) system, and others.
As required, additional integrated systems performance will be demonstrated prior to fuel loading.
14.2.10.1.3          Routine Surveillance Testing Because of the interval between completion of a preoperational test on a system and the requirement for that system to be operated may be of considerable length, a number of routine surveillance tests must be performed prior to fuel loading and must be repeated on a routine basis. The Technical Specifications described the test frequency. In general, this Surveillance Test Program (specified in the Technical Specifications) is instituted prior to fuel loading by the plant operating staff.
14.2.10.1.4          Master Startup Checklist A detailed list of items that must be complete, including the preoperational tests, work requests, design changes, and proper dispositioning of all exceptions noted during preoperational testing listed in Table 14.2-1 is rechecked to verify completion just prior to the final approvals for fuel loading and at each significant new step such as heat up, opening main steam isolation valves (MSIVs), and power operation.
14.2.10.1.5          Initial Fuel Loading Fuel loading requires the movement of the full core complement of assemblies from the fuel pool to the core, with each assembly identified by number before being placed in the correct coordinate position. The procedure controlling this movement is arranged so that shutdown margin and subcritical checks are made at predetermined intervals throughout the loading, thus ensuring safe loading increments. Specially sensitive invessel neutron monitors that are maintained at the loading face as loading progresses serve to provide indication for the shutdown margin measurements, and also to allow the recording of the core flux level as each assembly is added. A complete check is made of the fully loaded core to ascertain that all assemblies are properly installed, correctly oriented, and are occupying their designated positions.
14.2-29

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 14.2.10.1.6          Zero Power Level Tests At this point in the program, a number of tests are conducted which are best described as initial zero power level tests. Chemical and radiochemical tests are made to check the quality of the reactor water before fuel is loaded, and to establish base and background levels required to facilitate later analysis and instrument calibrations. Plant and site radiation surveys are made at specific locations for later comparison with the values obtained at the subsequent operating power levels. Shutdown margin checks are repeated for the fully loaded core, and criticality is achieved with each of the two prescribed rod sequences in turn, the data being recorded for each rod withdrawn. Each rod drive is subjected to scram and performance testing. The initial setting of the intermediate range monitors (IRMs) is at maximum gain.
14.2.10.2       Initial Heatup to Rated Temperature and Pressure Heatup follows the satisfactory completion of the fuel loading and zero power level tests (Sections 14.2.10.1.5 and 14.2.10.1.6) and further checks are made of coolant chemistry together with radiation surveys at the selected plant locations. All control rod drives (CRDs) are scram-timed at rated temperature and pressure, with selected drives timed at two intermediate reactor pressures and for different accumulator pressures. The process computer checkout continues as more process variables become available for input. The reactor core isolation cooling (RCIC) system will complete controlled starts at low reactor pressure and at rated conditions, with testing in the quick-start mode at 150 psig and 1000 psig. Correlations are obtained between reactor vessel temperatures at several locations and the values of other process variables as heatup continues. The movements of NSSS piping in the drywell mainly as a function of expansion are recorded for comparison with design data.
14.2.10.3       Power Testing From 25% to 100% of Rated Output The power test phase comprises the following tests, many of which are repeated several times at the different test levels; consequently, see Table 14.2-4 for the series. While a certain basic order of testing is maintained relative to power ascension, there is, nevertheless, considerable flexibility in the test sequence at a particular power level which may be used whenever it becomes operationally expedient. In no instance, however, is nuclear safety compromised.
: a.      Coolant chemistry tests and radiation surveys are made at each principal test level to preserve a safe and efficient power increase,
: b.      Selected CRDs are scram-timed at various power levels to provide a correlation with the initial data,
: c.      The effect of control rod movement on other parameters (e.g., electrical output, steam flow, and neutron flux level) is examined for different power conditions, 14.2-30

COLUMBIA GENERATING STATION                            Amendment 59 FINAL SAFETY ANALYSIS REPORT                           December 2007
: d. Following the first reasonable, accurate heat balance (25% power) the average power range monitors (APRMs) are calibrated and IRMs are reset if necessary,
: e. At each major power level (25%, 60%, and 100%), the local power range monitors (LPRMs) are calibrated,
: f. The APRMs are calibrated initially at each new power level and following LPRM calibration,
: g. Completion of the process computer checkout is made for all variables, and the various options are compared with hand calculations as soon as significant power levels are available,
: h. Further tests of the RCIC are made with and without injection into the reactor pressure vessel (RPV),
: i. Collection of data from the system expansion tests is completed for those piping systems which had not previously reached full operating temperatures,
: j. The axial and radial power profiles are explored fully by means of the traversing in-core probe (TIP) system at representative power levels during the power ascension, and
: k. Core performance evaluations are made at all test points above the 10% power level and for selected flow transient conditions; the work involves the determination of core thermal power, maximum fuel rod surface heat flux, and minimum critical power ratio (MCPR), and other thermal parameters.
: l. Overall plant stability in relation to minor perturbations is shown by the following group of tests which are made at selected test points:
: 1.      Core power-void mode response,
: 2.      Pressure regulator setpoint change,
: 3.      Water level setpoint change,
: 4.      Turbine valve surveillance, and
: 5.      Recirculation flow setpoint change.
For the first of these tests, a centrally located control rod is moved and the flux response is noted on a selected LPRM chamber. The next two tests require that the changes made should approximate as closely as possible a step change in demand, while for the next test the turbine stop, control, and bypass valves are opened to verify stability and power level for surveillance testing. The remaining test is performed to properly adjust the control loop of the LDCN-06-000                                 14.2-31

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 recirculation system. For all of these tests the plant performance is monitored by recording the transient behavior of numerous process variables, the one of principal interest being neutron flux. Other imposed transients are produced by step changes in demand core flow, partial loss of feedwater heating, and simulating failure of the operating pressure regulator to permit takeover by the backup regulator. Table 14.2-3 shows the power and flow levels at which all these stability tests are performed.
: m. The category of major plant transients includes full closure of all the MSIVs, fast closure of turbine generator control valves, fast closure of turbine generator stop valves, loss of the main generator and offsite power, tripping a feedwater pump, and several trips of the recirculation pumps. The plant transient behavior is recorded for each test and the results may be compared with the acceptance criteria and the predicted design performance. Table 14.2-2 shows the operating test condition for all the proposed major transients;
: n. A test is made of the relief valves in which leaktightness and general operability are demonstrated;
: o. At some major power levels the jet pump flow instrumentation is calibrated;
: p. The as-built characteristics of the recirculation system are investigated as soon as operating conditions permit full core flow; and
: q. The local control loop performance, based on the drive pump, jet pumps, and control equipment is checked.
14.2.11    TEST PROGRAM SCHEDULE The test program schedule for preoperational and startup tests are indicated in Table 14.2-4 and Figure 14.2-4. These schedules are preliminary and will be adjusted to consider actual construction and testing progress; they are included to provide general information but are not considered to be identical to the schedules in use during the startup program. The test procedures will be made available for review at least 30 days prior to the test date or fuel load.
14.2.12    INDIVIDUAL TEST DESCRIPTIONS 14.2.12.1     Preoperational Test Procedures The following general descriptions are the specific objectives of each preoperational test.
During the final construction phase, it may be necessary to modify the preoperational test methods as operating and preoperational test procedures are developed. Consequently, methods described in the following descriptions are general, not specific.
14.2-32

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 Specific acceptance criteria for each preoperational test are in accordance with the detailed system and equipment specifications for equipment in those systems. The tests demonstrate that the installed equipment and systems perform within the limits of these specifications.
In addition to the prerequisites listed on each on the following preoperational tests, there will be electrical power available to each of the systems.
Table 14.2-1 lists the preoperational tests anticipated for this facility.
14.2.12.1.1          Reactor Feedwater System Preoperational Test
: a.      Purpose To verify the operation of the reactor feedwater system, including pumps, valves, turbines, turbine auxiliaries, and turbine control systems.
: b.      Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The condensate system, control air system, and service water system must have a readiness verification.
: c.      General Test Methods and Acceptance Criteria The performance of the reactor feedwater system is verified within the limitations of the auxiliary steam supply by the demonstration of the proper operation of the following:
: 1.       Valves and related controls, interlocks, and position indicators,
: 2.       Reactor feedwater pumps, turbines, and auxiliaries,
: 3.       Control logic, and
: 4.       Annuciators and protective devices.
14.2.12.1.2          Condensate System Preoperational Test
: a.      Purpose To verify the operation of the condensate system, including pumps, valves, and control systems.
14.2-33

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The condenser, condensate filter demineralizers, feedwater, and control air systems are capable of supporting this test as necessary.
: c. General Test Methods and Acceptance Criteria The performance of the condensate system is verified by the demonstration of the proper operation of the following:
: 1.       Valves and related controls, interlocks, and positions indicators,
: 2.       Condensate pumps, condensate booster pumps and auxiliaries,
: 3.       Control logic, and
: 4.       Annuciators and protective devices.
14.2.12.1.3      Fire Protection System Preoperational Test
: a. Purpose To verify the operation of the fire protection system including the diesel engine, pumps, valves, detection and alarm circuits, and control and instrumentation circuits. To verify the location and status of all portable equipment.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The circulating water system, control and service air system, and electrical distribution system are available to support operation.
: c. General Test Methods and Acceptance Criteria Verification of the fire protection system capability is demonstrated by the proper integrated operation of the following:
: 1.       Diesel engine and pump operation and related control and logic,
: 2.       Fire alarm and detection circuits,
: 3.       Fire control panel in the main control room,
: 4.       Deluge, wet pipe and preaction sprinkler systems, and
: 5.       Carbon dioxide and Halon systems.
14.2-34

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 In addition, portable equipment and hose station capability will be verified.
14.2.12.1.4      Reactor Water Cleanup System Preoperational Test
: a. Purpose To verify the operation of the RWCU system, including pumps, valves, and filter/demineralizer equipment.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Filter aid, and anion and cation resin should be available.
The RCC system and instrument air system must have readiness verification.
: c. General Test Methods and Acceptance Criteria Verification of the RWCU system capability is demonstrated by the proper integrated operation of the following:
: 1.       Drain flow regulator flow interlocks,
: 2.       System isolation and logic,
: 3.       Valve-operating sequence,
: 4.       Pump operation and related control and logic,
: 5.       Annuciators, and
: 6.       Filter/demineralizer system operation.
14.2.12.1.5      Standby Liquid Control System Preoperational Test
: a. Purpose To verify the operation of the standby liquid control (SLC) system including pumps, tanks, control, logic, and instrumentation.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Valves should be previously bench tested and other precautions relative to positive displacement pumps taken. The reactor vessel should be available for injecting demineralized water.
14.2-35

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003
: c. General Test Methods and Acceptance Criteria Verification of the SLC system capability is demonstrated by the proper integrated operations of the following:
: 1.       SLC system tank level instrumentation,
: 2.       Heaters,
: 3.       Alarms and logic,
: 4.       Relief valves,
: 5.       Pumps and related controls and logic, and
: 6.       Flow testing with different flow paths.
14.2.12.1.6      Nuclear Boiler System Preoperational Test
: a. Purpose To verify proper operation of the nuclear boiler system including safety/relief valves (SRVs) and related controls and logic.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Verify that all SRVs have been previously bench tested.
: c. General Test Methods and Acceptance Criteria Functional and capacity tests of SRVs are not performed; verification of the NSSS capability is demonstrated by the proper integrated operation of the following:
: 1.       System valves and related sensors and logic,
: 2.       Vacuum breaker in relief valve discharge lines,
: 3.       Automatic isolation function of reactor water sample isolation valves,
: 4.       Isolation and leak detection systems,
: 5.       Automatic depressurization system logic,
: 6.       Reactor vessel actuators accumulator capacity test,
: 7.       Safety/relief valves air piston operation,
: 8.       Reactor head seal leak detection, and
: 9.       Alarms and annunciators.
14.2-36

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 14.2.12.1.7      Residual Heat Removal System Preoperational Test
: a. Purpose To verify the operation of the residual heat removal (RHR) system under its various modes of operation: LPCI, shutdown cooling and vessel head spray, containment spray, and suppression pool water cooling.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The RHR service water system must have readiness verification. The reactor vessel and recirculation loops shall be intact and capable of receiving water.
: c. General Test Methods and Acceptance Criteria Verification of the RHR system capability is demonstrated by the proper integrated operation of the following:
: 1.       System isolation valve control and logic tests,
: 2.       RHR and RHR service water pump and motor operation, controls, and related logic features,
: 3.       Automatic LPCI initiation logic,
: 4.       Verification of all flow paths. The time from initiation signal to full flow should be verified, and
: 5.       Alarms and annunciators.
14.2.12.1.8      Reactor Core Isolation Cooling System Preoperational Test
: a. Purpose To verify the operation of the RCIC system including turbine, pump, valves, instrumentation, and control.
14.2-37

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The turbine, disconnected from the pump, shall be tested.
The turbine instruction manual shall be reviewed in detail in order that precautions relative to turbine operation are followed. Then the system shall be tested within the capability of a temporary steam supply with the pump coupled to the turbine.
: c. General Test Methods and Acceptance Criteria
: 1.       All valves and related controls, interlocks, and indicators,
: 2.       Manual and automatic initiation,
: 3.       Automatic isolation, including leak detection system logic,
: 4.       Turbine speed control, trip, mode selection, and test mode,
: 5.       Barometric condenser condensate pump, and vacuum pump controls,
: 6.       Flow path verification, and
: 7.       Annunciators.
14.2.12.1.9      Reactor Recirculation System and Control Preoperational Test
: a. Purpose To verify the operation of the reactor recirculation system including pumps and their associated motors, valves, instrumentation, and controls. The rated conditions tests will be conducted during the startup testing program.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The RCC system must receive readiness verification. All required testing of equipment up to the operation of the recirculation pump has been completed, including recirculation pump motor (uncoupled) and all control loops.
: c. General Test Methods and Acceptance Criteria After prerequisite testing, verification of system capability is demonstrated by the proper integrated operation of the following:
: 1.       System valves, 14.2-38

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003
: 2.       Logic and interlocks,
: 3.       Recirculation pumps, valves, and related controls and interlocks,
: 4.       Annunciators, and
: 5.       Low frequency motor generator (LFMG) set.
14.2.12.1.10      Reactor Manual Control System Preoperational Test
: a. Purpose To verify the operation of the reactor manual control (RMC) system, including relays, control circuitry, switches and indicating lights, and control valves.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The CRD pump will not be operational during this test.
: c. General Test Methods and Acceptance Criteria Verification of RMC system capability is demonstrated by the proper integrated operation of the following:
: 1.       Rod blocks, alarms, and interlocks for all modes of the reactor mode switch,
: 2.       Rod position information system,
: 3.       Rod drift alarm circuit, and
: 4.       Rod directional control valve time sequence for insert and withdraw commands.
14.2.12.1.11      Control Rod Drive Hydraulic System Preoperational Test
: a. Purpose To verify the operation of the CRD hydraulic system including CRD mechanisms, hydraulic control units, hydraulic power supply, instrumentation, and controls.
14.2-39

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The CRD manual control system preoperational test must be completed on associated CRDs. The RCC system and instrument air system must receive readiness verification.
: c. General Test Methods and Acceptance Criteria Verification of CRD system capability is demonstrated by the proper integrated operation of the following:
: 1.       Logic and interlocks,
: 2.       CRD pumps and related controls and interlocks,
: 3.       Flow controller, pressure control valves, and stabilizer valves,
: 4.       Scram discharge level switches and CRD position indication, alarms, and interlocks,
: 5.       CRDs functional testing including latching and position indication,
: 6.       Scram testing of control rods at atmospheric pressure, and
: 7.       Annunciators.
14.2.12.1.12      Fuel Handling and Vessel Servicing Equipment Preoperational Test
: a. Purpose To verify the operation of the fuel handling and vessel servicing equipment including tools used in the servicing of control rods, fuel assemblies, LPRMs and dry tubes, and vacuum cleaning equipment.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Additionally, the refueling platform, fuel preparation machine, and fuel racks must be installed and operational; all slings and lifting devices must be certified at their design load, at least by the vendor.
14.2-40

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003
: c. General Test Methods and Acceptance Criteria Verification of the fuel handling and vessel servicing equipment is demonstrated by dry operation of the following equipment:
: 1.       Cell disassembly tools,
: 2.       Channel replacement tools,
: 3.       Instrument handling tools,
: 4.       Vacuum cleaning equipment,
: 5.       Interlocks and logic associated with the refueling and service platform are verified, and
: 6.       Proper operation of refueling and service platforms are verified.
14.2.12.1.13      Low-Pressure Core Spray System Preoperational Test
: a. Purpose To verify the operation of the low-pressure core spray system (LPCS), including spray pumps, sparger ring, spray nozzles, controls, valves, and instrumentation.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The reactor vessel must be available and ready to receive water.
: c. General Test Methods and Acceptance Criteria Verification of the LPCS system capability is demonstrated by the proper integrated operation of the following:
: 1.       Logic and interlocks,
: 2.       Low-pressure core spray system pumps, including auto initiation, 14.2-41

COLUMBIA GENERATING STATION                             Amendment 57 FINAL SAFETY ANALYSIS REPORT                            December 2003
: 3.       Flow path verification, including determination of system hydraulic performance to verify proper sizing of restricting orifice in LPCS discharge line to vessel (see Section 6.3.2.2.3),
: 4.       Annunciators,
: 5.       The time for initiation signal to full flow should be verified, and
: 6.       Photographs to prove acceptability of core spray patterns.
14.2.12.1.14      High-Pressure Core Spray System Preoperational Test
: a. Purpose To verify the operation of the high-pressure core spray (HPCS) system, including diesel generator and related auxiliary equipment, pumps, valves, instrumentation, and control.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The HPCS diesel generator must be installed and be operational.
: c. General Test Methods and Acceptance Criteria Verification of HPCS system capability is demonstrated by the proper integrated operation of the following:
: 1.       Valve controls and interlocks,
: 2.       HPCS electrical system tests, including dc and ac,
: 3.       HPCS diesel generator functional tests including starting, rated load, load rejection,
: 4.       Pump and motor tests with normal power supply and with diesel generator,
: 5.       HPCS flow path and flow rate verification,
: 6.       Annunciators, 14.2-42

COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                           December 2003
: 7.       The time from initiation signal to full flow should be verified, and
: 8.       Photographs to prove acceptability of HPCS spray pattern.
14.2.12.1.15      Fuel Pool Cooling and Cleanup System Preoperational Test
: a. Purpose To verify the operation of the fuel pool cooling and cleanup system including the pumps, heat exchangers, controls, valves, and instrumentation.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The instrument air, service air, fuel pool emergency makeup, service water, and RHR systems must be available.
: c. General Test Methods and Acceptance Criteria Verification of the fuel pool system capability is demonstrated by the integrated operation of the following:
: 1.       Logic and interlocks,
: 2.       Interconnection to RHR system,
: 3.       Pump operation and related controls,
: 4.       Cleanup subsystem operation, and
: 5.       Annunciators.
14.2.12.1.16      Leak Detection System Preoperational Test
: a. Purpose To summarize the test requirements and verify the leak detection test data for each of the nuclear systems.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The prerequisites are included in the preoperational test specifications for each of the nuclear systems listed below.
14.2-43

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003
: c. General Test Methods and Acceptance Criteria As an integral part of each of the following system preoperational tests, the nuclear systems leak detection is verified by the proper operation of the leak detection features of the following nuclear systems:
: 1.       Feedwater control system,
: 2.       RWCU system,
: 3.       NSSS,
: 4.       RHR system,
: 5.       RCIC system,
: 6.       Recirculation system, and
: 7.       Radwaste system.
14.2.12.1.17      Liquid and Solid Radwaste System Preoperational Test
: a. Purpose To verify that the radioactive waste system will perform its design functions of processing liquid and solid radioactive wastes.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing.
: c. General Test Methods and Acceptance Criteria Testing will demonstrate that the pumps, tanks, controls, and valves including automatic isolation, diversion and protection features, and instrumentation and alarms will operate and function in accordance with design requirements.
Testing will also verify that the CGS Process Control Program results in an acceptable waste form as required by 10 CFR 61. Simulated waste will be verified to form a free-standing monolithic solid with no free liquid prior to implementation of the solidification process on radioactive waste. Liners containing solidified waste will be inspected prior to shipment to the disposal site to verify compliance with 10 CFR 61 requirements.
14.2-44

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 14.2.12.1.18      Reactor Protection System Preoperational Test
: a. Purpose To verify the proper operation of the reactor protection system (RPS), including sensor logic and their respective scram relays, scram reset time delay, the annunciators, and motor generator set power supply.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing.
: c. General Test Methods and Acceptance Criteria Verification of the RPS capability is demonstrated by the proper integrated operation of the following:
: 1.       Motor generator set performance,
: 2.       Sensor logic and scram relay logic,
: 3.       Scram reset time delay,
: 4.       Sensors input-to-scram trip actuator response time on all channels of each function for which response times are required by the Technical Specifications,
: 5.       Annunciators,
: 6.       Mode switch tests, and
: 7.       Auxiliary sensor operation.
The ability of the system to scram the reactor within a specified time must be demonstrated in the CRD hydraulic system preoperational test (see Section 14.2.12.1.11).
14.2-45

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 14.2.12.1.19      Neutron Monitoring System Preoperational Test
: a. Purpose To verify the operation of the neutron monitoring system (NMS) including startup, intermediate, and power range detectors, and their related equipment.
: b. Prerequisites The system lineup tests have been complete, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Additionally, all source range monitors (SRMs) and pulse preamplifiers, IRMs and voltage preamplifiers, and APRMs will have been calibrated according to the vendors instructions.
: c. General Test Methods and Acceptance Criteria Verification of the NMS capability is demonstrated by the proper integrated operation of the following:
: 1.       All SRM detectors, and their respective insert and retract mechanisms, and cables;
: 2.       SRM channel including pulse preamp, remote meter and record, trip logic, logic bypass and related lamps and annunciators, control system interlocks, refueling instrument trips, and power supply;
: 3.       All IRM detectors and their respective insert and retract mechanisms and cables;
: 4.       IRM channels including voltage preamps, remote recorders, RMC system interlocks, RPS trips, annunciators and lamps, and power supplies;
: 5.       All LPRM detectors and their respective cables, and power supplies;
: 6.       All APRM channels including trips, trip bypasses, annunciators and lamps, remote recorders, RMC system interlocks, RPS trips, and power supplies;
: 7.       Recirculation flow bias signal including flow unit, flow transmitters, and related annunciators, interlocks, and power supplies, and 14.2-46

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003
: 8.       Both rod block monitor (RBM) channels including trips, trip bypasses, annunciators and lamps, remote recorders, RMC system interlocks, and power supplies.
14.2.12.1.20      Traversing In-Core Probe System Preoperational Test
: a. Purpose To verify the operation of the traversing in-core probe (TIP) system including the TIP detector, controls and interlocks, containment secure lamp, and containment isolation circuits.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. (Additionally, the TIP detector and dummy detector, ball valve time delay, core top and bottom limits, clutch, x-y recorder, and purge system will have been shown to be operational.)
: c. General Test Methods and Acceptance Criteria With the exception of the shear valve, which is not tested, verification of the TIP system is demonstrated by the proper integrated operation of the following:
: 1.       Indexer cross-calibration interlock,
: 2.       Shear valve control monitor lamp, and
: 3.       Drive motor manual control and override, automatic control and stop, and low speed control.
14.2.12.1.21      Rod Worth Minimizer System Preoperational Test
: a. Purpose To verify the operation of the rod worth minimizer (RWM) system under its various modes of operation.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the 14.2-47

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 initiation of testing. Additionally, the rod position indication system (RPIS) will have been shown to be operational, rod sequence control (RSC) system bypassed, and computer diagnostic and special tests completed.
: c. General Test Methods and Acceptance Criteria Verification of the RWM system is demonstrated by the proper integrated operation of the following:
: 1.       Rod test option,
: 2.       System initialization both above and below the low power setpoints, and above and below the low power alarm points,
: 3.       RWM program,
: 4.       Rod withdrawal and insertion error block, and
: 5.       Rod drift scan, and annunciation.
The RWM program acceptance of an operator-supplied rod position value must be demonstrated.
14.2.12.1.22      Process Radiation Monitoring System Preoperational Test
: a. Purpose To verify the operation of the process radiation monitoring (PRM) system, including the offgas vent, offgas, main steam line, liquid process, and building ventilation radiation monitoring subsystems.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Additionally, the process radiation monitors, pulse preamplifiers, power supplies, indicator and trip units, are calibrated.
Insulation resistance and high potentiometer tests will have been completed.
14.2-48

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003
: c. General Test Methods and Acceptance Criteria Verification of the PRM system is demonstrated by the proper integrated operation of the following:
: 1.       Vent preamps, channels, trip points, annunciators and lamps, sample rack, and check source,
: 2.       Offgas vial sampler, log radiation monitor (LRM) and their related annunciators, lamps and recorders, and high/low flow detector,
: 3.       Main steam and LRM channels, trip points, and annunciators and lamps, High-High and Inop trip, and recorders,
: 4.       Liquid process preamps, channels, trip points, and annunciators and lamps, and recorders,
: 5.       Building ventilation system sensors, channels, trip points, and annunciators and lamps, recorders, and SGTS interlock, and
: 6.       Control center air monitoring sensors, channels, annunciators, and indicators.
14.2.12.1.23      Area Radiation Monitoring System Preoperational Test
: a. Purpose To verify the operation of the area radiation monitoring (ARM) system, including channels, trip points, alarms, and recorder.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Additionally, indicator, trip units, and power supplies are calibrated.
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COLUMBIA GENERATING STATION                        Amendment 57 FINAL SAFETY ANALYSIS REPORT                       December 2003
: c. General Test Methods and Acceptance Criteria Verification of the ARM system capability is demonstrated by the proper integrated operation of the following:
: 1.       Monitor channels,
: 2.       Channel trip points,
: 3.       Alarm annunciators and lights, and
: 4.       Recorder.
14.2.12.1.24      Process Computer Interface System Preoperational Test
: a. Purpose To verify the operation of the process computer interface (PCI) system including computer inputs and printout.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Additionally, computer diagnostic checks and programming are completed.
: c. General Test Methods and Acceptance Criteria Verification of the PCI system is demonstrated by the proper integrated operation of the following:
: 1.       Analog input signals,
: 2.       Computer printout,
: 3.       Digital input signals, and
: 4.       Digital output signals.
14.2.12.1.25      Rod Sequence Control System Preoperational Test
: a. Purpose To verify the operation of the RSC system under its various modes of operation.
14.2-50

COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                           December 2003
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Additionally, the self-test feature of the RSC system is verified.
: c. General Test Methods and Acceptance Criteria Verification of the RSC system is demonstrated by the proper integrated operation of the following:
: 1. Low power setpoint and low power alarm point tests,
: 2. RSC system status displays and annunciators,
: 3. Reactor mode switch test,
: 4. System diagnostic and data quality tests,
: 5. Rod position data tests,
: 6. Single rod bypass provision,
: 7. Rod sequences tests,
: 8. Rod group assignment,
: 9. Constraints of rod movement tests,
: 10. 100% to 75% control rod density tests,
: 11. 5% to 50% control rod density tests, and
: 12. 0% control rod density to low power setpoint tests.
14.2.12.1.26      Remote Shutdown Preoperational Test
: a. Purpose To verify the feasibility and operability of the shutdown functions from the remote shutdown panel and its ability to bring the reactor to a cold condition in an orderly fashion.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Additionally, the control power should be supplied to the remote shutdown panel, and the independence of power supply voltage, and fuses should be verified.
14.2-51

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003
: c. General Test Methods and Acceptance Criteria Verification of the remote shutdown system is demonstrated by the proper integrated operation of the following tests:
: 1.      Operation of valves, controls, instruments, and pumps on systems available from this panel, and
: 2.      Transfer switch operation from the control room panels to the remote shutdown panel.
14.2.12.1.27     Offgas System Preoperational Test
: a. Purpose To verify the operation of the offgas system including valves, recombiner, condensers, coolers, filters, and hydrogen analyzers.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager (Assistant Plant Manager) has approved the initiation of testing. Additionally, the instrument air system, electrical power, and cooling water should be operational.
: c. General Test Methods and Acceptance Criteria Verification of the offgas system is demonstrated by the following tests:
: 1.      Valve operation including fail safe and isolation features and valve status lights indicate the correct valve position,
: 2.      Pump operation,
: 3.      Level and temperature control and indication,
: 4.      Recombiner and preheater tests,
: 5.      Condenser, cooler, and moisture separator tests,
: 6.      Gas dryer and cooler tests,
: 7.      Filter efficiency, 14.2-52

COLUMBIA GENERATING STATION                        Amendment 57 FINAL SAFETY ANALYSIS REPORT                       December 2003
: 8.       Hydrogen analyzer performance test, and
: 9.       Purge and bleed air rate test.
14.2.12.1.28      Environs Radiation Monitoring Preoperational Test
: a. Purpose To verify the operation of the environs radiation monitoring system, including dosimeters, sampling pump, and filter equipment.
: b. Prerequisites System lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Additionally, indicator power supplies are calibrated according to the vendors instruction manual.
: c. General Test Methods and Acceptance Criteria Verification of the environs radiation monitoring system capability is demonstrated by the proper operation of the following:
: 1.       Air sample equipment, and
: 2.       Thermoluminescent detector (TLD) (passive dosimeters).
14.2.12.1.29      Main Steam System Preoperational Test
: a. Purpose To verify the proper operation of the MSIVs and related controls.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing.
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COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003
: c. General Test Methods and Acceptance Criteria Verification of the main steam system is demonstrated by the proper integrated operation of the following:
: 1.       Automatic isolation of the MSIVs,
: 2.       Minimum closing times are met,
: 3.       MSIV accumulator capacity tests are satisfactory, and
: 4.       Valves, heaters, blowers, and initiating logic of the MSIV leakage control system.
14.2.12.1.30      Radwaste Building Heating, Ventilating, and Air Conditioning System Preoperational Test
: a. Purpose To verify that the radwaste building heating, ventilating, and air conditioning (HVAC) system will function in accordance with the design requirements as set forth in the design specifications.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The 480-V ac power system, control air supply service air system, and the turbine service water system is capable of supporting this test as necessary.
: c. General Test Methods and Acceptance Criteria Verification of the radwaste building HVAC system is demonstrated by the proper integrated operation of the following:
: 1.       Ventilation fans and their related controls,
: 2.       Filters and instrumentation,
: 3.       Dampers and controls, and
: 4.       Annunciators and protective devices.
14.2-54

COLUMBIA GENERATING STATION                        Amendment 58 FINAL SAFETY ANALYSIS REPORT                       December 2005 14.2.12.1.31      Closed Cooling Water System Preoperational Test
: a. Purpose To verify the operation of the RCC system including pumps, valves, logic, and annunciator.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The following support systems must have received readiness verifications:
: 1.       Control and service air (CAS/SA),
: 2.       Makeup water treatment,
: 3.       Essential 480-V ac power, and
: 4.       Instrumentation power.
: c. General Test Methods and Acceptance Criteria Verification of the RCC system is demonstrated by the proper integrated operation of the following:
: 1.       Surge tank level control,
: 2.       System pumps and control logic,
: 3.       Chemical addition pump and control, and
: 4.       Remote-operated valves.
14.2.12.1.32      Primary Containment Atmospheric Control System Preoperational Test (SYSTEM DEACTIVATED)
: a. Purpose To verify the operation of the primary containment atmospheric control (CAC) system including blowers, coolers, valves, instruments, and alarms.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Primary containment, essential 480-V ac power, standby LDCN-05-002                                 14.2-55

COLUMBIA GENERATING STATION                        Amendment 58 FINAL SAFETY ANALYSIS REPORT                       December 2005 service water (SW), instrument power, and control air systems must have received readiness verification.
: c. General Test Methods and Acceptance Criteria Verification of the primary CAC system is demonstrated by the proper integrated operation of the following:
: 1.       Isolation and control valves,
: 2.       Blowers,
: 3.       Instrumentation,
: 4.       Alarms, and
: 5.       Recombiner components to the extent that flow paths are verified.
Primary CAC system hydrogen/oxygen recombining performance capabilities are not demonstrated during the preoperational test.
14.2.12.1.33      Primary Containment Cooling System Preoperational Test
: a. Purpose To verify the operation of the primary containment cooling system including fans, dampers, related controls, and instrumentation.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The 480-V ac power, instrument power, and RCC systems must have received readiness verification.
: c. General Test Methods and Acceptance Criteria Verification of the primary containment cooling system is demonstrated by the proper integrated operation of the following:
: 1.       Fans and control logic,
: 2.       Cooling coils,
: 3.       Dampers, cooling water flow control valves and related controls,
: 4.       Instrumentation,
: 5.       Related loss-of-power logic, and
: 6.       Annunciators.
14.2-56

COLUMBIA GENERATING STATION                        Amendment 58 FINAL SAFETY ANALYSIS REPORT                       December 2005 Primary containment cooling system heat removal capabilities are not demonstrated during the preoperational test.
14.2.12.1.34      Primary Containment Instrument Air Preoperational Test
: a. Purpose To verify proper operation of the containment instrument air (CIA) system, including compressors, dryers, valves, and related controls and logic.
: b. Prerequisites The system lineup tests have been completed, and the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The plant service water supply system must receive a readiness classification.
: c. General Test Methods and Acceptance Criteria Verification of the CIA system capability is demonstrated by the proper integrated operation of the following:
: 1.       Logic and interlocks,
: 2.       CIA system air compressors,
: 3.       CIA system air dryers,
: 4.       System nonreturn check valves,
: 5.       Alarms and controls,
: 6.       Nitrogen backup supply, and
: 7.       Valve/component failure modes for those valves/components supplied by the CIA system to simulated loss of air supply.
14.2.12.1.35      Primary Containment Atmospheric Monitoring System Preoperational Test
: a. Purpose To verify the capability of the primary containment atmospheric monitoring system to monitor and display containment atmospheric conditions.
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COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Instrument power is available to system components.
: c. General Test Methods and Acceptance Criteria Verification of the primary containment atmospheric monitoring system capability is demonstrated by the proper integrated operation of the following:
: 1.       Samples and controls,
: 2.       Analyzers,
: 3.       Pressure and temperature instrumentation,
: 4.       Radiation monitors,
: 5.       Indicating/recording instrumentation, and
: 6.       Annunciators.
14.2.12.1.36      Standby Gas Treatment System Preoperational Test
: a. Purpose To verify the reliable operation of the standby gas treatment system (SGTS),
including fans, filter trains, and related controls.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The following systems must have readiness verification:
: 1.       Essential 480-V ac power,
: 2.       Instrument power,
: 3.       Control air, and
: 4.       Reactor building heating and ventilation.
: c. General Test Methods and Acceptance Criteria Verification of the SGTS is demonstrated by the proper integrated operation of the following:
: 1.       SGTS fans and control logic, 14.2-58

COLUMBIA GENERATING STATION                             Amendment 57 FINAL SAFETY ANALYSIS REPORT                            December 2003
: 2.      Filter trains and related instruments,
: 3.      Automatic valves and control logic,
: 4.      System interconnections to reactor building heating and ventilation and primary containment atmospheric control system, and
: 5.      Annunciators.
14.2.12.1.37     Loss of Power and Safety Testing Preoperational Test
: a. Purpose To verify the operation of the 230/115-kV, 6.9-kV, 4.16-kV, and 480-V distribution systems.
To verify the integrated ability of the plant electrical distribution and safety systems to operate on normal and standby power sources during accident conditions.
To verify that loss of a single ac or dc distribution system division (exclusive of the HPCS diesel generator and batteries) will not prevent the remaining systems from actuating during an accident condition.
: b. Prerequisites The system lineup tests and the 69/N (N = number of diesels) consecutive starts from the emergency diesel generators have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The 125-V dc system and the emergency core cooling systems (ECCS) are available to support testing.
: c. General Test Methods and Acceptance Criteria Verification of the 230/115-kV, 6.9-kV, 4.16-kV, and 480-V distribution systems operability shall be demonstrated by the following:
: 1.      Demonstration of circuit integrity and integrated operation of circuit breakers, controls and interlocks, instrumentation, automatic transfer features, and protective devices and alarms.
14.2-59

COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003
: 2. Demonstration of proper system response to a loss of the 230-kV and 115-kV distribution systems independently and simultaneously both with and without loss-of-coolant accident (LOCA)/containment isolation signals.
: 3. Demonstration of proper system response to a loss of the 230/115-kV distribution systems and one individual standby diesel generator during an ECCS/containment isolation actuation.
Signals for these tests shall be simulated from the actual initiating devices when this is practical.
: 4. Testing of the diesel generators will include the following:
(a)     Sequential loading of each diesel generator unit, (b)     Maintenance of specified frequency and voltage during the loading sequence, (c)     Capability to reject and restart their largest single load any time after the design loading sequence is complete, and (d)     Capability to supply power to vital equipment during loss of station normal power conditions.
: 5. Electrical independence will be verified during testing by (a)     Verifying that operation of the division/equipment being tested and the nonactuation of deenergized buses/equipment does not affect the proper operation of the remaining buses/equipment.
(b)     Monitoring of the major distribution buses to ensure absence of voltage.
Main power transformers supplying power from the offsite system cannot be full load tested; they are tested according to this procedure to the design emergency load. All other in-plant power sources are load tested in their individual preoperational tests.
14.2-60

COLUMBIA GENERATING STATION                        Amendment 57 FINAL SAFETY ANALYSIS REPORT                       December 2003 14.2.12.1.38      Instrument Power Preoperational Test
: a. Purpose To verify the operation of the instrument power systems.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing.
The 125-V dc and the 480-V ac power systems are energized and capable of supplying power to the instrument power systems.
: c. General Test Methods and Acceptance Criteria Verification of the instrument power systems shall be accomplished by demonstrating circuit integrity and integrated operation of
: 1.       Static inverters, transformers, and buses,
: 2.       Controls and interlocks,
: 3.       Transfer features,
: 4.       Instrumentation, and
: 5.       Protective devices and alarms.
14.2.12.1.39      Emergency Lighting System Preoperational Test
: a. Purpose To verify the operation of the emergency lighting system within the design requirements of the system.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The 125-V dc system has received a readiness verification.
14.2-61

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003
: c. General Test Methods and Acceptance Criteria Verification of the emergency lighting system is to demonstrate proper automatic operation of the system and to provide sufficient lighting during loss of normal lighting.
14.2.12.1.40      Standby Alternating Current Power System Preoperational Test
: a. Purpose To verify the operation of the standby ac power system including diesel engines, auxiliaries, generators, controls, and instrumentation.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing.
The following support systems or components must have received readiness verification:
: 1.       Standby service water,
: 2.       125/250-V dc power,
: 3.       Instrument power, and
: 4.       Essential 4160-V ac power.
: c. General Test Methods and Acceptance Criteria Verification of the standby ac power system is demonstrated by the proper integrated operation of the following:
: 1.       The diesel engines and auxiliaries,
: 2.       The generators, exciters, and voltage regulators,
: 3.       Fuel storage and supply system,
: 4.       Start and control logic circuitry and interlocks,
: 5.       Protective devices,
: 6.       Instrumentation, and
: 7.       Annunciators.
Testing will be performed to demonstrate the following design features.
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COLUMBIA GENERATING STATION                         Amendment 60 FINAL SAFETY ANALYSIS REPORT                        December 2009
: 1.       The diesel generators performance capability to establish frequency, voltage, and load acceptance with a specified time interval on initiation of an automatic start signal under both cold and hot conditions.
: 2.       Specified full- and over-load performance capabilities.
: 3.       The diesel generators capability to reject the maximum rated load without exceeding speeds or voltage which will cause tripping.
14.2.12.1.41      250-V Direct Current Power System Preoperational Test
: a. Purpose To verify the operation of the 250-V dc power system including batteries, chargers, controls, interlocks, instruments, and protective devices.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Battery room ventilation and 480-V ac power supply to the chargers have received readiness verification.
: c. General Test Methods and Acceptance Criteria Verification of the 250-V dc power system is demonstrated by the proper integrated operation of the following:
: 1.       Battery chargers including capability to recharge the battery in accordance with Section 8.3.2.1.4.3,
: 2.       Batteries (including charge and discharge rate/capacity tests and load profiles described in Table 8.3-14),
: 3.       Protective relays and devices,
: 4.       System control logic,
: 5.       Instrumentation (including ground detection),
: 6.       Breakers, and
: 7.       Annunciators.
LDCN-08-025                                  14.2-63

COLUMBIA GENERATING STATION                         Amendment 60 FINAL SAFETY ANALYSIS REPORT                        December 2009 14.2.12.1.42      125-V Direct Current Power System Preoperational Test
: a. Purpose To verify the operation of the 125-V dc power system including batteries, chargers, controls, interlocks, instruments, and protective devices.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Battery room ventilation and 480-V ac power supply to the chargers have received readiness verification.
: c. General Test Methods and Acceptance Criteria Verification of the 125-V dc power system is demonstrated by the proper integrated operation of the following:
: 1.       Battery chargers including capability to recharge the battery in accordance with Section 8.3.2.1.1.3,
: 2.       Batteries (including charge and discharge rate/capacity tests and load profiles described in Tables 8.3-11 and 8.3-12),
: 3.       Protective relays and devices,
: 4.       System control logic,
: 5.       Instrumentation (including ground detection),
: 6.       Breakers, and
: 7.       Annunciators.
14.2.12.1.43      24-V Direct Current Power System Preoperational Test
: a. Purpose To verify the operation of the 24-V dc power system.
LDCN-08-025                                  14.2-64

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing.
: c. General Test Methods and Acceptance Criteria Verification of the 24-V dc power system shall include demonstrations of battery capacity and battery charger capabilities described in Section 8.3.2.1.3.3.
14.2.12.1.44      Plant Service Water System Preoperational Test
: a. Purpose To demonstrate the proper operation of the plant service water system, including pumps, valves, and related controls.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing.
The following support systems or components must have received readiness verification:
: 1.       4160-V ac power,
: 2.       480-V ac power,
: 3.       Instrument power,
: 4.       Service water pump house structure,
: 5.       Various heat exchangers or coolers utilizing service water, and
: 6.       Tower makeup (TMU).
: c. General Test Methods and Acceptance Criteria Verification of the plant service water system is demonstrated by the proper operation and performance of the service water pumps, the operation of filters, remote-operated valves, related controls, and instrumentation.
14.2-65

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998 14.2.12.1.45      Standby Service Water System Preoperational Test
: a. Purpose To verify the proper operation of the SW system for normal and abnormal plant operating modes.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The following support systems or components must have received readiness verification:
: 1.       Essential 4160-V ac power, 2        Instrument power,
: 3.       Control air,
: 4.       Standby service water pump house structure,
: 5.       Various heat exchangers or coolers utilizing SW, and
: 6.       Tower makeup (TMU).
: c. General Test Methods and Acceptance Criteria Verification of this system is demonstrated by the proper integrated operation and performance of the following:
: 1.       Pumps and related controls,
: 2.       Remote-operated valves and controls,
: 3.       Automatic-operated valves and control logic,
: 4.       Instrumentation,
: 5.       Annunciators,
: 6.       Standby service water system control logic response to a simulated loss of normal station power event,
: 7.       Pumps net positive suction head (NPSH) adequate and no vortexing,
: 8.       Proper operation of basin siphon cross connection, and 14.2-66

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998
: 9.       The preoperational test program includes tests to confirm the performance characteristics of the spray ponds (see Section 9.2.5).
14.2.12.1.46      Plant Communications System Preoperational Test
: a. Purpose To demonstrate that the plant communications and evacuation alarm system will provide effective communication between various plant locations and to verify proper operation of the emergency evacuation alarm components and system.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing.
: c. General Test Methods and Acceptance Criteria Proper operation of all the communication system components and the emergency evacuation alarm system and components will be demonstrated.
14.2.12.1.47      Reactor Building Emergency Cooling System Preoperational Test
: a. Purpose To demonstrate the proper integrated operation of the reactor building emergency equipment cooling system including fans, cooling coils, instrumentation, and controls.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The following support systems or components must have received readiness verification:
: 1.       Electrical power to motors, control circuits, and instrumentation, and
: 2.       Standby service water system.
14.2-67

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998
: c. General Test Methods and Acceptance Criteria Verification of this system is demonstrated by the proper integrated operation of the fan coil units, their associated controls, interlocks, and annunciators.
14.2.12.1.48      Control, Cable, and Critical Switchgear Rooms Heating, Ventilating, and Air Conditioning System Preoperational Test
: a. Purpose To verify that the control, cable, and critical switchgear rooms HVAC systems will function in accordance with the design requirements as set forth in the design specifications.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The following support systems have received readiness verification:
: 1.       480-V ac power,
: 2.       Instrument power, and
: 3.       Chilled water.
: c. General Test Methods and Acceptance Criteria Verification of the control, cable, and critical switchgear rooms HVAC system is demonstrated by the proper integrated operation of the following:
: 1.       Supply and exhaust fans and their related controls,
: 2.       Filters, dampers, valves, and related instrumentation and control logic,
: 3.       Coolers, and
: 4.       Annunciators.
14.2.12.1.49      Standby Service Water Pump House Heating and Ventilating System Preoperational Test
: a. Purpose To verify that the SW pump house heating and ventilating system will function in accordance with the design requirements as set forth in the design specifications.
14.2-68

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The 480-V ac power system must have received readiness verification.
: c. General Test Methods and Acceptance Criteria Verification of the SW pump house heating and ventilating system is demonstrated by the proper integrated operation of the following:
: 1.       Ventilation fans and their related controls,
: 2.       Filters and instrumentation,
: 3.       Dampers and controls, and
: 4.       Annunciators.
14.2.12.1.50      Reactor Building Crane Preoperational Test
: a. Purpose To verify the operation of the reactor building crane.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. Construction load tests of 125% static and 100%
operational are complete.
Contractor use of the reactor building crane for construction purposes is complete.
: c. General Test Methods and Acceptance Criteria Verification of the reactor building crane is demonstrated by the proper integrated operation of the following:
: 1.       Crane traverse components,
: 2.       Hook traverse and hoist components,
: 3.       Controls and indicators, 14.2-69

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998
: 4.       Safety devices, and
: 5.       Instrumentation.
14.2.12.1.51      Primary Containment Integrated Leak Rate Preoperational Test
: a. Purpose To verify overall primary containment integrity by pressurizing to specified test pressures and conducting integrated leak rate measurements.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The following supporting activities, systems, or components must have been completed or received readiness verification:
: 1.       All type B and C local leak testing completed, documented, and verified as a system lineup test; see Section 6.2.6.1,
: 2.       All containment isolation valves fully operable and closed in the normal manner,
: 3.       All containment-associated piping hangers, supports, restraints, and anchors have been installed and properly set,
: 4.       Residual heat removal and core spray systems preoperational tests complete, and
: 5.       A containment area survey completed to locate, isolate, or remove any instrumentation, light bulbs, etc., which may be damaged by high external pressure.
: c. General Test Methods and Acceptance Criteria Verification of primary containment integrity is demonstrated by pressurizing to the required test pressure. See Section 6.2.6.1 for a detailed test description.
The drywell-wetwell leakage test will be performed as part of this test to verify the acceptance criteria described in Section 3.8.3.7.
14.2-70

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 14.2.12.1.52      Secondary Containment Integrated Leak Rate Preoperational Test
: a. Purpose To verify overall secondary containment integrity by subjecting the reactor building to a specified negative pressure and measuring the inleakage.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The following supporting activities or systems/components must have been completed or received readiness verification:
: 1.       Reactor building structure complete with personnel and vehicle air lock (railroad bay) doors installed and operable,
: 2.       Reactor building conduit, pipe, and other structural penetrations sealed, and
: 3.       Standby gas treatment system.
: c. General Test Methods and Acceptance Criteria Verification of secondary containment integrity is demonstrated by operating the SGTS at a specific capacity while maintaining the reactor building internal structure at a specified negative pressure.
14.2.12.1.53      Diesel Generator Building Heating and Ventilating System Preoperational Test
: a. Purpose To verify that the diesel generator building heating and ventilating system will function in accordance with the design requirements as set forth in the design specifications.
: b. Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing. The 480-V ac power system must have received readiness verification.
LDCN-02-036                                 14.2-71

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998
: c.      General Test Methods and Acceptance Criteria Verification of the diesel generator building heating and ventilating system is demonstrated by the proper integrated operation of the following:
: 1.       Ventilation fans and their related controls,
: 2.       Filters and instrumentation,
: 3.       Dampers and controls, and
: 4.       Annunciators.
14.2.12.1.54         Seismic Monitoring System Preoperational Test
: a.      Purpose To verify the operation of the seismic monitoring system.
: b.      Prerequisites The system lineup tests have been completed, the TWG has reviewed and approved the procedure, and the Test and Startup Manager has approved the initiation of testing.
: c.      General Test Methods and Acceptance Criteria Verification of the seismic monitoring system is demonstrated by the proper integrated operation of the following:
: 1.       Annunciators, and
: 2.       Instrumentation.
14.2.12.2      General Discussion of Startup Tests All those tests comprising the startup test phase (Table 14.2-4) are discussed in this section.
For each test a description is provided for test purpose, test prerequisites, test description, and statement of test acceptance criteria, where applicable.
In describing the purpose of a test, an attempt is made to identify those operating and safety-oriented characteristics of the plant which are being explored.
Where applicable, a definition of the relevant acceptance criteria for the test is given and is designated either Level 1 or Level 2. A Level 1 criterion normally relates to the value of a process variable assigned in the design of the plant, components, systems, or associated 14.2-72

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998 equipment. If a Level 1 criterion is not satisfied, the plant will be placed in a suitable hold-condition until resolution is obtained. Tests compatible with this hold-condition may be continued. Following resolution, applicable tests must be repeated to verify that the requirements of the Level 1 criterion are now satisfied.
A Level 2 criterion is associated with expectations relating to the performance of systems. If a Level 2 criterion is not satisfied, operating and testing plans would not necessarily be altered.
Investigations of the measurements and of the analytical techniques used for the predictions would be started.
For transients involving oscillatory response, the criteria are specified in terms of decay ratio (defined as the ratio of successive maximum amplitudes of the same polarity). The decay ratio must be less than unity to meet a Level 1 criterion and less than 0.25 to meet a Level 2 criterion.
14.2.12.3      Startup Test Procedures 14.2.12.3.1         Test Number 1 - Chemical and Radiochemical 14.2.12.3.1.1 Purpose. The principal objectives of this test are to (a) secure information on the chemistry and radiochemistry of the reactor coolant, and (b) determine that the sampling equipment, procedures, and analytic techniques are adequate to supply the data required to demonstrate that the chemistry of all parts of the entire reactor system meet specifications and process requirements.
Specific objectives of the test program include evaluation of fuel performance, evaluations of demineralizer operations by direct and indirect methods, measurements of filter performance, confirmation of condenser integrity, demonstration of proper steam separator-dryer operation, measurement and calibration of the offgas system, and calibration of certain process instrumentation. Data for these purposes is secured from a variety of sources: plant operating records, regular routine coolant analysis, radiochemical measurements of specific nuclides, and special chemical tests.
14.2.12.3.1.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.1.3 Description. Prior to fuel loading a complete set of chemical and radiochemical samples will be taken to ensure that all required sample stations are functioning properly and to determine initial concentrations. Subsequent to fuel loading during reactor heatup and at each major power level change, samples will be taken and measurements will be made to determine the chemical and radiochemical quality of reactor water and reactor 14.2-73

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 feedwater, amount of radiolytic gas in the steam, gaseous activities leaving the air ejectors, decay times in the offgas lines and performance of filters and demineralizers.
Calibrations will be made of monitors in the stack, liquid waste system, and liquid process lines.
14.2.12.3.1.4 Criteria.
Level 1 Chemical factors defined in the Technical Specifications and Fuel Warranty must be maintained within the limits specified.
The activity of gaseous liquid effluents must conform to license limitations.
Water quality must be known at all times and should remain within the guidelines of the Water Quality Specifications.
Level 2 Not applicable.
14.2.12.3.2         Test Number 2 - Radiation Measurements 14.2.12.3.2.1 Purpose. The purposes of this test are to (a) determine the background radiation levels in the plant environs prior to operation for base data on activity buildup, and (b) monitor radiation at selected power levels to ensure the protection of personnel during plant operation.
14.2.12.3.2.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.2.3 Description. A survey of natural background radiation throughout the plant site will be made prior to fuel loading. Subsequent to fuel loading, during reactor heatup and at nominal power levels of 25%, 60%, and 100% of rated power, gamma dose rate measurements and where appropriate, neutron dose rate measurements will be made at significant locations throughout the plant. All potentially high radiation areas will be surveyed.
14.2-74

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998 14.2.12.3.2.4 Criteria.
Level 1 The radiation doses of plant origin and the occupancy times of personnel in radiation zones shall be controlled consistent with the guidelines of the Standards for Protection Against Radiation outlined in 10 CFR 20 and the NRC General Design Criteria in 10 CFR 50, Appendix A.
Level 2 Not applicable.
14.2.12.3.3        Test Number 3 - Fuel Loading 14.2.12.3.3.1 Purpose. The purpose of this test is to load fuel safely and efficiently to the full core size.
14.2.12.3.3.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing. Also the following prerequisites will be met prior to commencing fuel loading to ensure that this operation is performed in a safe manner:
: a. The status of all systems required for fuel loading will be specified and will be in the status required;
: b. Fuel and control rod inspections will be complete. Control rods will be installed and tested;
: c. At least three movable neutron detectors will be calibrated and operable. At lease three neutron detectors will be connected to the high flux scram trips.
They will be located so as to provide acceptable signals during fuel loading;
: d. Nuclear instruments will be source checked with a neutron source prior to loading or resumption if sufficient delays are incurred;
: e. The status of secondary containment will be specified and established;
: f. Reactor vessel status will be specified relative to internal component placement and this placement established to make the vessel ready to receive fuel;
: g. Reactor vessel water level will be established and minimum level prescribed; 14.2-75

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998
: h.      The standby liquid control system will be operable and in readiness;
: i.      Fuel handling equipment will have been checked and dry runs completed;
: j.      The status of protection systems, interlocks, mode switches, alarms, and radiation protection equipment will be prescribed and verified. The high flux trip points will be set for a relatively low power level;
: k.      Water quality must meet required specifications; and
: l.      A neutron source will be installed near the center of the core.
14.2.12.3.3.3 Description. Prior to fuel loading, control rods and neutron sources and detectors will be installed and tested. Fuel loading will begin at the center of the core and will proceed radially to the fully loaded configuration.
Control rod functional tests, subcriticality checks, and shutdown margin demonstrations will be performed periodically during the loading.
14.2.12.3.3.4 Criteria.
Level 1 The partially loaded core must be subcritical by at least 0.38% k/k with the analytically strongest rod fully withdrawn.
Level 2 Not applicable.
14.2.12.3.4         Test Number 4 - Full Core Shutdown Margin 14.2.12.3.4.1 Purpose. The purpose of this test is to demonstrate that the reactor will be subcritical throughout the first fuel cycle with any single control rod fully withdrawn.
14.2.12.3.4.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing. Also the following prerequisites will be complete prior to performing the full core shutdown margin test:
: a.      The predicted critical rod position is available,
: b.      The standby liquid control system is available, 14.2-76

COLUMBIA GENERATING STATION                            Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998
: c.      Nuclear instrumentation is available with neutron count rate of at least 0.5 counts per sec and signal to noise ratio greater than two, and
: d.      High-flux scram trips are set conservatively low.
14.2.12.3.4.3 Description. This test will be performed in the fully loaded core in the xenon-free condition. The shutdown margin test will be performed by withdrawing the control rods from the all-rods-in configuration until criticality is reached. If the highest worth rod will not be withdrawn in sequence, other rods may be withdrawn providing that the reactivity worth is equivalent. The difference between the measure Keff and the calculated Keff for the in sequence critical will be applied to the calculated value to obtain the true shutdown margin.
14.2.12.3.4.4 Criteria.
Level 1 The shutdown margin of the fully loaded, cold (68&deg;F or 20&deg;C), xenon-free core occurring at the most reactive time during the cycle must be at least 0.38% k/k with the analytically strongest rod (or its reactivity equivalent) withdrawn. If the shutdown margin is measured at some time during the cycle other than the most active time, compliance with the above criterion is shown by demonstrating that the shutdown margin is 0.38% k/k plus an exposure dependent correction factor which corrects the shutdown margin at that time to the minimum shutdown margin.
Level 2 Criticality should occur within +/-1% k/k of the predicted critical (predicted critical to be determined later).
14.2.12.3.5         Test Number 5 - Control Rod Drive System 14.2.12.3.5.1 Purpose. The purposes of the CRD system test are to (a) demonstrate that the CRD system operates properly over the full range of primary coolant temperatures and pressures from ambient to operating, and (b) determine the initial operating characteristics of the entire CRD system.
14.2.12.3.5.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing. The RMC system preoperational testing must be completed on CRDs being tested. The reactor vessel, RCC system, condensate supply system, and instrument air system must be operational to the extent required to conduct the test.
14.2-77

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 14.2.12.3.5.3 Description. The CRD tests performed during the startup test program are designed as an extension of the tests performed during the preoperational CRD system tests.
Thus, after it is verified that all CRDs operate properly when installed, they are tested periodically during heatup to ensure that there is not significant binding caused by thermal expansion of the core components.
Test Conditions Reactor Pressure with Core Loaded Accumulator                         psig (kg/cm2)
Action                         Pressure           0     600 (42.2)       800 (56.2)    Rated Position indication                             All Normal stroke times                             All                                     4*
insert/withdraw Coupling                                        All**                                   4*
Friction                                        All                                     4*
Scram                       Normal              All         4*              4*          All Scram                       Minimum             4*
Scram                       Zero                                                        4*
Scram                       Normal                                                      4***
NOTE:        Single CRD scrams should be performed with the charging valve closed. (Do not ride the charging pump head.)
Refers to four CRDs selected for continuous monitoring based on slow normal accumulator pressure scram times, or unusual operating characteristics, at zero reactor pressure or rated reactor pressure when this data is available. The four selected CRDs must be compatible with the RWM, RSC system, and CRD sequence requirements.
Established initially that this check is normal operating procedures.
Scram times of the four slowest CRDs (based on scram data at rated pressure will be determined at test condition 2, 3, and 6 during planned reactor scram).
14.2-78

COLUMBIA GENERATING STATION                            Amendment 53 FINAL SAFETY ANALYSIS REPORT                           November 1998 14.2.12.3.5.4 Criteria.
Level 1
: a. Each CRD must have a normal withdraw speed less than or equal to 3.6 in./sec (9.14 cm/sec), indicated by a full 12-ft stroke in greater than or equal to 40 sec.
: b. The mean scram time of all operable CRDs with functioning accumulators must not exceed the following times (scram time is measured from the time the pilot scram valve solenoids are deenergized):
Position Inserted From                  Scram Time Fully Withdrawn                          (sec) 45                                0.430 39                                0.868 25                                1.936 05                                3.497
: c. The mean scram time of the three fastest CRDs in a two-by-two array must not exceed the following times (scram time is measured from the time the pilot scram valve solenoids are deenergized):
Position Inserted From                  Scram Time Fully Withdrawn                          (sec) 45                                0.455 39                                0.920 25                                2.052 05                                3.706 Level 2
: a. Each CRD must have normal insert or withdraw speed of 3.0 +/- 0.6 in./sec (7.62 +/- 1.52 cm/sec), indicated by a full 12-ft stroke in 40 to 60 sec.
: b. With respect to the CRD friction tests, if the differential pressure variation exceeds 15 psid (1.1 kg/cm2) for a continuous drive in, a settling test must be performed, in which case the differential settling pressure should not be less than 30 psid (2.1 kg/cm2) nor should it vary by more than 10 psid (0.7 kg/cm2) over a full stroke.
14.2-79

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 Level 3
: a.      On receipt of a simulated or actual scram signal (maximum error), the flow control valve must close to its minimum position within 10 sec to 30 sec.
: b.      The CRD system flow should not change by more than +/- 3.0 gpm as reactor pressure varies from 0 to rated pressure.
: c.      The decay ratio of any oscillatory controlled variable must be 0.25 for any flow setpoint changes or for system disturbances caused by the CRDs being stroked.
14.2.12.3.6         Test Number 6 - Source Range Monitor Performance and Control Rod Sequence 14.2.12.3.6.1 Purpose. The purpose of this test is to demonstrate that the operational sources, SRM instrumentation, and rod withdrawal sequences provide adequate information to achieve criticality and increase power in a safe and efficient manner. The effect of typical rod movements on reactor power will be determined.
14.2.12.3.6.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing. The CRD system must be operational.
14.2.12.3.6.3 Description. Source range monitor count-range data will be taken during rod withdrawals to critical and compared with stated criteria on signal count-to-noise count ratio.
A withdrawal sequence has been calculated which completely specifies control rod withdrawals from the all-rods-in condition to the rated power configuration. Critical rod patterns will be recorded periodically as the reactor is heated to rated temperature.
Movement of rods in a prescribed sequence is monitored by the rod control and information system, which will prevent out of sequence withdrawal. Also not more than two rods may be inserted out of sequence.
As the withdrawal of each rod group is completed during the power ascension, the electrical power, steam flow, control valve position, and APRM response will be recorded.
14.2.12.3.6.4 Criteria.
Level 1 There must be a neutron signal-to-noise ratio of at least 2 to 1 on the required operable SRMs or fuel loading chambers.
LDCN-02-000                                    14.2-80

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 There must be a minimum count rate of 0.5 counts/sec on the required operable SRMs or fuel loading chambers.
The IRMs must be on scale before the SRMs exceed the rod block setpoint.
Level 2 Not applicable.
14.2.12.3.7       Test Number 7 Not applicable.
14.2.12.3.8       Test Number 8 Not applicable.
14.2.12.3.9       Test Number 9 See test number 16B in Section 14.2.12.3.16.2.
14.2.12.3.10      Test Number 10 - Intermediate Range Monitor System Performance 14.2.12.3.10.1 Purpose. The purpose of this test is to adjust the IRM system to obtain an optimum overlap with the SRM and APRM systems.
14.2.12.3.10.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing. All SRMs and pulse preamplifiers, IRMs and voltage preamplifiers, and APRMs have been calibrated in accordance with the vendors instructions.
14.2.12.3.10.3 Description. Initially the IRM system is set to maximum gain. After the APRM calibration, the IRM gains will be adjusted to optimize the IRM overlap with the SRMs and APRMs.
14.2.12.3.10.4 Criteria.
Level 1 Each IRM channel must be on scale before the SRMs exceed their rod block setpoint. Each APRM must be on scale before the IRMs exceed their rod block setpoint.
14.2-81

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 Level 2 Each IRM channel must be adjusted so that a half decade overlap with the SRMs and one decade overlap with the APRMs are ensured.
14.2.12.3.11       Test Number 11 - Local Power Range Monitor Calibration 14.2.12.3.11.1 Purpose. The purpose of this test is to calibrate the LPRM system.
14.2.12.3.11.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation for calibration has been checked and installed.
14.2.12.3.11.3 Description. The LPRM channels will be calibrated to make the LPRM readings proportional to the neutron flux in the LPRM water gap at the chamber elevation.
Calibration factors will be obtained through the use of either an off-line or a process computer calculation that relates the LPRM reading to average fuel assembly power at the chamber height.
14.2.12.3.11.4 Criteria.
Level 1 Not applicable.
Level 2 Each LPRM reading will be within 10% of its calculated value.
14.2.12.3.12       Test Number 12 - Average Power Range Monitor Calibration 14.2.12.3.12.1 Purpose. The purpose of this test is to calibrate the APRM system.
14.2.12.3.12.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation for calibration has been checked and installed.
14.2.12.3.12.3 Description. A heat balance will generally be made each shift and after each major power level change. Each APRM channel reading will be adjusted to be consistent with the core thermal power as determined from the heat balance. During heatup a preliminary calibration will be made by adjusting the APRM amplifier gains so that the APRM readings agree with the results of a constant heatup rate heat balance. The APRMs should be recalibrated in the power range by a heat balance as soon as adequate feedwater indication is 14.2-82

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 available. Recalibration of the APRM system will not be necessary from safety considerations if at least two APRM channels per RPS trip circuit have readings greater than or equal to core power.
14.2.12.3.12.4 Criteria.
Level 1 The APRM channels must be calibrated to read equal to or greater than the actual core thermal power.
Technical Specifications and Fuel Warranty Limits on APRM scram and rod block shall not be exceeded.
In the startup mode, all APRM channels must produce a scram at less than or equal to 15% of rated thermal power.
Level 2 If the above criteria are satisfied then the APRM channels will be considered to be reading accurately if they agree with the heat balance or the minimum value required based on peaking factor maximum linear heat generation rate (MLHGR) and fraction of rated power to within
(+7, -0)% of rated power.
14.2.12.3.13        Test Number 13 - Process Computer 14.2.12.3.13.1 Purpose. The purpose of this test is to verify the performance of the process computer under plant operating conditions.
14.2.12.3.13.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Computer diagnostic testing has been completed. Construction and construction testing on each input instrument and its cabling has been completed.
14.2.12.3.13.3 Description. Computer system program verifications and calculational program validations at static and at simulated dynamic input conditions will be preoperationally tested at the computer suppliers site and following delivery to the plant site.
Following fuel loading, during plant heatup and the ascension to rated power, the NSSS and the balance-of-plant system process variables sensed by the computer as digital or analog signals will become available. Verify that the computer is receiving correct values of NSSS process variables and that the results of performance calculations of the NSSS is correct. At steady-state power conditions the dynamic system test case will be performed.
14.2-83

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                       December 2003 As discussed in Test 19 the BUCLE offline computation system will be used to evaluate core performance until the process computer performance is verified. A manual computation method is available at the site if both the process computer and BUCLE are not available.
14.2.12.3.13.4 Criteria.
Level 1 Not applicable.
Level 2 Programs OD-1, P1, and OD-6 will be considered operational when
: a. The MCPR calculated by BUCLE and the process computer either
: 1. Are in the same fuel assembly and do not differ in value by more than 2%, or
: 2. For the case in which the MCPR calculated by the process computer is in a different assembly than that calculated by BUCLE, for each assembly, the MCPR and CPR calculated by the two methods shall agree within 2%.
: b. The MLHGR calculated by BUCLE and the process computer either
: 1. Are in the same fuel assembly and do not differ in value by more than 2%, or
: 2. For the case in which the MLHGR calculated by the process computer is in a different assembly than that calculated by BUCLE, for each assembly, the MLHGR and LHGR calculated by the two methods shall agree within 2%.
: c. The maximum average planar linear heat generation rate (MAPLHGR) calculated by BUCLE and the process computer either
: 1. Are in the same fuel assembly and do not differ in value by more than 2%, or
: 2. For the case in which the MAPLHGR calculated by the process computer is in different assembly than that calculated by BUCLE, for each 14.2-84

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 assembly, the MAPLHGR and APLHGR calculated by the two methods shall agree within 2%.
: d.      The LPRM gain adjustment factors calculated by BUCLE and the process computer agree to within 2%.
: e.      The remaining programs will be considered operational on successful completion of the static and dynamic testing.
14.2.12.3.14        Test Number 14 - Reactor Core Isolation Cooling System 14.2.12.3.14.1 Purpose. The purpose of this test is to verify the proper operation of the RCIC system over its expected operating pressure range.
14.2.12.3.14.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
14.2.12.3.14.3 Description. The RCIC system test consists of two parts: Injection to the condensate storage tank and injection to the reactor vessel. The initial condensate storage tank (CST) injections consist of manual and automatic starts at 150 psi and at rated reactor pressure. The pump discharge pressure during these tests is throttled to 100 psi above reactor pressure. This initial testing is done to demonstrate system operability and making initial controller adjustments. This is followed by vessel injections beginning with cold RCIC hardware; cold being defined as a minimum of 3 days without any kind of RCIC operation.
The vessel injections verify the adequacy of the startup transient and also include steady-state controller adjustments. Five consecutive successful system initiations starting from cold condition and with the same equipment settings are necessary to demonstrate system reliability.
Two of these initiations are vessel injection tests with one performed using the controllers on the remote shutdown panel.
After final controller settings are determined, three CST injections at rated pressure and/or 150 psig pressure are done with initially cold RCIC equipment. These runs provide a bench mark for future surveillance testing and provide further assurance of system reliability.
A demonstration of extended operation of 30 minutes of continuous running until pump and turbine oil temperature is stabilized is scheduled at a convenient time during the test program, probably in conjunction with one of the system reliability tests. During this demonstration, automatic RCIC suction transfer from the CST to the suppression pool will be performed to confirm system stability in this configuration.
14.2-85

COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                           December 2003 During vessel injections all reactor steam is routed to the turbine bypass valves. The steam admission valves of the main and feedwater turbines should be closed whenever the moisture carryover threshold is reached.
14.2.12.3.14.4 Criteria.
Level 1 The average pump discharge flow must be equal to or greater than 600 gpm after 30 sec have elapsed from automatic initiation at any reactor pressure between 150 psig and rated.
The RCIC turbine must not trip off or isolate during auto or manual start tests.
If any Level 1 criteria are not met, the reactor operation will be restricted to the power level defined by Figure 14.2-5. This restriction is in addition to any restrictions defined by the Technical Specifications.
Level 2 The turbine gland seal condenser system shall be capable of preventing steam leakage to the atmosphere.
The differential pressure switch for the RCIC steam supply line high flow isolation trip shall be adjusted to actuate at the valve specified in the Technical Specifications (about 300%).
The speed and flow control loops shall be adjusted so that the decay ratio of any RCIC system related variable is not greater than 0.25.
To provide an overspeed trip avoidance margin, the transient start first and subsequent speed peaks shall not exceed 5% above the rated RCIC turbine speed.
14.2.12.3.15        Test Number 15 Not applicable.
14.2.12.3.16        Test Numbers 16A and 16B 14.2.12.3.16.1 Test Number 16A - Selected Process Temperatures.
14.2.12.3.16.1.1 Purpose. The purpose of this test is to (a) ensure that the measured bottom head drain temperature corresponds to bottom head coolant temperature during normal operations, (b) identify any reactor operating modes that cause temperature stratification, (c) determine the proper setting of the low flow control limiter for the recirculation pumps to 14.2-86

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 avoid coolant temperature stratification in the RPV bottom head region, and (d) familiarize the plant personnel with the temperature differential limitations of the reactor system.
14.2.12.3.16.1.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
14.2.12.3.16.1.3 Description. The adequacy of bottom drain line temperature sensors will be determined by comparing it with recirculation loop coolant temperature when core flow is 100% of rated.
During initial heatup while at hot standby conditions, the bottom drain line temperature, recirculation loop suction temperature, and applicable reactor parameters are monitored as the recirculation flow is slowly lowered to either minimum stable flow or the low recirculation pump speed minimum valve position, whichever is the greater. The effects of cleanup flow will be investigated as operational limits allow. Using this data it can be determined whether coolant temperature stratification occurs and if so, what minimum recirculation flow will prevent it.
Monitoring the preceding information during planned pump trips will determine if temperature stratification occurs in the idle recirculation loops or in the lower plenum when one or more loops are inactive.
All data will be analyzed to determine if changes in operating procedures are required.
14.2.12.3.16.1.4 Criteria.
Level 1
: a. The reactor recirculation pumps shall not be started nor flow increased unless the coolant temperatures between the steam dome and bottom head drain are within 145&deg;F (81&deg;C).
: b. The recirculation pump in an idle loop must not be started, active loop flow must not be raised, and power must not be increased unless the idle loop suction temperature is with in 50&deg;F (28&deg;C) of the active loop suction temperature. If two pumps are idle, the loop suction temperature must be within 50&deg;F (28&deg;C) of the steam dome temperature before pump startup.
Level 2 During two-pump operation at rated core flow, the bottom head temperature as measured by the bottom drain line thermocouple should be within 30&deg;F (17&deg;C) of the recirculation loop temperatures.
14.2-87

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 14.2.12.3.16.2 Test Number 16B - Water Level Reference Leg Temperature Measurement.
14.2.12.3.16.2.1 Purpose. The purpose of this test is to measure the reference leg temperature and recalibrate the affected level instruments if the measured temperature is different than the value assumed during the initial calibration.
14.2.12.3.16.2.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing. All applicable system instrumentation is installed and calibrated.
14.2.12.3.16.2.3 Description. To monitor the reactor vessel water level, five level instrument systems are provided. These are
: a.      Shutdown range level system,
: b.      Narrow range level system,
: c.      Wide range level system,
: d.      Fuel zone level system, and
: e.      Upset range.
These systems are used respectively as follows:
: a.      Water level measurement in cold shutdown conditions (shutdown range level system),
: b.      Feedwater flow and water level control functions in hot operating conditions (narrow range level system),
: c.      Safety functions in hot operating conditions (wide range level system),
: d.      Safety functions in cold shutdown conditions (fuel zone level system), and
: e.      High water level protection, hot operating condition (upset range).
The test will be done at rated temperature and pressure and under steady-state conditions and will verify that the reference leg temperature of the level instrument is the value assumed during initial calibration. If not, the instruments will be recalibrated using the measured value.
14.2-88

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                       December 2003 14.2.12.3.16.2.4 Criteria.
Level 1 Not applicable.
Level 2 The indicator readings on the narrow range level system should agree with +/- 1.5 in. of the average readings or the reading calculated from the correct reference leg temperatures.
The wide and upset range level system indicators should agree within +/- 6 in. of the average readings or the readings calculated from the correct reference leg temperatures.
14.2.12.3.17        Test Number 17 - System Expansion 14.2.12.3.17.1 Purpose. The purpose of this test is to (a) verify that piping systems and components are unrestrained with respect to thermal expansion, (b) verify that suspension components are functioning in the specified manner, (c) provide confirmatory data for the calculated stress levels in nozzles and weldments, (d) perform an inspection to satisfy ASME Section XI, IWF-220 post heatup (shakedown) inspection requirements, and (e) satisfy the inspection requirements for the condensate and feedwater systems according to Regulatory Guide 1.68.1.
14.2.12.3.17.2 Prerequisites. Necessary preoperational tests have been completed. The preheatup examination program relating to component supports as contained in the CGS Preservice Inspection Program Plan has been completed. The POC has reviewed and the Plant Manager has approved the test procedure and initiation of testing. Instrumentation has been installed and calibrated.
14.2.12.3.17.3 Description. A significant mechanical design objective for nuclear piping support systems is to provide for unrestricted thermal expansion of piping and components, from ambient to rated temperature. The combination of visual and remote monitoring of selected piping systems will provide the data necessary to evaluate the support system. The criteria used for system selection is Standard Review Plan Section 3.9.2 and those systems with a normal operating temperature greater than 250&deg;F. The drywell piping systems selected for visual inspection and remote monitoring are the following:
: a.      Reactor recirculation,
: b.      Main steam,
: c.      Feedwater,
: d.      Residual heat removal (shutdown cooling supply and return line),
: e.      Reactor core isolation cooling (steam supply and head spray line),
14.2-89

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003
: f. Safety/relief valve discharge piping, and
: g. Reactor water cleanup.
In addition, visual inspections only of the following drywell systems will be conducted:
: a. High-pressure core spray,
: b. Low-pressure core spray,
: c. Sacrificial shield wall penetrations,
: d. Residual heat removal (LPCI) injection lines,
: e. Main steam flow instrumentation piping,
: f. Main steam drain piping,
: g. Reactor head vent piping,
: h. Reactor coolant sample piping, and
: i. Standby liquid control injection piping.
Piping support system components (hangers, sway struts, boxes, snubbers, and whip restraints) for the systems listed will be visually inspected at ambient (less than or equal to 200&deg;F), during the initial heatup cycle at an intermediate temperature (200&deg;F to 300&deg;F, equivalent to 30 psig reactor pressure) and at normal operating temperature (545&deg;F, equivalent to 1000 psig reactor pressure). Data from the remote monitoring instrumentation will be recorded and evaluated at similar intervals. Exceptions to this are feedwater, main steam relief valve (MSRV) discharge piping, and the reactor head spray and vent piping above the drywell bulkhead. The feedwater piping will attain rated temperatures only at higher reactor power levels, which precludes drywell entry. The MSRV piping is only heated up during valve actuation, which also represents a potential inspection personnel hazard. The area above the bulkhead is considered hazardous due to confinement and high temperatures. The methods used to evaluate these are as follows:
: a. Feedwater drywell piping is instrumented and will be evaluated at 25% and 100% reactor power using the data collected by the lanyard potentiometers.
: b. Two MSRV lines will be instrumented allowing data evaluation to be applied to all lines during SRV actuation.
: c. The piping above the bulkhead will be visually inspected prior to drywell head installation.
Feedwater and the SRV piping systems will also be inspected during the shakedown inspection.
The instrumented nodes will be provided with three sensors to indicate movement in three orthogonal plans. The actual node locations will be selected through a coordinated effort between the CGS Plant Technical and Technology organizations. In this way the analytically best suited node will be coupled with accessible locations. General Electric will provide 14.2-90

COLUMBIA GENERATING STATION                         Amendment 57 FINAL SAFETY ANALYSIS REPORT                        December 2003 locations and acceptance criteria for the recirculation and main steam systems. The Energy Northwest Mechanics Department will provide similar information for the remainder of the systems tested. The instruments will provide thermal movement and vibration data that will be compared with predicted values. If these measured displacements confirm the calculated values, coupled with acceptable visual inspections, the piping system will be considered to have responded as designed. The type of lanyard potentiometer monitors used enable the collection of thermal movement and vibration data. With the acceptance criteria for all testing based on the system design, conformance to the acceptance criteria indicates adherence to the analytical limits.
On completion of the startup test, the piping response data and the completed test procedure will be reviewed by the Energy Northwest Engineering Department responsible for the Stress Report Review and GE. The review will determine if the test results indicate the piping responded in a manner consistent with the Stress Report predictions and the ASME Code limits.
An Energy Northwest Level 3 inspector and the American Nuclear Insurers (ANI) will sign all data sheets performing ASME Section XI inspections.
The drywell piping testing/inspections will be conducted during the PATP as follows:
: a. The visual inspections and thermal expansion data will be taken during the initial reactor heatup at thermal equilibrium conditions,
: b. During the course of the PATP, data will be collected during steady state and transient conditions for vibration level evaluation, and
: c. Near the end of the PATP a final drywell entry and inspection is scheduled.
Visual inspections will be conducted on selected piping systems outside the drywell during thermal equilibrium, steady-state operation, and selected transient conditions. The systems selected are:
: a. Main steam,
: b. Condensate and feedwater,
: c. RCIC steam supply and exhaust,
: d. RCIC injection piping,
: e. RHR shutdown cooling supply and return,
: f. Reactor water cleanup, and
: g. Main steam leakage control system.
14.2-91

COLUMBIA GENERATING STATION                           Amendment 57 FINAL SAFETY ANALYSIS REPORT                          December 2003 14.2.12.3.17.4 Criteria.
Level 1 Thermally induced displacement of system components shall be unrestrained with no evidence of binding or impairment.
Spring hangers shall not be bottomed out or have the spring fully stretched.
Snubbers shall not reach the limits of their travel. The displacements at the established transducer locations used to measure pipe deflections shall not exceed the allowable values.
The allowable values of displacement shall be based on not exceeding ASME Section III Code Stress allowables.
Level 2 Spring hangers will be in their operating range (between the hot and cold settings).
Snubber settings must be within their expected operating range.
The displacements at the established transducer locations shall not exceed the expected values.
14.2.12.3.18       Test Number 18 - Core Power Distribution 14.2.12.3.18.1 Purpose. The purpose of this test is to determine the reproducibility of the TIP system readings.
14.2.12.3.18.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing. The TIP detector and dummy detector, ball valve time delay, core top and bottom limits, clutch, x-y recorder, and purge system will have been shown to be operational. Instrumentation has been calibrated and installed.
14.2.12.3.18.3 Description. The TIP reproducibility consists of a random noise component and a geometric component. The geometric component is due to variation in the water gap geometry and TIP tube orientation from TIP location to location. Measurement of these components is obtained by taking repetitive TIP readings at a single TIP location, and by analyzing pairs of TIP readings taken at TIP locations which are symmetrical about the core diagonal of fuel loading symmetry.
One set of TIP data will be taken at the 50% power level and at least one other set at 75%
power or above.
14.2-92

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 The TIP data will be taken with the reactor operating with an octant symmetric rod pattern and at steady-state conditions.
The total TIP reproducibility is obtained by dividing the standard deviation of the symmetric TIP pair nodal ratios by two. The nodal TIP ratio is defined as the nodal base value of the TIP in the lower right half of the core divided by its symmetric counterpart in the upper left half.
The total TIP reproducibility value that is compared with the test criterion is the average value of the data sets taken.
The random noise uncertainty is obtained from successive TIP runs made at the common hole, with each of the TIP machines making six runs. The standard deviation of the random noise is derived by taking the square root of the average of the variances at nodal levels 5 through 22, where the nodal variance is obtained from the fractional deviations of the successive TIP values about their nodal mean value.
The geometric component of TIP reproducibility is obtained by statistically subtracting the random noise component from the total TIP reproducibility.
14.2.12.3.18.4 Criteria.
Level 1 Not applicable.
Level 2 The total TIP uncertainty (including random noise and geometrical uncertainties) obtained by averaging the uncertainties for all data sets shall be less than 6.0%.
The data acquired for random noise uncertainty does not have specific acceptance criteria value and is used only to aid in the analysis of the TIP uncertainty.
14.2.12.3.19        Test Number 19 - Core Performance 14.2.12.3.19.1 Purpose. The purposes of this test are to (a) evaluate the core thermal power, and (b) evaluate the following core performance parameters are within limits: (a) maximum linear heat generation rate (MLHGR), (b) minimum critical power ratio (MCPR), and (c) maximum average planar linear heat generation rate (MAPLHGR).
14.2.12.3.19.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
System instrumentation has been installed and calibrated, and test instrumentation has been calibrated.
14.2-93

COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                           December 2003 14.2.12.3.19.3 Description. The core performance evaluation is employed to determine the principal thermal and hydraulic parameters associated with core behavior. These parameters are
: a.      Core flow rate,
: b.      Core thermal power level,
: c.      MLHGR,
: d.      MAPLHGR, and
: e.      MCPR.
The core performance parameters will be evaluated by manual calculation techniques described in Startup Test Instruction 19 or may be obtained from the process computer.
If the process computer is used as a primary means to obtain these parameters, it must be proven that it agrees with BUCLE within 2% on all thermal parameters (see Test Number 13).
If both BUCLE and the process computer are not available, the manual calculation techniques described in Startup Test Instruction 19 can be used for the core performance evaluation.
14.2.12.3.19.4 Criteria.
Level 1 The MLHGR of any rod during steady-state conditions shall not exceed the limit specified by the Technical Specifications.
The steady-state MCPR shall not exceed the minimum limits specified by the Technical Specifications.
The MAPLHGR shall not exceed the limits specified by the Technical Specifications.
Steady-state reactor power shall be limited to the rated MWt and values on or below the design flow control line. Core flow shall not exceed its rated value.
Level 2 Not applicable.
14.2.12.3.20       Test Number 20 - Steam Production 14.2.12.3.20.1 Purpose. The purpose of performing this test is to demonstrate that the NSSS is providing steam sufficient to satisfy all appropriate warranties as defined in the contract.
14.2-94

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 14.2.12.3.20.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
14.2.12.3.20.3 Description. Warranty demonstration consists of recording sufficient data under steady-state conditions to determine the reactor power level, the pressure and quality of the steam, and the steam flow rate from the reactor.
These measurements will include the temperature, pressure, and flow rate of feedwater entering the reactor; the energy added to the reactor water by the recirculation drive pumps; the flow rate through and temperature entering and leaving the reactor cleanup system; the flow rate and temperature of the CRD cooling water; the carryover of reactor water into the steam lines, and the steam pressure outside the drywell near the MSIV.
Each set of measurements shall be taken at frequent intervals, every 5 or 10 minutes as appropriate, for a total test run duration of 4 hr. The average measure quantity, suitably corrected for all calibration factors, is used to determine NSSS output during the test run.
Where the contract requires a 100-hr demonstration, two test runs shall be made, one in the first 50 hr and one in the second 50 hr. The demonstrated output is the average of the values from the two test runs. During the balance of the 100-hr demonstration, the NSSS output shall be held constant within +/- 5% of the nominal steam flow rate as indicated by the installed plant feedwater instrumentation.
14.2.12.3.20.4 Criteria.
Level 1
: a. The NSSS parameters as determined by using normal operating procedures shall be within the appropriate license restrictions.
: b. The NSSS will be capable of supplying steam in an amount and quality corresponding to the final feedwater temperature and other conditions shown on the rated steam output curve in the NSSS technical description. The rated steam output curve provides the warrantable reactor vessel steam output as a function of feedwater temperature, as well as warrantable steam conditions at the outboard MSIVs.
: c. Thermodynamic parameters are consistent with the 1967 ASME steam tables.
Correction techniques for conditions that differ from the contracted conditions will be mutually agreed to prior to the performance of the test.
Level 2 Not applicable.
14.2-95

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 14.2.12.3.21       Test Number 21 - Core Power-Void Mode 14.2.12.3.21.1 Purpose. The purpose of this test is to measure the stability of the core power-void dynamic response and to demonstrate that its behavior is within specified limits.
14.2.12.3.21.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
System instrumentation has been installed and calibrated, and test instrumentation calibrated.
14.2.12.3.21.3 Description. The core power void loop mode that results from a combination of the neutron kinetics and core thermal hydraulic dynamics is least stable near the natural circulation end of the rated 100% power rod line. A fast change in the reactivity balance is obtained by a pressure regulator step change (see test 22) and by moving a very high worth rod only 1 or 2 notches. Both local flux and total core response will be evaluated by monitoring selected LPRMs during the transient.
14.2.12.3.21.4 Criteria.
Level 1 The transient response of any system-related variable to any test input must not diverge.
Level 2 The decay ratio for each system-related variable containing oscillatory modes must be less than or equal to 0.5.
14.2.12.3.22       Test Number 22 - Pressure Regulator 14.2.12.3.22.1 Purpose. The purposes of this test are to: (a) determine the optimum settings for the pressure control loop by analysis of the transients induced in the reactor pressure control system by means of the pressure regulators, (b) demonstrate the backup capability of the pressure regulators via simulated failure of the controlling pressure regulator and to set the regulating pressure difference between the two regulators at an appropriate value, (c) demonstrate smooth pressure control transition between the control valves and bypass valves when reactor steam generation exceeds steam used by the turbine, and (d) demonstrate that affected parameters are within acceptable limits during pressure-regulator-induced transient maneuvers.
14.2.12.3.22.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2-96

COLUMBIA GENERATING STATION                            Amendment 57 FINAL SAFETY ANALYSIS REPORT                           December 2003 14.2.12.3.22.3 Description. The pressure setpoint will be decreased rapidly and then increased rapidly by about 10 psi (0.7 kg/cm2) and the response of the system will be measured in each case. It is desirable to accomplish the setpoint change in less than 1 sec. At specified test conditions the load limit setpoint will be set so that the transient is handled by control valves, bypass valves, and both. The regulators will be tested by simulating a failure of a selected pressure regulator so that the other regulator will take over control. The response of the system will be measured and evaluated and regulator settings will be optimized.
14.2.12.3.22.4 Criteria.
Level 1 The transient response of any pressure control system related variable to any test input must not diverge.
Level 2
: a.      Pressure control system variables may contain oscillatory modes of response. In these cases, the decay ratio for each controlled mode of response must be less than or equal to 0.25,
: b.      The pressure response time from initiation of pressure setpoint change to the turbine inlet pressure peak shall be 10 sec,
: c.      Pressure control system deadband, delay, etc., shall be small enough that steady-state limit cycles (if any) shall produce steam flow variations no larger than +/- 0.5% of rated steam flow,
: d.      For all pressure regulator transients the peak neutron flux and/or peak vessel pressure shall remain below the scram settings by 7.5% and 10 psi respectively (maintain a plot of power versus the peak variable values along the 100% rod line), and
: e.      The variation in incremental regulation (ratio of the maximum to the minimum valve of the quantity, incremental change in pressure control signal/incremental change in steam flow, for each flow range) shall meet the following:
14.2-97

COLUMBIA GENERATING STATION                          Amendment 57 FINAL SAFETY ANALYSIS REPORT                         December 2003 Steam Flow Obtained With Valves Wide Open (%)                 Variation 0 to 90                        4:1 90 to 97                       2:1 90 to 99                       5:1 Level 3
: a. Additional dynamics of the control system, outside of the regulator compensation filters, shall be equivalent to a time constant no greater than 0.10 sec. This also includes any dead time which may exist,
: b. Control or bypass valve motion must respond to pressure inputs with deadband (insensitivity) no greater than +/- 0.1 psi, and
: c. Dynamics of both pressure regulators will be essentially identical.
14.2.12.3.23        Test Number 23 - Feedwater System 14.2.12.3.23.1 23A - Water Level Setpoint and Manual Flow Changes.
14.2.12.3.23.1.1 Purpose. The purpose of this test is to verify that the feedwater system has been adjusted to provide acceptable reactor water level control.
14.2.12.3.23.1.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.23.1.3 Description. Reactor water level setpoint changes of approximately 3 in. to 6 in. (8 cm to 15 cm) will be used to evaluate (and adjust if necessary) the feedwater control system settings for all power and feedwater pump modes. The level setpoint changes will also demonstrate core stability to subcooling changes.
14.2.12.3.23.1.4 Criteria.
Level 1 The transient response of any level control system-related variable to any test must not diverge.
14.2-98

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 Level 2
: a. Level control system-related variables may contain oscillatory modes of response. In these cases, the decay ratio for each controlled mode of response must be less than or equal to 0.25;
: b. The open loop dynamic flow response of each feedwater actuator (turbine or valve) to small (<10%) step disturbances shall be
: 1.       Maximum time to 10% of a step disturbance             1.1 sec
: 2.       Maximum time from 10% to 90% of a                     1.9 sec step disturbance
: 3.       Peak overshoot (% of step disturbance)                15%
: 4.       Settling time, 100%, +/- 5%                             14 sec
: c. The average rate of response of the feedwater actuator to large (>20% of pump flow) step disturbances shall be between 10% and 25% rated feedwater flow/sec. This average response rate will be assessed by determining the time required to pass linearly through the 10% and 90% response points; and
: d. At steady-state generation for the 3/1 element system, the input scaling to be mismatch gain should be adjusted such that level error due to biased mismatch gain output should be within +/- 1 in.
Level 3
: a. The dynamic response of each individual level or flow sensor shall be as fast as possible. Band width must be at least 4.0 radians/sec (faster than 0.25 sec equivalent time constant), except for the steam flow sensors which must have band width of at least 1.0 radian/sec (faster than 1.0 sec equivalent time constant);
: b. Vessel level, feedwater flow, and steam flow sensors must be installed with sufficiently short lines and proper damping adjustment so that no resonances exist;
: c. Initial settings of the function generators should give a straight line. The function generators must be adjusted so that the change in slope (actual fluid flow change divided by demand change for small disturbances) shall not exceed a factor of 2 to 1 (maximum slope versus minimum slope) over the entire 20% to 14.2-99

COLUMBIA GENERATING STATION                          Amendment 54 FINAL SAFETY ANALYSIS REPORT                         April 2000 100% feed flow range. Also the function generators should be used to minimize the differences between feedwater actuators (pumps and/or valves); and
: d.      All auxiliary controls which have direct impact on reactor level and feedwater control (e.g., feed pump minimum recirculation flow valve control) should be functional, responsive, and stable. The minimum low valve control should be fast enough to avoid pump trips and yet slower than the feedwater startup valve to avoid possible reactor flux scram due to a cold water slug.
14.2.12.3.23.2 23B - Loss of Feedwater Heating 14.2.12.3.23.2.1 Purpose. The purpose of this test is to demonstrate adequate response to a feedwater temperature loss.
14.2.12.3.23.2.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.23.2.3 Description. The condensate/feedwater system will be studied to determine the single failure that will cause the largest loss in feedwater heating. This event will then be performed at between 80% and 90% power with the recirculation flow near its rated value.
14.2.12.3.23.2.4 Criteria.
Level 1
: a.      For the feedwater heater loss test, the maximum feedwater temperature decrease due to a single failure case must be 100&deg;F. The resultant MCPR must be greater than the fuel thermal safety limit; and
: b.      The increase in simulated heat flux cannot exceed the predicted Level 2 value by more than 2%. The predicted value will be based on the actual test values of feedwater temperature change and power level.
Level 2 The increase in simulated heat flux cannot exceed the predicted value in the Transient Safety Analysis Design Report referenced to the actual feedwater temperature change and power level.
LDCN-99-000                                   14.2-100

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998 14.2.12.3.23.3 22C - Feedwater Pump Trip.
14.2.12.3.23.3.1 Purpose. The purpose of this test is to demonstrate the capability of the automatic core flow runback feature to prevent low water level scram following the trip of one feedwater pump.
14.2.12.3.23.3.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.23.3.3 Description. One of the two operating feedwater pumps will be tripped and the automatic recirculation runback circuit will act to drop the power to within the capacity of the remaining feedwater pump. Prior to the test a simulation of the feedwater pump trip will be done to verify the runback capability of the recirculation system. This test should be performed after test 23D (limiting pump speeds).
14.2.12.3.23.3.4 Criteria.
Level 1 Not applicable.
Level 2 The reactor shall avoid low water level scram by a 3-in. margin from an initial water level halfway between the high- and low-level alarm setpoints.
14.2.12.3.23.4 23D - Maximum Feedwater Runout Capability.
14.2.12.3.23.4.1 Purpose. This test calibrates the feedwater flow and determines if the maximum feedwater runout capability is compatible with the licensing.
14.2.12.3.23.4.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.23.4.3 Description. The test is divided into two parts: first, the initial calibration of the speed controller and second, verification of calibration by measured data which includes a verification that the maximum feedwater flows do not exceed the flows (different flows at different vessel pressures) in the FSAR.
: a.      The speed controller calibration is done by first obtaining vendor pump performance curves. The pump performance curves are then used to determine 14.2-101

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 the turbine speed corresponding to the maximum allowable flow rated vessel pressure specified by the FSAR and the minimum speed that corresponds to 0%
flow at 865 psia. Additionally, for good level control system performance it should reach 115% nuclear boiler rated (NBR) flow at 1080 psia and 90% NBR flow at 1024 psi in the one pump tripped condition. Adjustable equipment (i.e.,
feed pump turbine speed loops, mechanical limiters, and feedwater control system function generator, etc.) are set to prevent the feedwater pumps from exceeding their maximum allowed output and yet allow the desirable performance; and
: b. During the data collection and verification of calibration portion of the test, pressure, flow, and controller data will be collected between 60%-100% power.
Measured data will be compared against expected values to ensure proper calibration. The measured maximum flow will be adjusted to the FSAR pressures using the measured data. The maximum flows stated in the FSAR are used as licensing assumptions; therefore, the FSAR maximum flows should not be exceeded. If, however, the FSAR maximum flows are exceeded two options exist. The system can be adjusted so that the licensing assumption is not exceeded or an additional penalty can be applied to the CPR. The CPR can be revised by applying a 0.01 adder for each 5% of rated feedwater flow difference (between the determined actual maximum flow and the FSAR maximum flow).
14.2.12.3.23.4.4 Criteria.
Level 1 Maximum speed attained shall not exceed the speeds which will give the following flows with the normal complement of pumps operating.
: a. F% NBR at P psia, and
: b.    [F% + A(P-P rated)] % NBR at P rated, psig where: F = 135%, P = 1075 psia, A = 0.2%/psig.
Level 2 The maximum speed must be greater than the calculated speeds required to supply:
: a. With rated complement of pumps -115% NBR at 1075 psi, and
: b. One feedwater pump tripped condition -68% NBR at 1025 psia.
NOTE:         Level 1 test criteria are originated from NSSS transient Performance Engineering Unit. Level 2 test criteria are originated from the Control System Design Unit.
14.2-102

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 14.2.12.3.24        Test Number 24 - Turbine Valve Surveillance 14.2.12.3.24.1 Purpose. The purpose of this test is to demonstrate the acceptable procedures and maximum power levels for recommended periodic surveillance testing of the main turbine, control, and stop and bypass valves without producing a reactor scram.
14.2.12.3.24.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.24.3 Description. Individual main turbine control and stop and bypass valves are tested routinely during plant operation as required for turbine surveillance testing. At several test points the response of the reactor will be observed. It is recommended that the maximum possible power level for performance of these tests along the 100% load line be established.
First, actuation should be between 45% and 65% power and used to extrapolate to the next test point between 75% and 90% power and ultimately to the maximum power test condition with ample margin to scram. Note the proximity to APRM flow bias scram point and preconditioning cladding interim operating management recommendation (PCIOMR) envelope.
Each valve test will be manually initiated and reset. The rate of valve stroking and timing of the close-open sequence will be such that the minimum practical disturbance is introduced and that PCIOMR limits are not exceeded.
14.2.12.3.24.4 Criteria.
Level 1 Not applicable.
Level 2
: a.      Peak neutron flux must be at least 7.5% below the scram trip setting. Peak vessel pressure must remain at least 10 psi below the high pressure scram setting. Peak heat flux must remain at least 5.0% below its scram trip point; and
: b.      Peak steam flow in each line must remain 10% below the high flow isolation trip setting.
14.2-103

COLUMBIA GENERATING STATION                             Amendment 53 FINAL SAFETY ANALYSIS REPORT                           November 1998 14.2.12.3.25       Test Number 25 - Main Steam Isolation Valves 14.2.12.3.25.1 25A - Main Steam Isolation Valve Function Tests.
14.2.12.3.25.1.1 Purpose. The purposes of this test are to (a) functionally check the MSIVs for proper operation at selected power levels, (b) determine isolation valve closure times, and (c) determine a maximum power at which full closures of a single valve can be performed without a scram.
14.2.12.3.25.1.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.25.1.3 Description. At 5% and greater reactor power levels, individual fast closure of each MSIV will be performed to verify their functional performance and to determine closure times. The times to be determined are (a) the time from deenergizing the solenoids until the valve is 100% closed (tsol), and (b) the valve stroke time (ts) Time tsol equals the interval from deenergizing the solenoids until the valve reaches 90% closed plus 1/8 times the interval from 10% to 90% closure. Time ts equals the interval from when the valve starts to move until it is 100% closed and is based on the interval from 10% to 90% closure and linear valve travel from 0% to 100% closure.
To determine the maximum power level at which full individual closures can be performed without a scram, first actuation will be performed between 40% to 55% power and used to extrapolate to the next test point between 60% and 85% power and ultimately to the maximum power test condition with ample margin to scram.
14.2.12.3.25.1.4 Criteria.
Level 1 The MSIV stroke time (ts) shall be not faster than 3.0 sec (average of the fastest valve in each steam line) and for any individual valve 2.5 sec ts5 sec. Total effective closure time for any individual MSIV shall be tsol plus the maximum instrumentation delay time as determined in preoperational test GE-4 and shall be 5.5 sec.
Level 2
: a. The reactor shall not scram or isolate, and
: b. During full closure of individual valves, peak valve pressure must be 10 psi (0.7 kg/cm2) below scram, peak neutron flux must be 7.5% below scram, and 14.2-104

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 steam flow in individual lines must be 10% below the isolation trip setting. The peak heat flux must be 5% less than its trip point.
14.2.12.3.25.2 25B - Full Reactor Isolation.
14.2.12.3.25.2.1 Purpose. The purpose of this test is to determine the reactor transient behavior that results from the simultaneous full closure of all MSIVs.
14.2.12.3.25.2.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.25.2.3 Description. A test of the simultaneous full closure of all MSIVs will be performed at >75% of rated thermal power. Correct performance of the RCIC and relief valves will be shown. Reactor process variables will be monitored to determine the transient behavior of the system during and following the main steam line isolation.
14.2.12.3.25.2.4 Criteria.
Level 1
: a.      Reactor must scram to limit the severity of the neutron flux and simulated fuel surface heat flux transient,
: b. Feedwater system settings must prevent flooding of the steam lines,
: c.      The recorded MSIV full closure times must meet the previously stated timing specifications (test 25A), and
: d.      The positive change in vessel dome pressure occurring within 30 sec after closure of all MSIV valves must not exceed the Level 2 criteria by more than 25 psi. The positive change in simulated heat flux shall not exceed the Level 2 criteria by more than 2% of rated value.
Level 2
: a. The temperature measured by the thermocouples on the discharge side of the SRVs must return to within 10&deg;F of the temperature recorded before the valve was opened. If pressure sensors are available, they shall return to their initial state upon valve closure;
: b.      For the full MSIV closure from full power predicted analytical results based on beginning-of-cycle design basis analysis, assuming no equipment failures and 14.2-105

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998 applying appropriate parametric corrections, will be used as the basis to which the actual transient is compared.
: c.      Initial action of RCIC and HPCS shall be automatic if low water level (L2) is reached, and system performance shall be within specification, and
: d.      Recirculation pump trip shall be initiated if low water level (L2) is reached.
Recirculation pump power will shift to the LFMGs if low water level (L3) is reached.
14.2.12.3.26        Test Number 26 - Relief Valves 14.2.12.3.26.1 Purpose. The purposes of this test are to (a) verify the proper operation of the main system relief valves, (b) verify that the discharge piping is not blocked, (c) verify their proper seating following operation, (d) obtain signature information of relief valve response for subsequent comparisons, and (e) determine their capacities.
14.2.12.3.26.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.26.3 Description. The main steam relief valves will each be opened using the manual control mode so that at any time only one is open. During heatup at 250 psig (17.5 kg/cm2), each valve will be opened and closed to demonstrate proper functioning. Flow verification of each relief valve will be determined at rate pressure by observing bypass or control valve motion and by observing a change in discharge thermocouple readings. Proper reseating of each relief valve will be verified by observation of temperatures in the relief valve discharge piping. At selected test conditions each valve will be manually actuated and appropriate system parameters recorded during the transient. Data analysis will include a comparison of the system response during each of the valve actuations. Capacity of each relief valve will be determined at rated pressure by the amount of bypass or control valve closure required to maintain reactor pressure.
14.2.12.3.26.4 Criteria.
Level 1 There should be positive indication of steam discharge during the manual actuation of each valve.
The sum of capacity measurements from all relief valves shall be equal to or greater than 15.8 x 106 lb/hr at an inlet pressure of 103% at 1205 psig. The total flow capacity of the SRVs used in the automatic depressurization system must be equal to or greater than 4.8 x 106 lb/hr 14.2-106

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 at 1125 psig when the valve having the highest measured capacity is assumed to be out of service.
Level 2 Relief valve leakage shall be low enough that the temperature measured by the thermocouples in the discharge side of the valves returns to within 10&deg;F (5.6&deg;C) of the temperature recorded before the valve was opened. The thermocouples are expected to be operating properly.
The pressure regulator must satisfactorily control the reactor transient and close the control valves or bypass valves by an amount equivalent to the relief valve discharge. The valve transients recorder signatures for each valve must be returned to GE in San Jose for relative system response comparison.
Each relief valve shall have a capacity between 90% and 122.5% of its expected value corrected to an inlet pressure of 103% at 1205 psig.
No more than 25% of the relief valves may have an individual corrected flow rate that is between 90% and 100% of their expected flow rates.
The transient recorder signatures for each valve must be analyzed for relative system response comparison.
14.2.12.3.27        Test Number 27 - Turbine Trip and Generator Load Rejection 14.2.12.3.27.1 Purpose. The purpose of this test is to demonstrate the response of the reactor and its control systems to protective trips in the turbine and generator.
14.2.12.3.27.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing. All controls and interlocks are checked and instrumentation calibrated. The plant electrical system will be aligned in the normal mode for the operating condition at which the test is performed.
14.2.12.3.27.3 Description. Turbine trip (closure of the main turbine stop valves within 0.1 sec) and generator trip (closure of the main turbine control valves in about 0.1 sec to 0.2 sec) will be performed at selected power levels during the startup test program. At low power levels, reactor protection following the trip is provided by high neutron flux and vessel high pressure scram. For the protective trips occurring at intermediate and higher power levels, reactor will scram by relays, actuated by control or stop valve motion.
A generator trip will be performed at low power level such that nuclear boiler steam generation is just within the bypass valve capacity to demonstrate scram avoidance.
14.2-107

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998 For the trips performed at intermediate power range, reactor scram is most important in controlling the transient peaks.
Above 40% power, the recirculation pump circuit breakers are both automatically tripped, and subsequent transient pressure rise will be limited by the opening of the bypass valves initially and the SRVs if necessary.
14.2.12.3.27.4 Criteria.
Level 1
: a. For turbine and generator trips at power levels greater than 50% NBR, there should be a delay of less than 0.1 sec following the beginning of control or stop valve closure before the beginning of bypass valve opening. The bypass valves should be opened to a point corresponding to greater than or equal to 80% of their capacity within 0.3 sec from the beginning of control or stop valve closure motion;
: b. Feedwater system settings must prevent flooding of the steam line following these transients;
: c. The two pump drive flow coastdown transient during the first 6 sec must be equal to or faster than that specified in test 30B (see Figure 14.2-6);
: d. The positive change in vessel dome pressure occurring within 30 sec after either generator or turbine trip must not exceed the Level 2 criteria by more than 25 psi;
: e. The positive change in simulated heat flux shall not exceed the Level 2 criteria by more than 2% of the rated value; and
: f. The total time delay from start of turbine stop valve motion or control valve motion to the complete suppression of electrical arc between the fully open contacts of the recirculation pump trip (RPT) circuit breakers shall be less than 190 msec.
Level 2
: a. There shall be no MSIV closure during the first 3 minutes of the transient, and operator action shall not be required during that period to avoid the MSIV trip.
(The operator may take action after the first 3 minutes, including switching out of run mode. The operator may also switch out of run mode in the first 14.2-108

COLUMBIA GENERATING STATION                             Amendment 53 FINAL SAFETY ANALYSIS REPORT                            November 1998 3 minutes if measured data confirms that his action did not prevent MSIV closure);
: b. The positive change in vessel dome pressure and in simulated heat flux which occurs within the first 30 sec after the initiation of either generator or turbine trip must not exceed the predicted values. [Predicted values will be referenced to actual test conditions of initial power life and dome pressure and will use beginning of life (BOL) nuclear data. Worst case design or Technical Specification values of all hardware performance shall be used in the prediction with the exception of control rod insertion time and the delay from beginning of turbine control valve or stop valve motion to the generation of the scram signal.
The predicted pressure and heat flux will be corrected for the actual measured values of these two parameters];
: c. For the generator grip within the bypass valves capacity, the reactor shall not scram for initial thermal power values within that bypass valve capacity;
: d. The measured bypass capacity (in percent of rated power) shall be equal or greater than that used for the FSAR analysis (3,576,000 lb/hr);
: e. Recirculation LFMG sets shall take over after the initial recirculation pump trips and adequate vessel temperature difference shall be maintained;
: f. Feedwater level control shall avoid loss of feedwater due to possible high level (L8) trip during the event;
: g. Low water level total recirculation pump trip, HPCS, and RCIC shall not be initiated; and
: h. The temperature measured by thermocouples on the discharge side of the SRVs must return to within 10&deg;F of the temperature recorded before the valve was opened. In addition the acoustical monitors should indicate the valve is closed after the transient is complete.
14.2.12.3.28        Test Number 28 - Shutdown From Outside the Main Control Room 14.2.12.3.28.1 Purpose. The purpose of this test is to demonstrate that the reactor can be brought down from a normal initial steady-state power level to the point where cooldown is established and under control with reactor vessel pressure and water level controlled from outside the control room.
14.2-109

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998 14.2.12.3.28.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.28.3 Description. The test will be performed at a low power level and will consist of demonstrating the capability to control reactor level and pressure from outside the control room. The reactor will be scrammed and isolated from the control room. Reactor pressure and water level will be controlled using SRVs, RCIC, and RHR from outside the control room during the subsequent cooldown. In addition, the RHR shutdown cooling mode will be placed in service from outside the control room. All other operator actions not directly related to maintaining vessel water level and pressure will be performed in the main control room.
Operation from the main control room to protect or secure systems not related to the controlled cooldown of the reactor is permitted during this test. These actions are recorded and later evaluated to determine if they had bearing on the transient.
14.2.12.3.28.4 Criteria.
Level 1 Not applicable.
Level 2 During a simulated main control room evacuation, the reactor must be brought to the point where cooldown can be initiated, and the reactor vessel pressure and water level must be controlled using equipment and controls outside the main control room.
14.2.12.3.29       Test Number 29 - Recirculation Flow Control 14.2.12.3.29.1 29A - Valve Position Control.
14.2.12.3.29.1.1 Purpose. The purpose of this test is to demonstrate the recirculation flow control systems capability while in the valve position (POS) mode.
14.2.12.3.29.1.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing. All controls are checked and instrumentation calibrated.
14.2.12.3.29.1.3 Description. The testing of the recirculation flow control system follows a building block approach while the plant is ascending from low to high power levels:
Components and inner control loops are tested first, followed by drive flow control and plant power maneuvers to adjust and then demonstrate the outer loop controller performance.
Preliminary component and valve position loop tests will be run when the plant is in cold 14.2-110

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 shutdown to visually observe the hydraulic cylinder response. While operating at low power with the pumps using the low frequency power supply, small step changes will input into the position controller and the response recorded.
14.2.12.3.29.1.4 Criteria.
Level 1 The transient response of any recirculation system related variables to any test input must not diverge.
Level 2
: a. Recirculation system related variables may contain oscillatory modes of response. In these cases, the decay ratio for each controlled mode of response must be less than or equal to 0.25,
: b. Maximum rate of change of valve position shall be 10 +/- 1% sec.
During TC-3 and TC-6 while operating on the high speed (60 Hz) source, gains and limiters shall be set to obtain the following response,
: c. Delay time for position demand step shall be For step inputs of 0.5% to 5% 0.15 sec.
For step inputs of 0.2% to 0.5%-
: d. Response time for position demand step shall be For step inputs of 0.5% to 5% 0.45 sec.
For step inputs of 0.2% to 0.5%-, and
: e. Overshoot after a small position demand input (1% to 5%) step shall be 10% of magnitude of input.
Level 3
: a. Gains shall be set to give as fast a response as possible for small position demand input within the overshoot criterion (e) and without additional valve duty cycle. (See test 29B, Section 14.2.12.3.29.2, for valve duty cycle measurement.)
: b. Position loop deadband shall be 0.2% of full valve stroke.
14.2-111

COLUMBIA GENERATING STATION                            Amendment 53 FINAL SAFETY ANALYSIS REPORT                           November 1998 NOTE:       At a minimum, performing tests near the high and low end of the specified range is acceptable for verifying step input response.
14.2.12.3.29.2 29B - Recirculation Flow Loop Control.
14.2.12.3.29.2.1 Purpose. The purposes of this test are to (a) demonstrate the core flow systems control capability over the entire flow control range, including both core flow neutron flux and load following modes of operation, and (b) determine that all electrical compensators and controllers are set for desired system performance and stability.
14.2.12.3.29.2.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing. All controls are checked and instrumentation calibrated.
14.2.12.3.29.2.3 Description. Following the initial position mode tests of 29A the final adjustment of the position loop gains, flow loop gains, and preliminary valves of the flux loop adjustments will be made on the mid-power line. This will be the most extensive testing of the recirculation control system. The core power distribution will be adjusted by control rods to permit broader range of maneuverability with respect to PCIOMR. In general, the controller dials and gains will be raised to meet the maneuvering performance objectives. Thus, the system will be set to be the slowest that will perform satisfactorily to maximize stability margins and to minimize equipment wear by avoiding controller overactivity.
Because of PCIOMR power maneuvering rate restrictions, the fast flow maneuvering adjustments are performed along a mid-power rod line, and extrapolation made to the expected results along the 100% rod line. The utility has the option to decide to
: a. Perform the faster power changes on the 100% rod line that are greater than what the PCIOMR allow, or
: b. To accept the mid-power load line demonstrations as acceptable proof of maneuverability.
For immediate commercial operation, the flux loop will be set slower and the operator will limit manual mode maneuvers. If PCIOMRs are ever withdrawn, the tested faster auto settings can be inserted onto the controller with only a brief dynamic test, rather than a full startup test.
14.2-112

COLUMBIA GENERATING STATION                           Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 14.2.12.3.29.2.4 Criteria.
Level 1 The transient response of any recirculation system related variable to any test input must not diverge.
Level 2
: a. The decay ratio of the flow loop response to any test inputs shall be <0.25,
: b. The flow loops provide equal flows in the two loops during steady-state operation. Flow loop gains should be set to correct a flow imbalance in less than 25 sec,
: c. The delay time for flow demand step (5%) shall be 0.4 sec or less,
: d. The response time for flow demand step (5%) shall be 1.1 sec or less,
: e. The maximum allowable flow over shoot for step demand of 5% of rated shall be 6% of the demand step, and
: f. The flow demand step settling time shall be 6 sec.
Level 3
: a. Incremental gain from function generator for valve position demand input to sensed drive flow shall not vary by more than 2 to 1 over the entire flow range, and
: b. Flow loop upper limit should be checked for proper setting.
Flux Loop Criteria Level 1 The flux loop response to test inputs shall not diverge.
Level 2
: a. Flux over shoot to a flux demand step shall not exceed 2% of rated for a step demand of 20% of rated, 14.2-113

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998
: b. The delay time for flux response to a flux demand step shall be 0.8 sec,
: c. The response time for flux demand stop shall be 2.5 sec, and
: d. The flux setting time shall be 15 sec for a flux demand step 20% of rated.
Scram Avoidance and General Criteria Level 1 Not applicable.
Level 2 For any one of the above loops test maneuvers, the trip avoidance margins must be at least the following:
: a. For APRM 7.5%, and
: b. For simulated heat flux 5.0%.
Flux Estimator Test Criteria Level 1 Not applicable.
Level 2
: a. Switching between estimated and sensed flux should not exceed 5 times/5 minutes at steady state, and
: b. During flux step transient there should be no switching to sensed flux or if switching does occur, it should switch back to estimated flux within 20 sec of the transient.
Flux Control Valve Duty Test Criteria Level 1 Not applicable.
14.2-114

COLUMBIA GENERATING STATION                            Amendment 55 FINAL SAFETY ANALYSIS REPORT                          May 2001 Level 2 The flow control valve duty cycle in any operating mode shall not exceed 0.2% Hz. Flow control valve duty cycle is defined as Integrated valve movement in percent (% Hz) 2x time span in seconds 14.2.12.3.30        Test Number 30 - Recirculation System 14.2.12.3.30.1 30A - One Pump Trip.
14.2.12.3.30.1.1 Purpose. The purposes of this test are to (a) obtain recirculation system performance data during the pump trip, flow coastdown, and pump restart, and (b) verify that the feedwater control system can satisfactorily control water level without a resulting turbine trip/scram.
14.2.12.3.30.1.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.30.1.3 Description. The reactor coolant recirculation system consists of the reactor vessel and two piping loops. Each loop contains a constant speed centrifugal recirculation pump, a flow control valve and two isolation valves located in the drywell, and 10 jet pumps in parallel, situated in the reactor downcomer and discharges through a manifold system to the nozzles of the 10 jet pumps. Here the flow is augmented by suction flow from the downcomer and delivered to the reactor inlet plenum.
A potential threat to plant availability is the high water level turbine trip scram caused by the level upswell that results after an unexpected recirculation one pump trip. The change in core flow and the resultant power decrease causes void formation which the level sensing system senses as a rise in water level. The one-pump trip tests are to prove that the water level will not rise enough to threaten a high level trip of the main turbine or the feedwater pumps.
14.2.12.3.30.1.4 Criteria.
Level 1 The reactor shall not scram during the one-pump trip recovery.
LDCN-01-000                                    14.2-115

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 Level 2 The reactor water level margin to avoid a high level trip shall be 3.0 in. during the one-pump trip.
NOTE: Margin to trip is defined as Margin (high level trip <8 setpoint) - (maximum water level reached ruing test) - (high level alarm <7 setpoint - initial water level) a       The simulated heat flux margin to avoid a scram shall be 5.0% during the one-pump trip and also during the recovery, and
: b.      The APRM margin to avoid a scram shall be 7.5% during the one-pump trip recovery.
14.2.12.3.30.2 30B - Recirculation Trip of Two Pumps.
14.2.12.3.30.2.1 Purpose. The purpose of the test is to record and verify acceptable performance of the recirculation two pump circuit trip system.
14.2.12.3.30.2.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.30.2.3 Description. In case of higher power turbine or generator trips, there is an automatic opening of circuit breakers in the pump power supply. The result is a fast core flow coastdown that helps reduce peak neutron and heat flow in such events. This two-pump trip test verifies that this flow coastdown is satisfactory prior to the high power turbine/generator trip tests and subsequent operation.
14.2.12.3.30.2.4 Criteria.
Level 1 The two-pump-drive flow coastdown transient during the first 6 sec must be bounded by the limiting curves. (See Figure 14.2-6.)
(The limiting curves will be determined based on measurement of the recirculation flow delta P using the elbow flow meters, transmitter time delay, and time constant.)
14.2-116

COLUMBIA GENERATING STATION                        Amendment 53 FINAL SAFETY ANALYSIS REPORT                       November 1998 Level 2 Not applicable.
14.2.12.3.30.3 30C - System Performance.
14.2.12.3.30.3.1 Purpose. The purpose of this test is to record recirculation system parameters during the power test program.
14.2.12.3.30.3.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.30.3.3 Description. Recirculation system parameters will be recorded at several power-flow conditions and in conjunction with single pump trip recoveries and internals vibration testing (if applicable).
14.2.12.3.30.3.4 Criteria.
Level 1 Not applicable.
Level 2
: a.      The core flow shortfall shall not exceed 5% at rated power,*
: b.      The measured core delta P shall not be 70.6 psi above prediction,*
: c.      The calculated jet pump M ration shall not be 0.2 points below prediction,*
: d.      The drive flow shortfall shall not exceed 5% at rated power,*
: e.      The measured recirculation pump efficiency shall not be 78% points below the vendor tested efficiency, and
: f.      The nozzle and riser plugging criteria shall not be exceeded.
The GE Steam Generation System Design Unit will provide predictions for the comparisons for these criteria.
14.2-117

COLUMBIA GENERATING STATION                            Amendment 53 FINAL SAFETY ANALYSIS REPORT                          November 1998 14.2.12.3.30.4 30D - Recirculation Pump Runback.
14.2.12.3.30.4.1 Purpose. The purpose of this test is to verify the adequacy of the recirculation runback to mitigate a scram on the loss of one feedwater pump.
14.2.12.3.30.4.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.30.4.3 Description. While operating at near rated recirculation flow, a loss of a feedwater pump will be simulated. The transient and final condition will be studied to determine the adequacy of the system in preventing a scram during the scheduled loss of a single feedwater pump test (test 23C).
14.2.12.3.30.4.4 Criteria.
Level 1 Not applicable.
Level 2 The recirculation flow control valves shall runback on a trip of the runback circuit.
14.2.12.3.30.5 30E - Recirculation System Cavitation.
14.2.12.3.30.5.1 Purpose. The purpose of this test is to verify that no recirculation system cavitation will occur in the operable region of the power-flow map.
14.2.12.3.30.5.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.30.5.3 Description. Both the jet pumps and the recirculation pumps will cavitate at conditions of high flow and low power where NPSH demands are high and little feedwater subcooling occurs. However, the recirculation flow will automatically run back on sensing a decrease in subcooling (as measured by the difference between the steam and recirculation loop temperature), to lower the reactor power. The maximum recirculation flow is limited by approximate stops which will run back the recirculation flow away from the possible cavitation region. It will be verified that these limits are sufficient to prevent operation where recirculation pump or jet pump cavitation is predicted to occur.
14.2-118

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 The recirculation system flow control valves will cavitate at conditions of high differential pressure and low power (low subcooling). The recirculation flow will automatically run back on sensing a decrease in subcooling (as measured by a low feedwater flow). This limit will be verified to ensure that operation is prevented where flow control valve cavitation may occur.
In both the above cases, flow runback is caused by a shift in the power supply to the recirculation pump motors from normal power to the LFMGs.
14.2.12.3.30.5.4 Criteria.
Level 1 Not applicable.
Level 2 Runback logic shall have settings adequate to prevent operation in areas of potential cavitation.
14.2.12.3.31        Test Number 31 - Loss of Turbine-Generator and Offsite Power 14.2.12.3.31.1 Purpose. This test determines electrical equipment and reactor system transient performance during a loss of auxiliary power.
14.2.12.3.31.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate. The plant electrical system will be aligned in the normal mode for the operating condition at which the test is performed.
14.2.12.3.31.3 Description. The loss of auxiliary power test will be performed at 20% to 30% of rated power. The proper response of reactor plant equipment, automatic switching equipment, and the proper sequencing of the diesel generator load will be verified.
Appropriate reactor parameters will be recorded during the resultant transient.
14.2.12.3.31.4 Criteria.
Level 1
: a.      Reactor protection system actions shall prevent violation of fuel thermal limits.
: b.      All safety systems, such as the RPS, the diesel generators, and HPCS must function properly without manual assistance. The HPCS and/or RCIC system action, if necessary, shall keep the reactor water level above the initiation level 14.2-119

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998 of the LPCS, LPCI, automatic depressurization systems, and MSIV closure.
Diesel generators shall start automatically and when they reach rated frequency and voltage the diesel breakers will close and restore power to the engineered safety features (ESF) buses.
Level 2
: a. Proper instrument display to the reactor operator shall be demonstrated, including power monitors, pressure, water level, control rod position, suppression pool temperature, and reactor cooling system status. Displays shall not be dependent on specially installed instrumentation, and
: b. If SRVs open, the temperature measured by thermocouples on the discharge side of the SRVs must return to within 10&deg;F of the temperature recorded before the valve was opened. If pressure sensors are available, they shall return to their initial state on valve closure.
14.2.12.3.32        Not Applicable 14.2.12.3.33        Test Number 33 - Piping Vibration 14.2.12.3.33.1 Purpose. The purpose of this test is to verify that the design stress levels due to piping vibration are not exceeded and satisfy the inspection requirements for condensate and feedwater systems according to Regulatory Guide 1.68.1.
14.2.12.3.33.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been installed and calibrated.
14.2.12.3.33.3 Description. This test is an extension of test 17 and has been procedurally combined with the system expansion test. During reactor operation, it is desirable to show that destructive level piping vibrations do not occur during steady-state conditions and during planned transients. Acceptable vibration levels are verified by measurement (using the same sensors used in test 17) and by visual observation during system walkdowns for selected piping systems outside containment. See Section 14.2.12.3.17.2 for systems selected and selection criteria.
14.2.12.3.33.4 Criteria.
Level 1 The measured vibration amplitude (peak-to-peak) of the systems monitored shall not exceed the maximum allowable displacements.
14.2-120

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998 Level 2 The measured amplitude (peak-to-peak) of vibration shall not exceed the expected values.
Visual Inspection Acceptance Criteria The vibration levels experienced will be evaluated as acceptable if they are too small to be detected by the naked eye with consideration given to the following:
: a.      Proximity to sensitive equipment (pumps, valves, motor control centers, control panels, etc.),
: b.      Branch connection behavior, and
: c.      Performance of nearby component supports.
If an acceptable assessment of the observed deflections cannot be performed and corrective measures are not available, the inspector will then obtain the magnitude and frequency of the vibration using a portable vibration instrument. The information will then be evaluated by the piping design engineer to verify acceptance. Unacceptable vibration levels will be treated as a Level 1 violation.
14.2.12.3.34        Test Number 34 - Reactor Pressure Vessel Internals Vibration 14.2.12.3.34.1 Purpose. The purpose of this test is to provide information needed to confirm the similarity between the reactor internals design and the prototype with respect to flow-induced vibration. Testing is in response to Regulatory Guide 1.20 for a vibration measurement program for nonprototype, Category IV reactor internals, and the GE vibration test specification 22A6601, Revision 0.
14.2.12.3.34.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.34.3 Description. During operation, the reactor structure may be forced into many modes of vibrations. Analytical work indicates that unacceptable level vibrations will not occur.
Detailed descriptions of sensor locations are given in GE Test Specification 22A6601, Revision 0.
14.2-121

COLUMBIA GENERATING STATION                          Amendment 53 FINAL SAFETY ANALYSIS REPORT                         November 1998 Sensors used for the measurements are resistance wire strain gauges and accelerometers with double integrating output signal conditioning. Sensors will be installed in a manner to sense the most probable mode of vibration as indicated by analysis.
The test program consists of at power tests performed with the system at normal operating pressure and temperature.
During the vibration test the vibration engineer will monitor and record vibrating amplitudes and frequencies obtained from the sensors mounted on the various components. The measured amplitudes and frequencies are then compared to the acceptance criteria to ensure that all measured vibration amplitudes are within acceptable levels.
14.2.12.3.34.4 Criteria.
Level 1 The peak stress intensity may exceed 10,000 psi (single amplitude) when the component deformed in a manner corresponding to one of its normal or natural modes, but the fatigue usage factor must not exceed 1.0.
Level 2 The peak stress intensity shall not exceed 10,000 psi (single amplitude) when the component is deformed in a manner corresponding to one of its normal or natural modes. This is the low stress limit which is suitable for sustained vibration in the reactor environment for the design life of the reactor components.
14.2.12.3.35        Test Number 35 - Recirculation System Flow Calibration 14.2.12.3.35.1 Purpose. The purpose of this test is to perform complete calibration of the installed recirculation system flow instrumentation.
14.2.12.3.35.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.35.3 Description. During the testing program at operating conditions, which allow the recirculation system to be operated at rated flow at rated power, the jet pump flow instrumentation will be adjusted to provide correct flow indication based on the jet pump flow.
After the relationship between drive flow and core flow is established, the flow biased APRM/RBM system will be adjusted to match this relationship.
14.2-122

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998 14.2.12.3.35.4 Criteria.
Level 1 Not applicable.
Level 2 Jet pump flow instrumentation shall be adjusted such that the jet pump total flow recorder will provide a correct core flow indication at rated conditions.
The APRM/RBM flow-bias instrumentation shall be adjusted to function properly at rated conditions.
The flow control system shall be adjusted to limit maximum core flow to 102.5% of rated by limiting the flow control valve opening position.
14.2.12.3.36       Test Number 70 - Reactor Water Cleanup System 14.2.12.3.36.1 Purpose. The purpose of this test is to demonstrate specific aspects of the mechanical operability of the RWCU system. (This test, performed at rated reactor pressure and temperature, is actually the completion of the preoperational testing that could not be done without nuclear heating.)
14.2.12.3.36.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.36.3 Description. With the reactor at rated temperature and pressure, process variables will be recorded during steady-state operation in three modes as defined by the system process diagram: hot shutdown with loss of RPV recirculation pumps, normal, and blowdown. A comparison of the bottom head flow indicator and the RWCU inlet flow indicator will be made. The RWCU system sample station shall be tested at hot process conditions.
14.2.12.3.36.4 Criteria.
Level 1 Not applicable.
14.2-123

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998 Level 2 The temperature at the tube side outlet of the nonregenerative heat exchangers shall not exceed 130&deg;F (54&deg;C) in the blowdown mode and shall not exceed 120&deg;F in the normal mode.
The pump available NPSH will be 13 ft or greater during the hot shutdown with loss of RPV recirculation pumps mode defined in the process diagrams.
The cooling water supplied to the nonregenerative heat exchangers shall be less than 6% above the flow corresponding to the heat exchanger capacity (as determined from the process diagram) and the existing temperature differential across the heat exchangers. The outlet temperature shall not exceed 180&deg;F.
Recalibrate bottom head flow indicator (R610) against RWCU flow indicator (R609) if the deviation is greater than 25 gpm.
Pump vibration shall be less than or equal to 2 mils peak-to-peak (in any direction) as measured on the bearing housing and 2 mils peak-to-peak shaft vibration as measured on the coupling end.
14.2.12.3.37       Test Number 71 - Residual Heat Removal System 14.2.12.3.37.1 Purpose. The purpose of this test is to demonstrate the ability of the RHR system to remove heat from the reactor system so that the refueling and nuclear system servicing can be performed.
14.2.12.3.37.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.37.3 Description. During the first suitable reactor cooldown, the shutdown cooling mode of the RHR system will be demonstrated. Unfortunately, the decay heat load is insignificant during the startup test period. Use of the mode with low core exposure could result in exceeding the 100&deg;F/hr cooldown rate of the vessel if both RHR heat exchangers are used simultaneously. Late in the test program after accumulating significant core exposure, this demonstration would more adequately demonstrate the heat exchanger capacity.
14.2.12.3.37.4 Criteria.
Level 1 Not applicable.
14.2-124

COLUMBIA GENERATING STATION                            Amendment 53 FINAL SAFETY ANALYSIS REPORT                           November 1998 Level 2 The RHR system shall be capable of operating in the suppression pool cooling and shutdown cooling modes (with each heat exchanger) at the flow rates and temperature differentials determined by the flow rates and temperature differentials indicated on the process diagrams.
14.2.12.3.38       Test Number 72 - Drywell Atmosphere Cooling System 14.2.12.3.38.1 Purpose. The purpose of this test is to verify the ability of the drywell atmosphere cooling system to maintain design conditions in the drywell during operating conditions and post scram conditions.
14.2.12.3.38.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.38.3 Description. During heatup and power operation, data will be taken to ascertain that the drywell atmospheric conditions are within design limits.
14.2.12.3.38.4 Criteria.
Level 1 Not applicable.
Level 2 The drywell cooling system shall maintain drywell air temperatures at or below the design values as specified for the NSSS equipment.
14.2.12.3.39       Test Number 73 - Cooling Water Systems 14.2.12.3.39.1 Purpose. The purpose of the test is to verify that the heat removal performance of the SW system, the reactor building RCC system, and the plant service water (TSW) system is adequate.
14.2.12.3.39.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.39.3 Description. The SW, the RCC, and the TSW systems heat exchanger heat transport capabilities will be verified. Verification will be conducted in the following manner.
The system water flow rate through each heat exchanger will be measured. The system water 14.2-125

COLUMBIA GENERATING STATION                         Amendment 53 FINAL SAFETY ANALYSIS REPORT                        November 1998 temperature drop across each heat exchanger will also be measured. From these acquired water flow rates and temperature drop data, the heat transport rates will be calculated. Where available, the calculated heat transport data will be compared directly with design calculations to determine acceptability. For those systems in which no design calculations of the heat transport rate have been directly calculated, the heat removal performance of the particular heat exchanger will be considered acceptable if the components serviced by the cooling system exhibit proper operation. If proper performance is not experienced, adjustments in the heat transport capability (i.e., increased flow to the heat exchanger or increased flow to a particular load) would be made. In addition to the heat exchanger heat transport rate verification, the actual SW pump head will be determined for all three SW pumps. This actual SW pump head will be compared to the design requirements for acceptability.
14.2.12.3.39.4 Criteria.
Level 1 Not applicable.
Level 2 The system heat transport parameters either meet the requirements of the design specifications, or provide adequate cooling to the components serviced such that they operate satisfactorily.
14.2.12.3.40        Test Number 74 - Offgas System 14.2.12.3.40.1 Purpose. The purposes of this test are to verify the proper operation of the offgas system over its expected operating parameters and to determine the performance of the activated carbon adsorbers.
14.2.12.3.40.2 Prerequisites. The preoperational tests have been completed, reviewed by POC, and the Plant Manager has approved the test procedures and initiation of testing.
Instrumentation has been checked or calibrated as appropriate.
14.2.12.3.40.3 Description. The pressure, temperature, relative humidity, system flow, and percentage of radiolytic hydrogen in the offgas are periodically monitored during startup and at steady-state conditions. Prior to initial steam flow to the main condenser, charcoal bed hold-up times will be measure experimentally using a pulsed Krypton-85 gas injection technique. The charcoal bed dynamic adsorption coefficient will then be determined by established analytical methods. The performance of the catalytic recombiner will be compared the catalytic recombiner guaranteed performance curve.
14.2-126

COLUMBIA GENERATING STATION                          Amendment 54 FINAL SAFETY ANALYSIS REPORT                        April 2000 14.2.12.3.40.4 Criteria.
Level 1 The release of radioactive gaseous and particulate effluents must not exceed the limits specified in the Technical Specifications. There shall be no loss of flow of dilution steam to the noncondensing stage when the steam jet air ejectors are pumping.
Level 2 The system flow, pressure, temperature, and relative humidity shall comply with design specifications. The catalytic recombiner, the hydrogen analyzer, the activated carbon bed, and the filters shall be performing their required function.
LDCN-99-000                                  14.2-127

COLUMBIA GENERATING STATION             Amendment 53 FINAL SAFETY ANALYSIS REPORT            November 1998 Table 14.2-1 Preoperational Tests Section Reference                                 Title 14.2.12.1.1 Reactor Feedwater System 14.2.12.1.2 Condensate System 14.2.12.1.3 Fire Protection System 14.2.12.1.4 Reactor Water Cleanup System 14.2.12.1.5 Standby Liquid Control System 14.2.12.1.6 Nuclear Boiler System 14.2.12.1.7 Residual Heat Removal System 14.2.12.1.8 Reactor Core Isolation Cooling 14.2.12.1.9 Reactor Recirculation System and Control 14.2.12.1.10 Reactor Manual Control System 14.2.12.1.11 Control Rod Drive Hydraulic System 14.2.12.1.12 Fuel Handling and Vessel Servicing Equipment 14.2.12.1.13 Low Pressure Core Spray System 14.2.12.1.14 High Pressure Core Spray 14.2.12.1.15 Fuel Pool Cooling and Cleanup System 14.2.12.1.16 Leak Detection System 14.2.12.1.17 Liquid and Solid Radwaste System 14.2.12.1.18 Reactor Protection System 14.2.12.1.19 Neutron Monitoring System 14.2.12.1.20 Traversing In-Core Probe System 14.2.12.1.21 Rod Worth Minimizer System 14.2.12.1.22 Process Radiation Monitoring System 14.2.12.1.23 Area Radiation Monitoring System 14.2-129

COLUMBIA GENERATING STATION                        Amendment 53 FINAL SAFETY ANALYSIS REPORT                      November 1998 Table 14.2-1 Preoperational Tests (Continued)
Section Reference                                  Title 14.2.12.1.24 Process Computer Interface System 14.2.12.1.25 Rod Sequence Control System 14.2.12.1.26 Remote Shutdown 14.2.12.1.27 Offgas System 14.2.12.1.28 Environs Radiation Monitoring System 14.2.12.1.29 Main Steam System 14.2.12.1.30 Radwaste Building Heating, Ventilation, and Air Conditioning System 14.2.12.1.31 Closed Cooling Water System 14.2.12.1.32 Primary Containment Atmospheric Control System 14.2.12.1.33 Primary Containment Cooling System 14.2.12.1.34 Primary Containment Instrument Air System 14.2.12.1.35 Primary Containment Atmospheric Monitoring System 14.2.12.1.36 Standby Gas Treatment System 14.2.12.1.37 Loss of Power and Safety Testing 14.2.12.1.38 Instrument Power System 14.2.12.1.39 Emergency Lighting 14.2.12.1.40 Standby Alternating Current Power System 14.2.12.1.41 250-V Direct Current Distribution System 14.2.12.1.42 125-V Direct Current Distribution System 14.2.12.1.43 24-V Direct Current Distribution System 14.2.12.1.44 Plant Service Water System 14.2.12.1.45 Standby Service Water System 14.2.12.1.46 Plant Communication System 14.2-130

COLUMBIA GENERATING STATION                        Amendment 53 FINAL SAFETY ANALYSIS REPORT                       November 1998 Table 14.2-1 Preoperational Tests (Continued)
Section Reference                                  Title 14.2.12.1.47 Reactor Building Emergency Cooling System 14.2.12.1.48 Control Cable and Critical Switchgear Rooms Heating, Ventilation, and Air Conditioning System 14.2.12.1.49 Standby Service Water Pump House Heating and Ventilating System 14.2.12.1.50 Reactor Building Crane 14.2.12.1.51 Primary Containment Integrated Leak Rate Test 14.2.12.1.52 Secondary Containment Integrated Leak Rate Test 14.2.12.1.53 Diesel Generator Building Heating and Ventilating System 14.2-131

Table 14.2-2 Major Plant Transients Test Condition Approximate Power      20-25      60-75         95-100
(% rated)
Approximate Core Flow    37         100           100 Test                     Title                           (% rated)
COLUMBIA GENERATING STATION 23C     Feedwater pump trip                                                                            X 23B     Loss of feedwater heating                                                                      X 25      MSIVs (all valves, full isolation)                                                             X 14.2-132 FINAL SAFETY ANALYSIS REPORT 27      T-G stop valve fast close                                                        X 27      T-G control valve fast close                                         X                         X 28      Shutdown from outside control room                                   X 30      Recirculation pump trips                                                         X             X 31      Loss of generator and offsite power                                  X Test condition                                                      1, 2         3             6 Amendment 53 November 1998

Table 14.2-3 Stability Tests Test Condition Approximate Power      20   40   60-75   60-75     95-100   40-50
(% rated)
Approximate Core      37   50   100      55        100      NC Test                    Title                Flow (% rated)
COLUMBIA GENERATING STATION 21    Core power - void mode response                                                X                  X 22    Pressure regulator setpoint                                X    X      X       X         X        X changes 14.2-133 22    Pressure regulator backup                                  X    X      X       X         X        X FINAL SAFETY ANALYSIS REPORT regulator 23A   Feedwater system: water level                              X    X      X       X         X        X setpoint change 23B   Feedwater system: heater loss                                                            X 24    Turbine valve surveillance                                                     Xa        Xb 29    Recirculation flow control system                          X    X      X       X         X        X Test condition                                             1    2      3       5         6        4 Amendment 53 a
45-65% Power November 1998 b
75-90% Power

Table 14.2-4 Power Ascension Test Program Test Conditionsa Cold Test or Open      Heat Test                  Name             RPV         Up      1       2       3         4        5    6    Warranty COLUMBIA GENERATING STATION 1          Chemical and radiochemical       X          X       X       X       X                       X 2          Radiation measurements           X          X       X       X       X                       X 3          Fuel loading                     X 14.2-134 4          Full core shutdown margin        X FINAL SAFETY ANALYSIS REPORT 5          Control rod drive                X          X               Xb      Xb                      Xb 6          SRM performance and control      X          X       X       X                          X    X rod sequence 7          Not applicable 8          Not applicable 9          See 16B 10         IRM performance                  X          X       X 11         LPRM calibration                            X       X               X                       X               Amendment 53 November 1998

Table 14.2-4 Power Ascension Test Program (Continued)
Test Conditionsa Cold Test or Open     Heat Test                Name                 RPV        Up      1       2       3          4        5    6   Warranty COLUMBIA GENERATING STATION 12      APRM calibration                             X       X       X      X                    X    X      X 13      Process computer                   X         X       Xc 14      RCIC                                         X       X 14.2-135 15      Not applicable FINAL SAFETY ANALYSIS REPORT 16A     Selected process temperatures                X       X       X      X           X             X 16B     Water level reference leg                    X       X       X      X           X        X    X temperature measurement 17      System expansion and piping        X         X       X       X      X                         X vibration 18      Core power distribution                                             X                         X 19      Core performance                                     X       X      X           X        X    X      X Amendment 53 20      Steam production                                                                                     X 21      Core power void mode response                                                   X        X November 1998

Table 14.2-4 Power Ascension Test Program (Continued)
Test Conditionsa Cold Test or Open     Heat Test                Name                 RPV        Up      1        2      3          4        5       6     Warranty COLUMBIA GENERATING STATION 22      Pressure regulator: setpoint                       X,BP      X,BP   X,NO      X,BP     X,BP,    X,M, changes                                                             BP,M               M        BP Backup regulator                                   X,BP      X,BP   X,NO      X,BP     X,NO,    X,M, BP,M               BP,M     BP 14.2-136 23      Feedwater system FINAL SAFETY ANALYSIS REPORT C feedwater pump trip                                                                            Md A water level setpoint change                        X        X     X,M         X        X      X,M B heater loss                                                                                    Xe D maximum runout capability                  Xf      Xf                         X        X 24      Turbine valve surveillance                                                    X,g,h     X,i,j SP        SP 25      MSIVs:   each valve                          X     X,c S Amendment 53 one valve                                                           X,g,i,j X,k SP November 1998

Table 14.2-4 Power Ascension Test Program (Continued)
Test Conditionsa Cold Test or Open     Heat Test                    Name             RPV        Up      1        2      3          4        5     6     Warranty COLUMBIA GENERATING STATION full isolation                                                                X,b X,l SD 26      Relief valves:
14.2-137 Flow demonstration                               Xl,m FINAL SAFETY ANALYSIS REPORT Operational                               X      Xm 27      Turbine stop valve                                                  Xb,l Stop                                                             SD Generator load                                            X,BP                             Xb,l Rejection                                                                                  X,n SD 28      Shutdown from outside control                        X                                        Xo room Amendment 53 November 1998

Table 14.2-4 Power Ascension Test Program (Continued)
Test Conditionsa Cold Test or Open     Heat Test                Name                 RPV        Up      1        2       3          4        5      6     Warranty COLUMBIA GENERATING STATION 29      Recirculation flow control         L                 L       M,m     X,m        Lg     M,g Xg   L,g system                                                       X,m     L,m                        Xg Lm      M,m Am 14.2-138 30      Recirculation system:
FINAL SAFETY ANALYSIS REPORT Trip one pump                                                     Xl,n                       Xl,n Trip two pumps                                                    Xl,n System performance                                         X      Xl,m       Xg              Xl Runback                                                           Xd Noncavitation verification                                         X 31      Loss of T-G and offsite power                                X,b,l SD Amendment 53 32      Not applicable 33      Not applicable November 1998

Table 14.2-4 Power Ascension Test Program (Continued)
Test Conditionsa Cold Test or Open      Heat Test                  Name                   RPV         Up       1        2        3        4        5    6    Warranty COLUMBIA GENERATING STATION 34          RPV Internals                                                     Xm       Xm                Xg    Xg 36-69       Not applicable 70          Reactor water cleanup system                      X 14.2-139 71          Residual heat removal system                                                                       X FINAL SAFETY ANALYSIS REPORT 72          Drywell atmosphere cooling                        X                X        X                      X 73          Cooling water system                              X                                                X 74          Offgas system                          X          X       X                 X                      X a
See Figure 14.2-1 for test conditions region map.
b Perform test 5, timing of four slowest control rods in conjunction with these scrams.
c Between test conditions 1 and 3.
d Demonstrate recirculation system runback feature.
e 80%-90% power.                                                                                                             Amendment 53 November 1998 f
At either heatup or test condition 1.

Table 14.2-4 Power Ascension Test Program (Continued) g Between or at test conditions 5 and 6.
h Between 45% and 65% power on 100% load line.
i Future maximum power test point.
j Determine maximum power without scram.
COLUMBIA GENERATING STATION k
Between 40% and 55% power on the 100% load line.
l Do test 17 in conjunction with this test.
m Between test conditions 2 and 3.
14.2-140 n
FINAL SAFETY ANALYSIS REPORT Perform test 34 in conjunction with this test.
o After one of the scram transients from test condition, during the reactor cooldown, the last part of the shutdown from outside the control room test will be completed by demonstrating the operation of the shutdown cooling mode of RHR from the remote shutdown panel.
LEGEND L = Local position command mode operation, POS M = Flux command mode operation, FLX X = Combined flow command mode operation, FLO A = Automatic load following mode operation, ALF Amendment 53 SP = Scram possibility SD = Scram definite BP = Bypass valve response November 1998

Amendment 53 November 1998 130 120       A. Natural Circulation B. Low Recirculation Pump Speed Valve Minimum Position                                         (Truncate @ 100%
C. Low Recirculation Pump Speed Valve Maximum Position                                        Core Flow and Power) 110       D. Rated Recirculation Pump Speed Valve Minimum Position E. Analytical Lower Limit of Master Power Flow Control F. Analytical Upper Limit of Master Power Flow Control                                            F 100                                                                                                                        No. 6 105% Rod Line 90                                                                                                                       Rated 100% Rod Line                                                               Core Flow Line 80                                              No. 5                                   75% Rod Line Percent Power E                                                               No. 3 70 60                                        C D
B 50                            A No. 4 40                                                                                                          50% Rod Line No. 2 30                                                                                      Minimum Flow Control Line for Transfer to 100% SPD 20                                                                   Cavitation Region 10                                              Recommended Startup Path No. 1 0
0      10       20        30          40           50         60         70         80        90       100           110 Percent Core Flow Condition (TC) 1        Before main generator synchronization and recirc pumps operating on low frequency power supply from approximately 5 to 20 percent thermal power 2        Between 50% and 75% control rod lines, at or below the analytical lower limit of master flow control mode 3        From 50% to 75% control rod lines and core flow between 80% and maximum allowable 4        Natural circulation and within 5% of the intersection with 100% rod line 5        Mid-power range within 5% of 100% control rod line and 0 to +5% core flow of the minimum flow line, for master flow control in manual mode, and for automatic power control in auto mode 6        Within 0 to -5% of rated thermal power, and within 5% of rated core flow rate Test Condition Region Definition Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.93           Rev.           Figure   14.2-1 Form No. 960690

Amendment 53 November 1998 Licensing and          Technology                           Power Assurance              Director                        Generation Director                                               Director Quality            Engineering Assurance              Manager                Plant                   Other Plants Manager                                    Manager Plant QA/QC                                   Assistant Manager                                 Plant Manager
        *Test Group             Plant        Technical      Operations           Maintenance              HP/Chem Manager           Administrative   Manager         Manager               Manager                Manager Manager Test Group Supervisor Test Group Supervisor Test Group Supervisor Matrix Management QA Audit Function
* Reports Administratively to Test and Startup Programs Manager Test and Startup Relation to Other Energy Columbia Generating Station                              Northwest Departments Final Safety Analysis Report Draw. No. 960222.77           Rev.          Figure 14.2-2 Form No. 960690

Amendment 53 November 1998 Plant Manager Assistant Plant Manager Plant QA/QC Industrial Safety Manager AE, NSSS and Project Support Maintenance         Training            Operations                         Administration      Technical         HP/Chemistry Manager           Manager               Manager                              Manager          Manager             Manager Test Group                             Test Group                          Test Group Manager                                Manager                              Manager Test Group                               Test Group                        Test Group Supervisor                                Supervisor                        Supervisor Plan/Sched Test Engineers                            Test Engineers                    Test Engineers Engineers Test Group                               Test Group                        Test Group Supervisor                                Supervisor                        Supervisor Test Engineers                            Test Engineers                    Test Engineers Engineering Support S/U                                   Test Group                        Test Group Services                                 Supervisor                        Supervisor Systems Completion               S/U Support                                   Test Engineers                    Test Engineers Coordinator                 Group S/U Support Hanger Engineers Coordinator S/U Support Craft CGS Startup Organization Columbia Generating Station Final Safety Analysis Report Draw. No. 960222.78         Rev.        Figure  14.2-3 Form No. 960690

LEGEND: 1 PREPARE PREOP TEST PROCEDURES                                                                                                                  Amendment 53 2 REVIEW                                                                                                                                       November 1998 3 APPROVE                       NOTE: TIME SCALE LISTED ACROSS THE 4 TEST ACTIVITY                       BOTTOM OF PAGE IS IN MONTHS                                                                                                   FUEL LOAD 1              2      3          4 CONDENSATE 1        2   3   4 PLANT SERVICE WATER 1           2  3    4 STANDBY SERVICE WATER 1             2           3           4                                 4 FEEDWATER 1              2        3    4 PRIMARY CONTAINMENT ATMOSPHERIC CONTROL 1            2       3        4 PRIMARY CONTAINMENT COOLING 1              2     3      4 PRIMARY CONTAINMENT INSTRUMENT AIR 1                    2      3      4 PRIMARY CONTAINMENT ATMOSPHERIC MONITORING 1              2        3 4 125V DC DISTRIBUTION 1                        2           3        4 LOSS OF POWER AND SAFETY TEST 1               2       3 4 250V DC DISTRIBUTION 1              2      3   4 INSTRUMENT POWER 1              2       3    4 EMERGENCY LIGHTING 1            2      3 4 24V DC DISTRIBUTION 1                     2       3    4 STANDBY AC POWER 1                 2       3            4              4 HIGH PRESSURE CORE 1              2      3      4 LOW PRESSURE CORE SPRAY 1               2       3     4 STANDBY GAS TREATMENT 1             2         3 4                                 4 RESIDUAL HEAT REMOVAL 1              2         3      4 FUEL HANDLING & VESSEL SERVICING EQUIPMENT 1        2      3       4 FUEL POOL COOLING 1            2      3 4 SECONDARY CONTAINMENT ILRT 1                 2       3 4 PRIMARY CONTAINMENT ILRT 1              2      3      4 NUCLEAR BOILER 1               2       3           4 REACTOR WATER CLEANUP 1                 2         3       4 CONTROL ROD DRIVE MANUAL CONTROL 1                    2        3      4 CONTROL ROD DRIVE HYDRAULIC 1            2     3 4 ROD WORTH MINIMIZER 1             2      3 4 ROD SEQUENCE CONTROL 1            2       3 4 TRAVERSING INCORE PROBE 1                   2        3      4                    4 REACTOR RECIRCULATION 1             2       3      4 REACTOR CORE ISOLATION COOLING 1          2      3                                              4 PROCESS COMPUTER 1           2       3      4 STANDBY LIQUID CONTROL 1             2      3     4 LEAK DETECTION 1                     2     3       4 NEUTRON MONITORING 1          2       3       4 CLOSED COOLING WATER 1                    2       3     4                   4 REACTOR PROTECTION 1              2      3       4 PROCESS RADIATION MONITORING 1             2       3    4 AREA RADIATION MONITORING 1             2       3    4 ENVIRONS MONITORING 1          2        3 4 REACTOR BUILDING CRANE 1            2      3   4 REACTOR BUILDING EMERGENCY COOLING 1       2      3     4 CONTROL, CABLE, & CRITICAL SWCHGR ROOMS HVAC 1         2   3 4 STANDBY SERVICE WATER PUMPHOUSE H&V 1              2      3      4 DIESEL GENERATOR BUILDING H&V V 1                     2       3    4 SECURITY 1                    2       3           4 OFFGAS 1               2      3     4 MAIN STEAM 1               2       3          4 PLANT COMMUNICATION 1                    2        3     4 REMOTE SHUTDOWN 1                    2      3            4 LIQUID AND SOLID RADWASTE 1             2      3           4 RADWASTE BUILDING HVAC 1                    2      3                  4 FIRE PROTECTION Preoperational Test Schedule Columbia Generating Station Final Safety Analysis Report Draw. No.      960690.83                          Rev.                      Figure    14.2-4 Form No. 960690

Amendment 53 November 1998 450 400 350 300 Time Delay, Sec Unsafe 250 200 150 100 Safe up to 50        Limited Power 0
0   10      20       30    40       50      60            70     80   90         100 Percent Rated Power 100 90 80 70 Percent RCIC Design Flow Safe 60 50 40 30 Unsafe 20 10 0
0   10      20       30    40       50      60            70     80   90         100 Percent Rated Power RCIC Acceptance Criteria Curves for Capacity Columbia Generating Station                         and Actuation Time Final Safety Analysis Report Draw. No. 960690.82        Rev. Figure   14.2-5 Form No. 960690

Amendment 53 November 1998 100 90 80 Percent Drive Flow 70 60 50 40 30 0   1   2      Time    3     After    4    Start  5       6 in Seconds                 of TCV/TSV Movement Maximum Acceptable Drive Flow Response Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.81      Rev. Figure   14.2-6 Form No. 960690

COLUMBIA GENERATING STATION                                      Amendment 60 FINAL SAFETY ANALYSIS REPORT                                     December 2009 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS Section                                                                                           Page 15.0 GENERAL................................................................................. 15.0-1 15.0.1 ANALYTICAL OBJECTIVE........................................................ 15.0-3 15.0.2 ANALYTICAL CATEGORIES ..................................................... 15.0-3 15.0.2.1 Single Loop Operation (SLO) ..................................................... 15.0-4 15.0.3 EVENT EVALUATION.............................................................. 15.0-5 15.0.3.1 Identification of Causes and Frequency Classification ........................ 15.0-5 15.0.3.1.1 Unacceptable Results for Incidents of Moderate Frequency
[Anticipated (Expected) Operational Transients] ............................ 15.0-6 15.0.3.1.2 Unacceptable Results for Infrequent Incidents
[Abnormal (Unexpected) Operational Transients]........................... 15.0-6 15.0.3.1.3 Unacceptable Results for Limiting Faults [Design-Basis (Postulated) Accidents] ........................................................... 15.0-6 15.0.3.2 Sequence of Events and Systems Operation..................................... 15.0-7 15.0.3.2.1 Single Failures or Operator Errors ............................................. 15.0-8 15.0.3.2.1.1 General ........................................................................... 15.0-8 15.0.3.2.1.2 Initiating Event Analysis....................................................... 15.0-8 15.0.3.2.1.3 Single Active Component Failure or Single Operator Error Analysis ................................................................... 15.0-9 15.0.3.3 Core and System Performance .................................................... 15.0-9 15.0.3.3.1 Mathematical Model .............................................................. 15.0-10 15.0.3.3.2 Input Parameters and Initial Conditions for Analyzed Events ............. 15.0-11 15.0.3.3.3 Consideration of Uncertainties .................................................. 15.0-11 15.0.3.3.3.1 Core Flow Uncertainty Analysis ............................................. 15.0-12 15.0.3.3.4 Results............................................................................... 15.0-13 15.0.3.4 Barrier Performance................................................................. 15.0-14 15.0.3.5 Radiological Consequences ........................................................ 15.0-14 15.

==0.4 REFERENCES==
 ......................................................................... 15.0-14 15.1 DECREASE IN REACTOR COOLANT TEMPERATURE ..................... 15.1-1 15.1.1 LOSS OF FEEDWATER HEATING .............................................. 15.1-1 15.1.1.1 Identification of Causes and Frequency Classification ........................ 15.1-1 15.1.1.1.1 Identification of Causes .......................................................... 15.1-1 15.1.1.1.2 Frequency Classification ......................................................... 15.1-1 15.1.1.2 Sequence of Events and Systems Operation..................................... 15.1-1 15.1.1.2.1 The Effect of Single Failures and Operator Errors.......................... 15.1-2 LDCN-08-035                                       15-i

COLUMBIA GENERATING STATION                                      Amendment 61 FINAL SAFETY ANALYSIS REPORT                                     December 2011 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.1.1.3 Core and System Performance .................................................... 15.1-2 15.1.1.3.1 Mathematical Model .............................................................. 15.1-2 15.1.1.3.2 Input Parameters and Initial Conditions ....................................... 15.1-2 15.1.1.3.3 Results ............................................................................... 15.1-3 15.1.1.3.4 Considerations of Uncertainties ................................................. 15.1-3 15.1.1.4 Barrier Performance ................................................................. 15.1-3 15.1.1.5 Radiological Consequences ........................................................ 15.1-3 15.1.2 FEEDWATER CONTROLLER FAILURE - MAXIMUM DEMAND ...... 15.1-3 15.1.2.1 Identification of Causes and Frequency Classification ........................ 15.1-3 15.1.2.1.1 Identification of Causes .......................................................... 15.1-3 15.1.2.1.2 Frequency Classification ......................................................... 15.1-3 15.1.2.2 Sequence of Events and Systems Operation ..................................... 15.1-4 15.1.2.2.1 Sequence of Events and Systems Operation - Single Loop Operation ... 15.1-4 15.1.2.2.2 The Effect of Single Failures and Operator Errors .......................... 15.1-5 15.1.2.3 Core and System Performance .................................................... 15.1-5 15.1.2.3.1 Mathematical Model .............................................................. 15.1-5 15.1.2.3.2 Input Parameters and Initial Conditions ....................................... 15.1-6 15.1.2.3.3 Results ............................................................................... 15.1-6 15.1.2.3.4 Consideration of Uncertainties .................................................. 15.1-7 15.1.2.4 Barrier Performance ................................................................. 15.1-7 15.1.2.5 Radiological Consequences ........................................................ 15.1-7 15.1.3 PRESSURE REGULATOR FAILURE - OPEN ................................. 15.1-7 15.1.3.1 Identification of Causes and Frequency Classification ........................ 15.1-7 15.1.3.1.1 Identification of Causes .......................................................... 15.1-7 15.1.3.1.2 Frequency Classification ......................................................... 15.1-7 15.1.3.2 Sequence of Events and Systems Operation ..................................... 15.1-8 15.1.3.2.1 Sequence of Events ............................................................... 15.1-8 15.1.3.2.2 Systems Operation................................................................. 15.1-8 15.1.3.2.3 The Effect of Single Failures and Operator Errors .......................... 15.1-8 15.1.3.3 Core and System Performance .................................................... 15.1-9 15.1.3.3.1 Mathematical Model .............................................................. 15.1-9 15.1.3.3.2 Input Parameters and Initial Conditions ....................................... 15.1-9 15.1.3.3.3 Results ............................................................................... 15.1-9 15.1.3.3.4 Consideration of Uncertainties .................................................. 15.1-9 15.1.3.4 Barrier Performance ................................................................. 15.1-10 15.1.3.5 Radiological Consequences ........................................................ 15.1-10 LDCN-10-029                                       15-ii

COLUMBIA GENERATING STATION                                      Amendment 61 FINAL SAFETY ANALYSIS REPORT                                     December 2011 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.1.4 INADVERTENT SAFETY/RELIEF VALVE OPENING ..................... 15.1-10 15.1.4.1 Identification of Causes and Frequency Classification ........................ 15.1-10 15.1.4.1.1 Identification of Causes .......................................................... 15.1-10 15.1.4.1.2 Frequency Classification ......................................................... 15.1-10 15.1.4.2 Sequence of Events and Systems Operation ..................................... 15.1-11 15.1.4.2.1 Sequence of Events ............................................................... 15.1-11 15.1.4.2.2 Systems Operation................................................................. 15.1-11 15.1.4.2.3 The Effect of Single Failures and Operator Errors .......................... 15.1-11 15.1.4.3 Core and System Performance .................................................... 15.1-11 15.1.4.3.1 Mathematical Model .............................................................. 15.1-11 15.1.4.3.2 Input Parameters and Initial Conditions ....................................... 15.1-11 15.1.4.3.3 Results ............................................................................... 15.1-12 15.1.4.4 Barrier Performance ................................................................. 15.1-12 15.1.4.5 Radiological Consequences ........................................................ 15.1-12 15.1.5 SPECTRUM OF STEAM PIPING FAILURES INSIDE AND OUTSIDE OF CONTAINMENT IN A PRESSURIZED WATER REACTOR .............................................................................. 15.1-12 15.1.6 INADVERTENT RESIDUAL HEAT REMOVAL SHUTDOWN COOLING OPERATION ............................................................ 15.1-12 15.1.6.1 Identification of Causes and Frequency Classification ........................ 15.1-13 15.1.6.1.1 Identification of Causes .......................................................... 15.1-13 15.1.6.1.2 Frequency Classification ......................................................... 15.1-13 15.1.6.2 Sequence of Events and Systems Operation ..................................... 15.1-13 15.1.6.2.1 Sequence of Events ............................................................... 15.1-13 15.1.6.2.2 System Operation .................................................................. 15.1-13 15.1.6.2.3 Effect of Single Failures and Operator Action ............................... 15.1-14 15.1.6.3 Core and System Performance .................................................... 15.1-14 15.1.6.4 Barrier Performance ................................................................. 15.1-14 15.1.6.5 Radiological Consequences ........................................................ 15.1-14 15.

==1.7 REFERENCES==
 ......................................................................... 15.1-14 15.2 INCREASE IN REACTOR PRESSURE ............................................. 15.2-1 15.2.1 PRESSURE REGULATOR FAILURE - CLOSED.............................. 15.2-1 15.2.1.1 Identification of Causes and Frequency Classification ........................ 15.2-1 15.2.1.1.1 Identification of Causes .......................................................... 15.2-1 15.2.1.1.2 Frequency Classification ......................................................... 15.2-1 LDCN-10-029                                       15-iii

COLUMBIA GENERATING STATION                                      Amendment 59 FINAL SAFETY ANALYSIS REPORT                                     December 2007 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                           Page 15.2.1.2 Sequence of Events and Systems Operation..................................... 15.2-1 15.2.1.2.1 Sequence of Events ............................................................... 15.2-1 15.2.1.2.2 Systems Operation................................................................. 15.2-2 15.2.1.2.3 The Effect of Single Failures and Operator Errors.......................... 15.2-2 15.2.1.3 Core and System Performance .................................................... 15.2-2 15.2.1.3.1 Mathematical Model .............................................................. 15.2-2 15.2.1.3.2 Input Parameters and Initial Conditions ....................................... 15.2-3 15.2.1.3.3 Results............................................................................... 15.2-3 15.2.1.3.4 Consideration of Uncertainties .................................................. 15.2-3 15.2.1.4 Barrier Performance................................................................. 15.2-3 15.2.1.5 Radiological Consequences ........................................................ 15.2-3 15.2.2 GENERATOR LOAD REJECTION ............................................... 15.2-4 15.2.2.1 Identification of Causes and Frequency Classification ........................ 15.2-4 15.2.2.1.1 Identification of Causes .......................................................... 15.2-4 15.2.2.1.2 Frequency Classification ......................................................... 15.2-4 15.2.2.1.2.1 Generator Load Rejection ..................................................... 15.2-4 15.2.2.1.2.2 Generator Load Rejection with Bypass Failure............................ 15.2-4 15.2.2.2 Sequence of Events and System Operation ...................................... 15.2-4 15.2.2.2.1 Sequence of Events ............................................................... 15.2-5 15.2.2.2.1.1 Generator Load Rejection - Turbine Control Valve Fast Closure...... 15.2-5 15.2.2.2.1.2 Generator Load Rejection with Failure of Bypass ........................ 15.2-5 15.2.2.2.2 System Operation.................................................................. 15.2-5 15.2.2.2.2.1 Generator Load Rejection with Bypass ..................................... 15.2-5 15.2.2.2.2.2 Generator Load Rejection with Failure of Bypass ........................ 15.2-5 15.2.2.2.3 The Effect of Single Failures and Operator Errors.......................... 15.2-5 15.2.2.3 Core and System Performance .................................................... 15.2-6 15.2.2.3.1 Mathematical Model .............................................................. 15.2-6 15.2.2.3.1.1 Generator Load Rejection with Bypass ..................................... 15.2-6 15.2.2.3.1.2 Generator Load Rejection with Bypass Failure............................ 15.2-6 15.2.2.3.2 Input Parameters and Initial Conditions ....................................... 15.2-7 15.2.2.3.3 Results............................................................................... 15.2-7 15.2.2.3.3.1 Generator Load Rejection with Bypass ..................................... 15.2-7 15.2.2.3.3.2 Generator Load Rejection with Failure of Bypass ........................ 15.2-7 15.2.2.3.4 Consideration of Uncertainties .................................................. 15.2-7 15.2.2.4 Barrier Performance................................................................. 15.2-8 15.2.2.4.1 Generator Load Rejection........................................................ 15.2-8 LDCN-06-057, 07-011                              15-iv

COLUMBIA GENERATING STATION                                      Amendment 61 FINAL SAFETY ANALYSIS REPORT                                     December 2011 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.2.2.4.2 Generator Load Rejection with Failure of Bypass ........................... 15.2-8 15.2.2.5 Radiological Consequences ........................................................ 15.2-8 15.2.3 TURBINE TRIP ........................................................................ 15.2-8 15.2.3.1 Identification of Causes and Frequency Classification ........................ 15.2-8 15.2.3.1.1 Identification of Causes .......................................................... 15.2-8 15.2.3.1.2 Frequency Classification ......................................................... 15.2-8 15.2.3.1.2.1 Turbine Trip ..................................................................... 15.2-8 15.2.3.1.2.2 Turbine Trip with Failure of Bypass ........................................ 15.2-9 15.2.3.2 Sequence of Events and Systems Operation ..................................... 15.2-9 15.2.3.2.1 Sequence of Events ............................................................... 15.2-9 15.2.3.2.1.1 Turbine Trip ..................................................................... 15.2-9 15.2.3.2.1.2 Turbine Trip with Failure of Bypass ........................................ 15.2-9 15.2.3.2.2 Systems Operation................................................................. 15.2-9 15.2.3.2.2.1 Turbine Trip ..................................................................... 15.2-9 15.2.3.2.2.2 Turbine Trip with Failure of Bypass ........................................ 15.2-9 15.2.3.2.2.3 Turbine Trip at Low Power with Failure of Bypass ...................... 15.2-9 15.2.3.2.3 The Effect of Single Failures and Operator Errors .......................... 15.2-10 15.2.3.2.3.1 Turbine Trips at Power Levels Greater Than 30% Nuclear Boiler Rated ...................................................................... 15.2-10 15.2.3.2.3.2 Turbine Trips at Power Levels Less Than 30% Nuclear Boiler Rated ...................................................................... 15.2-10 15.2.3.3 Core and System Performance .................................................... 15.2-10 15.2.3.3.1 Mathematical Model .............................................................. 15.2-10 15.2.3.3.1.1 Turbine Trip with Bypass ..................................................... 15.2-10 15.2.3.3.1.2 Turbine Trip with Bypass Failure ............................................ 15.2-10 15.2.3.3.2 Input Parameters and Initial Conditions ....................................... 15.2-10 15.2.3.3.3 Results ............................................................................... 15.2-11 15.2.3.3.3.1 Turbine Trip ..................................................................... 15.2-11 15.2.3.3.3.2 Turbine Trip with Failure of Bypass ........................................ 15.2-11 15.2.3.3.3.3 Turbine Trip with Bypass Valve Failure, Low Power ................... 15.2-11 15.2.3.3.4 Considerations of Uncertainties ................................................. 15.2-12 15.2.3.4 Barrier Performance ................................................................. 15.2-12 15.2.3.4.1 Turbine Trip........................................................................ 15.2-12 15.2.3.4.2 Turbine Trip with Failure of Bypass ........................................... 15.2-12 15.2.3.4.2.1 Turbine Trip with Failure of Bypass at Low Power ...................... 15.2-12 15.2.3.5 Radiological Consequences ........................................................ 15.2-12 LDCN-10-029                                        15-v

COLUMBIA GENERATING STATION                                      Amendment 61 FINAL SAFETY ANALYSIS REPORT                                     December 2011 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.2.4 MAIN STEAM LINE ISOLATION VALVE CLOSURES..................... 15.2-12 15.2.4.1 Identification of Causes and Frequency Classification ........................ 15.2-13 15.2.4.1.1 Identification of Causes .......................................................... 15.2-13 15.2.4.1.2 Frequency Classification ......................................................... 15.2-13 15.2.4.1.2.1 Closure of All Main Steam Line Isolation Valves ........................ 15.2-13 15.2.4.1.2.2 Closure of One Main Steam Line Isolation Valve ........................ 15.2-13 15.2.4.2 Sequence of Events and Systems Operation ..................................... 15.2-13 15.2.4.2.1 Sequence of Events ............................................................... 15.2-13 15.2.4.2.2 Systems Operation................................................................. 15.2-14 15.2.4.2.2.1 Closure of All Main Steam Line Isolation Valves ........................ 15.2-14 15.2.4.2.2.2 Closure of One Main Steam Line Isolation Valve ........................ 15.2-14 15.2.4.2.3 The Effect of Single Failures and Operator Errors .......................... 15.2-14 15.2.4.3 Core and System Performance .................................................... 15.2-14 15.2.4.3.1 Mathematical Model .............................................................. 15.2-14 15.2.4.3.2 Input Parameters and Initial Conditions ....................................... 15.2-15 15.2.4.3.3 Results ............................................................................... 15.2-15 15.2.4.3.3.1 Closure of All Main Steam Line Isolation Valves ........................ 15.2-15 15.2.4.3.3.2 Closure of One Main Steam Line Isolation Valve ........................ 15.2-15 15.2.4.3.4 Considerations of Uncertainties ................................................. 15.2-16 15.2.4.4 Barrier Performance ................................................................. 15.2-16 15.2.4.4.1 Closure of All Main Steam Line Isolation Valves ........................... 15.2-16 15.2.4.4.2 Closure of One Main Steam Line Isolation Valve ........................... 15.2-16 15.2.4.5 Radiological Consequences ........................................................ 15.2-16 15.2.5 LOSS-OF-CONDENSER VACUUM .............................................. 15.2-17 15.2.5.1 Identification of Causes and Frequency Classification ........................ 15.2-17 15.2.5.1.1 Identification of Causes .......................................................... 15.2-17 15.2.5.1.2 Frequency Classification ......................................................... 15.2-17 15.2.5.2 Sequence of Events and Systems Operation ..................................... 15.2-17 15.2.5.2.1 Sequence of Events ............................................................... 15.2-17 15.2.5.2.2 Systems Operation................................................................. 15.2-17 15.2.5.2.3 The Effect of Single Failures and Operator Errors .......................... 15.2-18 15.2.5.3 Core and System Performance .................................................... 15.2-18 15.2.5.3.1 Mathematical Model .............................................................. 15.2-18 15.2.5.3.2 Input Parameters and Initial Conditions ....................................... 15.2-18 15.2.5.3.3 Results ............................................................................... 15.2-18 15.2.5.3.4 Consideration of Uncertainties .................................................. 15.2-18 LDCN-10-029                                       15-vi

COLUMBIA GENERATING STATION                                      Amendment 61 FINAL SAFETY ANALYSIS REPORT                                     December 2011 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.2.5.4 Barrier Performance ................................................................. 15.2-19 15.2.5.5 Radiological Consequences ........................................................ 15.2-19 15.2.6 LOSS OF ALTERNATING CURRENT POWER ............................... 15.2-20 15.2.6.1 Identification of Causes and Frequency Classification ........................ 15.2-20 15.2.6.1.1 Identification of Causes .......................................................... 15.2-20 15.2.6.1.1.1 Loss of Auxiliary Power Transformers ..................................... 15.2-20 15.2.6.1.1.2 Loss of All Grid Connections................................................. 15.2-20 15.2.6.1.2 Frequency Classification ......................................................... 15.2-20 15.2.6.1.2.1 Loss of Auxiliary Power Transformers ..................................... 15.2-20 15.2.6.1.2.2 Loss of All Grid Connections................................................. 15.2-20 15.2.6.2 Sequence of Events and Systems Operation ..................................... 15.2-20 15.2.6.2.1 Sequence of Events ............................................................... 15.2-20 15.2.6.2.1.1 Loss of Auxiliary Power Transformers ..................................... 15.2-20 15.2.6.2.1.2 Loss of All Grid Connections................................................. 15.2-20 15.2.6.2.2 Systems Operation................................................................. 15.2-21 15.2.6.2.2.1 Loss of Auxiliary Power Transformers ..................................... 15.2-21 15.2.6.2.2.2 Loss of All Grid Connections................................................. 15.2-21 15.2.6.2.3 The Effect of Single Failures and Operator Errors .......................... 15.2-21 15.2.6.3 Core and System Performance .................................................... 15.2-22 15.2.6.3.1 Mathematical Model .............................................................. 15.2-22 15.2.6.3.2 Input Parameters and Initial Conditions ....................................... 15.2-22 15.2.6.3.2.1 Loss of Auxiliary Power Transformers ..................................... 15.2-22 15.2.6.3.2.2 Loss of All Grid Connections................................................. 15.2-22 15.2.6.3.3 Results ............................................................................... 15.2-22 15.2.6.3.3.1 Loss of Auxiliary Power Transformers ..................................... 15.2-22 15.2.6.3.3.2 Loss of All Grid Connections................................................. 15.2-23 15.2.6.3.4 Consideration of Uncertainties .................................................. 15.2-23 15.2.6.4 Barrier Performance ................................................................. 15.2-23 15.2.6.4.1 Loss of Auxiliary Power Transformers........................................ 15.2-23 15.2.6.4.2 Loss of All Grid Connections ................................................... 15.2-24 15.2.6.5 Radiological Consequences ........................................................ 15.2-24 15.2.7 LOSS-OF-FEEDWATER FLOW ................................................... 15.2-24 15.2.7.1 Identification of Causes and Frequency Classification ........................ 15.2-24 15.2.7.1.1 Identification of Causes .......................................................... 15.2-24 15.2.7.1.2 Frequency Classification ......................................................... 15.2-24 LDCN-10-029                                       15-vii

COLUMBIA GENERATING STATION                                      Amendment 61 FINAL SAFETY ANALYSIS REPORT                                     December 2011 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.2.7.2 Sequence of Events and Systems Operation ..................................... 15.2-24 15.2.7.2.1 Sequence of Events ............................................................... 15.2-24 15.2.7.2.2 Systems Operation................................................................. 15.2-25 15.2.7.2.3 The Effect of Single Failures and Operator Errors .......................... 15.2-25 15.2.7.3 Core and System Performance .................................................... 15.2-25 15.2.7.3.1 Mathematical Model .............................................................. 15.2-25 15.2.7.3.2 Input Parameters and Initial Conditions ....................................... 15.2-26 15.2.7.3.3 Results ............................................................................... 15.2-26 15.2.7.3.4 Consideration of Uncertainties .................................................. 15.2-26 15.2.7.4 Barrier Performance ................................................................. 15.2-26 15.2.7.5 Radiological Consequences ........................................................ 15.2-26 15.2.8 FEEDWATER LINE BREAK ....................................................... 15.2-26 15.2.9 FAILURE OF RESIDUAL HEAT REMOVAL SHUTDOWN COOLING ............................................................................... 15.2-27 15.2.9.1 Identification of Causes and Frequency Classification ........................ 15.2-27 15.2.9.1.1 Identification of Causes .......................................................... 15.2-27 15.2.9.1.2 Frequency Classification ......................................................... 15.2-27 15.2.9.2 Sequence of Events and Systems Operation ..................................... 15.2-27 15.2.9.2.1 Sequence of Events ............................................................... 15.2-27 15.2.9.2.1.1 Identification of Operator Actions ........................................... 15.2-28 15.2.9.2.2 Systems Operation................................................................. 15.2-28 15.2.9.2.3 The Effect of Single Failures and Operator Errors .......................... 15.2-28 15.2.9.3 Core and System Performance .................................................... 15.2-28 15.2.9.4 Results ................................................................................. 15.2-29 15.2.9.4.1 Full Power to Approximately 100 psig ........................................ 15.2-29 15.2.9.4.2 Approximately 100 psig to Cold Shutdown ................................... 15.2-30 15.2.9.4.3 Temperature Response - 3462 MWt ........................................... 15.2-31 15.2.9.4.4 Temperature Response - 3702 MWt ........................................... 15.2-32 15.2.9.5 Barrier Performance ................................................................. 15.2-32 15.2.9.6 Radiological Consequences ........................................................ 15.2-32 15.2.10 REFERENCES ........................................................................ 15.2-32 15.3 DECREASE IN REACTOR COOLANT SYSTEM FLOW RATE ............. 15.3-1 15.3.1 RECIRCULATION PUMP TRIP ................................................... 15.3-1 15.3.1.1 Identification of Causes and Frequency Classification ........................ 15.3-1 15.3.1.1.1 Identification of Causes .......................................................... 15.3-1 LDCN-10-029                                      15-viii

COLUMBIA GENERATING STATION                                      Amendment 59 FINAL SAFETY ANALYSIS REPORT                                     December 2007 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                           Page 15.3.1.1.2 Frequency Classification ......................................................... 15.3-1 15.3.1.1.2.1 Trip of One Recirculation Pump ............................................. 15.3-1 15.3.1.1.2.2 Trip of Two Recirculation Pumps ........................................... 15.3-1 15.3.1.2 Sequence of Events and Systems Operation..................................... 15.3-2 15.3.1.2.1 Sequence of Events ............................................................... 15.3-2 15.3.1.2.1.1 Trip of One Recirculation Pump ............................................. 15.3-2 15.3.1.2.1.2 Trip of Two Recirculation Pumps ........................................... 15.3-2 15.3.1.2.2 Systems Operation................................................................. 15.3-2 15.3.1.2.2.1 Trip of One Recirculation Pump ............................................. 15.3-2 15.3.1.2.2.2 Trip of Two Recirculation Pumps ........................................... 15.3-2 15.3.1.2.3 The Effect of Single Failures and Operator Errors.......................... 15.3-2 15.3.1.2.3.1 Trip of One Recirculation Pump ............................................. 15.3-2 15.3.1.2.3.2 Trip of Two Recirculation Pumps ........................................... 15.3-2 15.3.1.3 Core and System Performance .................................................... 15.3-2 15.3.1.3.1 Mathematical Model .............................................................. 15.3-2 15.3.1.3.2 Input Parameters and Initial Conditions ....................................... 15.3-3 15.3.1.3.3 Results............................................................................... 15.3-3 15.3.1.3.3.1 Trip of One Recirculation Pump ............................................. 15.3-3 15.3.1.3.3.2 Trip of Two Recirculation Pumps ........................................... 15.3-3 15.3.1.3.4 Consideration of Uncertainties .................................................. 15.3-3 15.3.1.4 Barrier Performance................................................................. 15.3-3 15.3.1.4.1 Trip of One Recirculation Pump................................................ 15.3-3 15.3.1.4.2 Trip of Two Recirculation Pumps .............................................. 15.3-4 15.3.1.5 Radiological Consequences ........................................................ 15.3-4 15.3.2 RECIRCULATION FLOW CONTROL FAILURE - DECREASING FLOW ................................................................................... 15.3-4 15.3.2.1 Identification of Causes and Frequency Classification ........................ 15.3-4 15.3.2.1.1 Identification of Causes .......................................................... 15.3-4 15.3.2.1.2 Frequency Classification ......................................................... 15.3-4 15.3.2.2 Sequence of Events and Systems Operation..................................... 15.3-4 15.3.2.2.1 Sequence of Events ............................................................... 15.3-4 15.3.2.2.1.1 Speed Decrease of One Recirculation Pump ............................... 15.3-4 15.3.2.2.1.2 Speed Decrease of Two Recirculation Pumps ............................. 15.3-4 15.3.2.2.2 Systems Operation................................................................. 15.3-5 15.3.2.2.2.1 Speed Decrease of One Recirculation Pump ............................... 15.3-5 15.3.2.2.2.2 Speed Decrease of Two Recirculation Pumps ............................. 15.3-5 15-ix

COLUMBIA GENERATING STATION                                      Amendment 60 FINAL SAFETY ANALYSIS REPORT                                     December 2009 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                           Page 15.3.2.2.3 The Effect of Single Failures and Operator Errors.......................... 15.3-5 15.3.2.3 Core and System Performance .................................................... 15.3-5 15.3.2.3.1 Mathematical Model .............................................................. 15.3-5 15.3.2.3.2 Input Parameters and Initial Conditions ....................................... 15.3-5 15.3.2.3.2.1 Speed Decrease of One Recirculation Pump ............................... 15.3-5 15.3.2.3.2.2 Speed Decrease of Two Recirculation Pumps ............................. 15.3-6 15.3.2.3.3 Results............................................................................... 15.3-6 15.3.2.3.3.1 Speed Decrease of One Recirculation Pump ............................... 15.3-6 15.3.2.3.3.2 Speed Decrease of Two Recirculation Pumps ............................. 15.3-6 15.3.2.3.4 Consideration of Uncertainties .................................................. 15.3-6 15.3.2.4 Barrier Performance................................................................. 15.3-6 15.3.2.4.1 Speed Decrease of One Recirculation Pump.................................. 15.3-6 15.3.2.4.2 Speed Decrease of Two Recirculation Pumps................................ 15.3-7 15.3.2.5 Radiological Consequences ........................................................ 15.3-7 15.3.3 RECIRCULATION PUMP SEIZURE ............................................. 15.3-7 15.3.3.1 Identification of Causes and Frequency Classification ........................ 15.3-7 15.3.3.2 Sequence of Events and Systems Operation..................................... 15.3-7 15.3.3.2.1 Sequence of Events ............................................................... 15.3-7 15.3.3.2.2 Systems Operation................................................................. 15.3-8 15.3.3.2.3 The Effect of Single Failures and Operator Errors.......................... 15.3-8 15.3.3.3 Core and System Performance .................................................... 15.3-8 15.3.3.3.1 Mathematical Model .............................................................. 15.3-8 15.3.3.3.2 Input Parameters and Initial Conditions ....................................... 15.3-8 15.3.3.3.3 Results............................................................................... 15.3-9 15.3.3.3.3.1 Considerations of Uncertainties .............................................. 15.3-9 15.3.3.4 Barrier Performance................................................................. 15.3-9 15.3.3.5 Radiological Consequences ........................................................ 15.3-9 15.3.4 RECIRCULATION PUMP SHAFT BREAK ..................................... 15.3-9 15.3.4.1 Identification of Causes and Frequency Classification ........................ 15.3-9 15.3.4.1.1 Identification of Causes .......................................................... 15.3-10 15.3.4.1.2 Frequency Classification ......................................................... 15.3-10 15.3.4.2 Sequence of Events and Systems Operation..................................... 15.3-10 15.3.4.2.1 Sequence of Events ............................................................... 15.3-10 15.3.4.2.2 Systems Operation................................................................. 15.3-10 15.3.4.2.3 The Effect of Single Failures and Operator Errors.......................... 15.3-10 LDCN-08-035                                       15-x

COLUMBIA GENERATING STATION                                    Amendment 60 FINAL SAFETY ANALYSIS REPORT                                   December 2009 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                         Page 15.3.4.3 Core and System Performance .................................................... 15.3-11 15.3.4.3.1 Qualitative Results ................................................................ 15.3-11 15.3.4.4 Barrier Performance................................................................. 15.3-11 15.3.4.5 Radiological Consequences ........................................................ 15.3-11 15.

==3.5 REFERENCES==
 ......................................................................... 15.3-11 15.4 REACTIVITY AND POWER DISTRIBUTION ANOMALIES................. 15.4-1 15.4.1 ROD WITHDRAWAL ERROR - LOW POWER................................ 15.4-1 15.4.1.1 Control Rod Removal Error During Refueling ................................. 15.4-1 15.4.1.1.1 Identification of Causes and Frequency Classification...................... 15.4-1 15.4.1.1.2 Sequence of Events and Systems Operation .................................. 15.4-1 15.4.1.1.2.1 Initial Control Rod Removal .................................................. 15.4-1 15.4.1.1.2.2 Fuel Insertion With Control Rod Removed ................................ 15.4-1 15.4.1.1.2.3 Second Control Rod Removal ................................................ 15.4-1 15.4.1.1.2.4 Control Rod Removal Without Fuel Removal ............................. 15.4-1 15.4.1.1.2.5 Effect of Single Failure and Operator Errors .............................. 15.4-2 15.4.1.1.3 Core and System Performances................................................. 15.4-2 15.4.1.1.4 Barrier Performance .............................................................. 15.4-2 15.4.1.1.5 Radiological Consequences ...................................................... 15.4-2 15.4.1.2 Continuous Rod Withdrawal During Reactor Startup ......................... 15.4-2 15.4.1.2.1 Identification of Causes and Frequency Classification...................... 15.4-2 15.4.1.2.2 Sequence of Events and Systems Operation .................................. 15.4-3 15.4.1.2.2.1 Sequence of Events ............................................................. 15.4-3 15.4.1.2.2.2 Effects of Single Failure and Operator Errors ............................. 15.4-3 15.4.1.2.3 Core and System Performance .................................................. 15.4-3 15.4.1.2.4 Barrier Performance .............................................................. 15.4-3 15.4.1.2.5 Radiological Consequences ...................................................... 15.4-3 15.4.2 ROD WITHDRAWAL ERROR - AT POWER .................................. 15.4-4 15.4.2.1 Identification of Causes and Frequency Classifications ....................... 15.4-4 15.4.2.1.1 Identification of Causes .......................................................... 15.4-4 15.4.2.1.2 Frequency Classification ......................................................... 15.4-4 15.4.2.2 Sequence of Events and Systems Operation..................................... 15.4-4 15.4.2.2.1 Sequence of Events ............................................................... 15.4-4 15.4.2.2.2 Systems Operation................................................................. 15.4-4 15.4.2.2.3 Effect of Single Failure and Operator Errors................................. 15.4-5 LDCN-08-035                                    15-xi

COLUMBIA GENERATING STATION                                      Amendment 63 FINAL SAFETY ANALYSIS REPORT                                     December 2015 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.4.2.3 Core and System Performance .................................................... 15.4-5 15.4.2.3.1 Mathematical Model .............................................................. 15.4-5 15.4.2.3.2 Input Parameters and Initial Conditions ....................................... 15.4-5 15.4.2.3.2.1 Rod Block Monitor System Operation ...................................... 15.4-6 15.4.2.3.3 Results ............................................................................... 15.4-6 15.4.2.3.4 Considerations of Uncertainties ................................................. 15.4-6 15.4.2.4 Barrier Performance ................................................................. 15.4-6 15.4.2.5 Radiological Consequences ........................................................ 15.4-7 15.4.3 CONTROL ROD MALOPERATION (SYSTEM MALFUNCTION OR OPERATOR ERROR) ................................................................ 15.4-7 15.4.4 STARTUP OF IDLE RECIRCULATION PUMP ............................... 15.4-7 15.4.4.1 Identification of Causes and Frequency Classification ........................ 15.4-7 15.4.4.1.1 Identification of Causes .......................................................... 15.4-7 15.4.4.1.2 Frequency Classification ......................................................... 15.4-7 15.4.4.1.2.1 Normal Restart of Recirculation Pump at Power.......................... 15.4-7 15.4.4.1.2.2 Abnormal Startup of Idle Recirculation Pump ............................. 15.4-7 15.4.4.2 Sequence of Events and Systems Operation ..................................... 15.4-7 15.4.4.2.1 Sequence of Events ............................................................... 15.4-7 15.4.4.2.2 Systems Operation................................................................. 15.4-8 15.4.4.2.3 The Effect of Single Failures and Operator Errors .......................... 15.4-8 15.4.4.3 Core and System Performance .................................................... 15.4-8 15.4.4.3.1 Mathematical Model .............................................................. 15.4-8 15.4.4.3.2 Input Parameters and Initial Conditions ....................................... 15.4-8 15.4.4.3.3 Results ............................................................................... 15.4-8 15.4.4.3.4 Consideration of Uncertainties .................................................. 15.4-9 15.4.4.4 Barrier Performance ................................................................. 15.4-9 15.4.4.5 Radiological Consequences ........................................................ 15.4-9 15.4.5 RECIRCULATION FLOW CONTROL FAILURE WITH INCREASING FLOW ................................................................. 15.4-9 15.4.5.1 Identification of Causes and Frequency Classification ........................ 15.4-9 15.4.5.1.1 Identification of Causes .......................................................... 15.4-9 15.4.5.1.2 Frequency Classification ......................................................... 15.4-9 15.4.5.2 Sequence of Events and Systems Operation ..................................... 15.4-10 15.4.5.2.1 The Effect of Single Failures and Operator Errors .......................... 15.4-10 15.4.5.3 Core and System Performance .................................................... 15.4-10 15.4.5.3.1 Mathematical Model .............................................................. 15.4-10 LDCN-10-004                                       15-xii

COLUMBIA GENERATING STATION                                      Amendment 63 FINAL SAFETY ANALYSIS REPORT                                     December 2015 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.4.5.3.2 Input Parameters and Initial Conditions ....................................... 15.4-11 15.4.5.3.3 Results ............................................................................... 15.4-11 15.4.5.3.4 Considerations of Uncertainties ................................................. 15.4-11 15.4.5.4 Barrier Performance ................................................................. 15.4-11 15.4.5.5 Radiological Consequences ........................................................ 15.4-12 15.4.6 CHEMICAL AND VOLUME CONTROL SYSTEM MALFUNCTIONS .. 15.4-12 15.4.7 MISPLACED BUNDLE ACCIDENT ............................................. 15.4-12 15.4.7.1 Identification of Causes and Frequency Classification ........................ 15.4-12 15.4.7.1.1 Identification of Causes .......................................................... 15.4-12 15.4.7.1.2 Frequency of Occurrence ........................................................ 15.4-13 15.4.7.2 Sequence of Events and Systems Operation ..................................... 15.4-13 15.4.7.2.1 Effect of Single Failure and Operator Errors................................. 15.4-13 15.4.7.3 Core and System Performance .................................................... 15.4-13 15.4.7.3.1 Mathematical Model .............................................................. 15.4-13 15.4.7.3.2 Input Parameters and Initial Conditions ....................................... 15.4-13 15.4.7.3.3 Results ............................................................................... 15.4-13 15.4.7.3.4 Considerations of Uncertainties ................................................. 15.4-14 15.4.7.4 Barrier Performance ................................................................. 15.4-14 15.4.7.5 Radiological Consequences ........................................................ 15.4-14 15.4.8 SPECTRUM OF ROD EJECTION ASSEMBLIES .............................. 15.4-14 15.4.9 CONTROL ROD DROP ACCIDENT ............................................. 15.4-14 15.4.9.1 Identification of Causes and Frequency Classification ........................ 15.4-14 15.4.9.1.1 Identification of Causes .......................................................... 15.4-14 15.4.9.1.2 Frequency Classification ......................................................... 15.4-15 15.4.9.2 Sequence of Events and Systems Operation ..................................... 15.4-15 15.4.9.2.1 Effect of Single Failures and Operator Errors ............................... 15.4-16 15.4.9.3 Core and System Performance .................................................... 15.4-16 15.4.9.3.1 Mathematical Model .............................................................. 15.4-16 15.4.9.3.2 Input Parameters and Initial Conditions ....................................... 15.4-16 15.4.9.3.3 Results ............................................................................... 15.4-16 15.4.9.4 Barrier Performance ................................................................. 15.4-17 15.4.9.5 Radiological Consequences ........................................................ 15.4-17 15.4.9.5.1 Fission Product Release from Fuel ............................................. 15.4-17 15.4.9.5.2 Fission Product Transport to the Environment ............................... 15.4-18 15.4.9.5.3 Results ............................................................................... 15.4-18 15.4.10 REFERENCES ........................................................................ 15.4-19 LDCN-10-004                                      15-xiii

COLUMBIA GENERATING STATION                                      Amendment 57 FINAL SAFETY ANALYSIS REPORT                                     December 2003 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                           Page 15.5 INCREASE IN REACTOR COOLANT INVENTORY........................... 15.5-1 15.5.1 INADVERTENT HIGH-PRESSURE CORE SPRAY STARTUP ............ 15.5-1 15.5.1.1 Identification of Causes and Frequency Classification ........................ 15.5-1 15.5.1.1.1 Identification of Causes .......................................................... 15.5-1 15.5.1.1.2 Frequency Classification ......................................................... 15.5-1 15.5.1.2 Sequence of Events and Systems Operation..................................... 15.5-1 15.5.1.2.1 The Effect of Single Failures and Operator Errors.......................... 15.5-1 15.5.1.3 Core and System Performance .................................................... 15.5-2 15.5.1.3.1 Mathematical Model .............................................................. 15.5-2 15.5.1.3.2 Input Parameter and Initial Conditions ........................................ 15.5-2 15.5.1.3.3 Results............................................................................... 15.5-2 15.5.1.3.3.1 Consideration of Uncertainties ............................................... 15.5-2 15.5.1.4 Barrier Performance................................................................. 15.5-2 15.5.1.5 Radiological Consequences ........................................................ 15.5-2 15.5.2 CHEMICAL VOLUME CONTROL SYSTEM MALFUNCTION (OR OPERATOR ERROR) .......................................................... 15.5-2 15.5.3 BOILING WATER REACTOR TRANSIENTS WHICH INCREASE REACTOR COOLANT INVENTORY ............................................ 15.5-2 15.

==5.4 REFERENCES==
 ......................................................................... 15.5-3 15.6 DECREASE IN REACTOR COOLANT INVENTORY.......................... 15.6-1 15.6.1 INADVERTENT SAFETY/RELIEF VALVE OPENING ..................... 15.6-1 15.6.2 INSTRUMENT LINE PIPE BREAK............................................... 15.6-1 15.6.2.1 Identification of Causes and Frequency Classification ........................ 15.6-1 15.6.2.1.1 Identification of Causes .......................................................... 15.6-1 15.6.2.1.2 Frequency Classification ......................................................... 15.6-1 15.6.2.2 Sequence of Events and Systems Operation..................................... 15.6-1 15.6.2.2.1 The Effect of Single Failures and Operator Errors.......................... 15.6-2 15.6.2.3 Core and System Performance .................................................... 15.6-2 15.6.2.3.1 Qualitative Summary - Results .................................................. 15.6-2 15.6.2.4 Barrier Performance................................................................. 15.6-2 15.6.2.4.1 General .............................................................................. 15.6-2 15.6.2.5 Radiological Consequences ........................................................ 15.6-2 15.6.2.5.1 Results............................................................................... 15.6-3 15.6.3 STEAM GENERATOR TUBE FAILURE ........................................ 15.6-3 LDCN-03-003                                     15-xiv

COLUMBIA GENERATING STATION                                      Amendment 59 FINAL SAFETY ANALYSIS REPORT                                     December 2007 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                           Page 15.6.4 STEAM SYSTEM PIPING BREAK OUTSIDE CONTAINMENT .......... 15.6-3 15.6.4.1 Identification of Causes and Frequency Classification ........................ 15.6-3 15.6.4.1.1 Identification of Causes .......................................................... 15.6-3 15.6.4.1.2 Frequency Classification ......................................................... 15.6-3 15.6.4.2 Sequence of Events and Systems Operation..................................... 15.6-4 15.6.4.2.1 Sequence of Events ............................................................... 15.6-4 15.6.4.2.2 Systems Operation................................................................. 15.6-4 15.6.4.2.3 The Effect of Single Failures and Operator Errors.......................... 15.6-4 15.6.4.3 Core and System Performance .................................................... 15.6-4 15.6.4.3.1 Input Parameters and Initial Conditions ....................................... 15.6-4 15.6.4.3.2 Results............................................................................... 15.6-5 15.6.4.3.3 Considerations of Uncertainties................................................. 15.6-5 15.6.4.4 Barrier Performance................................................................. 15.6-5 15.6.4.5 Radiological Consequences ........................................................ 15.6-5 15.6.4.5.1 Results............................................................................... 15.6-6 15.6.5 LOSS-OF-COOLANT ACCIDENTS (RESULTING FROM SPECTRUM OF POSTULATED PIPING BREAKS WITHIN THE REACTOR COOLANT PRESSURE BOUNDARY) - INSIDE CONTAINMENT....... 15.6-6 15.6.5.1 Identification of Causes and Frequency Classification ........................ 15.6-7 15.6.5.1.1 Identification of Causes .......................................................... 15.6-7 15.6.5.1.2 Frequency Classification ......................................................... 15.6-7 15.6.5.2 Sequence of Events and Systems Operation..................................... 15.6-7 15.6.5.3 Core and System Performance .................................................... 15.6-7 15.6.5.4 Radiological Consequences ........................................................ 15.6-7 15.6.5.4.1 Design Basis Analysis ............................................................ 15.6-7 15.6.5.4.1.1 Fission Product Release from Fuel .......................................... 15.6-8 15.6.5.4.1.2 Fission Product Transport to the Environment ............................ 15.6-8 15.6.5.4.1.3 Suppression Pool pH Control ................................................. 15.6-9 15.6.5.4.1.4 Results ............................................................................ 15.6-9 15.6.6 FEEDWATER LINE BREAK - OUTSIDE CONTAINMENT................ 15.6-9 15.6.6.1 Identification of Causes and Frequency Classification ........................ 15.6-9 15.6.6.1.1 Identification of Causes .......................................................... 15.6-9 15.6.6.1.2 Frequency Classification ......................................................... 15.6-9 15.6.6.2 Sequence of Events and Systems Operation..................................... 15.6-9 15.6.6.2.1 Sequence of Events ............................................................... 15.6-9 15.6.6.2.2 Systems Operation................................................................. 15.6-9 LDCN-05-009, 06-043                              15-xv

COLUMBIA GENERATING STATION                                      Amendment 61 FINAL SAFETY ANALYSIS REPORT                                     December 2011 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.6.6.2.3 The Effect of Single Failures and Operator Errors .......................... 15.6-10 15.6.6.3 Core and System Performance .................................................... 15.6-10 15.6.6.3.1 Qualitative Summary ............................................................. 15.6-10 15.6.6.3.2 Qualitative Results ................................................................ 15.6-10 15.6.6.3.3 Consideration of Uncertainties .................................................. 15.6-10 15.6.6.4 Barrier Performance ................................................................. 15.6-10 15.6.6.5 Radiological Consequences ........................................................ 15.6-11 15.6.6.5.1 Fission Product Release .......................................................... 15.6-11 15.6.6.5.2 Fission Product Transport to the Environment ............................... 15.6-11 15.6.6.5.3 Results ............................................................................... 15.6-12 15.

==6.7 REFERENCES==
 ......................................................................... 15.6-12 15.7 RADIOACTIVE RELEASE FROM SUBSYSTEMS AND COMPONENTS ................................................................... 15.7-1 15.7.1 RADIOACTIVE GAS WASTE SYSTEM LEAK OR FAILURE ............. 15.7-1 15.7.2 LIQUID RADIOACTIVE SYSTEM FAILURE.................................. 15.7-1 15.7.3 POSTULATED RADIOACTIVE RELEASES DUE TO LIQUID RADWASTE TANK FAILURE ..................................................... 15.7-1 15.7.3.1 Identification of Causes and Frequency Classification ........................ 15.7-1 15.7.3.1.1 Identification of Causes .......................................................... 15.7-1 15.7.3.1.2 Frequency Classification ......................................................... 15.7-1 15.7.3.2 Sequence of Events and Systems Operation ..................................... 15.7-1 15.7.3.2.1 Sequence of Events ............................................................... 15.7-1 15.7.3.2.2 Systems Operation................................................................. 15.7-2 15.7.3.2.3 The Effects of Single Failures and Operator Errors ......................... 15.7-2 15.7.3.3 Core and System Performance .................................................... 15.7-2 15.7.3.4 Barrier Performance ................................................................. 15.7-2 15.7.3.5 Radiological Consequences ........................................................ 15.7-3 15.7.4 FUEL HANDLING ACCIDENT ................................................... 15.7-3 15.7.4.1 Identification of Causes and Frequency Classification ........................ 15.7-3 15.7.4.1.1 Identification of Causes .......................................................... 15.7-3 15.7.4.1.2 Frequency Classification ......................................................... 15.7-3 15.7.4.2 Sequence of Events and Systems Operation ..................................... 15.7-4 15.7.4.2.1 The Effects of Single Failures and Operator Errors ......................... 15.7-4 15.7.4.3 Core and System Performance .................................................... 15.7-4 15.7.4.3.1 Mathematical Model .............................................................. 15.7-4 LDCN-09-007                                      15-xvi

COLUMBIA GENERATING STATION                                      Amendment 63 FINAL SAFETY ANALYSIS REPORT                                     December 2015 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.7.4.3.2 Input Parameters and Initial Conditions ....................................... 15.7-5 15.7.4.3.3 Results ............................................................................... 15.7-5 15.7.4.4 Barrier Performance ................................................................. 15.7-5 15.7.4.5 Radiological Consequences ........................................................ 15.7-6 15.7.4.5.1 Design Basis Analysis ............................................................ 15.7-6 15.7.4.5.1.1 Fission Product Release From Fuel ......................................... 15.7-6 15.7.4.5.1.2 Fission Product Transport to the Environment ............................ 15.7-6 15.7.4.5.1.3 Results ............................................................................ 15.7-6 15.7.5 SPENT FUEL CASK DROP ACCIDENT ........................................ 15.7-6 15.

==7.6 REFERENCES==
 ......................................................................... 15.7-7 15.8 ANTICIPATED TRANSIENTS WITHOUT SCRAM............................. 15.8-1 15.8.0 CAPABILITIES OF PRESENT DESIGN TO ACCOMMODATE ANTICIPATED TRANSIENTS WITHOUT SCRAM ......................... 15.8-1 15.8.1 INADVERTENT CONTROL ROD WITHDRAWAL ......................... 15.8-2a 15.8.2 LOSS OF FEEDWATER ............................................................ 15.8-2a 15.8.2.1 Identification of Causes and Frequency Classification ........................ 15.8-2a 15.8.2.1.1 Identification of Causes .......................................................... 15.8-2a 15.8.2.1.2 Frequency Classification ......................................................... 15.8-3 15.8.2.2 Sequence of Events and System Operation ...................................... 15.8-3 15.8.2.2.1 Sequence of Events ............................................................... 15.8-3 15.8.2.2.1.1 Identification of Operator Actions ........................................... 15.8-3 15.8.2.2.2 System Operation .................................................................. 15.8-3 15.8.2.2.3 The Effect of Single Failure and Operator Errors ........................... 15.8-3 15.8.2.3 Core and System Performance .................................................... 15.8-4 15.8.2.3.1 Mathematical Model .............................................................. 15.8-4 15.8.2.3.2 Input Parameters and Initial Conditions ....................................... 15.8-4 15.8.2.3.3 Results ............................................................................... 15.8-4 15.8.2.3.4 Consideration of Uncertainties .................................................. 15.8-4 15.8.2.4 Barrier Performance ................................................................. 15.8-5 15.8.2.5 Radiological Consequences ........................................................ 15.8-5 15.8.3 LOSS OF ALTERNATE CURRENT POWER................................... 15.8-5 15.8.4 LOSS OF ELECTRICAL LOAD ................................................... 15.8-5 15.8.5 LOSS OF CONDENSER VACUUM ............................................... 15.8-5 15.8.6 TURBINE TRIP ........................................................................ 15.8-5 LDCN-10-004                                      15-xvii

COLUMBIA GENERATING STATION                                      Amendment 61 FINAL SAFETY ANALYSIS REPORT                                     December 2011 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.8.7 CLOSURE OF MAIN STEAM LINE ISOLATION VALVES ................ 15.8-6 15.8.7.1 Identification of Causes and Frequency Classification ........................ 15.8-6 15.8.7.1.1 Identification of Causes .......................................................... 15.8-6 15.8.7.1.2 Frequency Classification ......................................................... 15.8-6 15.8.7.2 Sequence of Events and System Operation ...................................... 15.8-6 15.8.7.2.1 Sequence of Events ............................................................... 15.8-6 15.8.7.2.1.1 Identification of Operator Actions ........................................... 15.8-6 15.8.7.2.2 System Operation .................................................................. 15.8-6 15.8.7.2.3 The Effect of Single Failures and Operator Errors .......................... 15.8-7 15.8.7.3 Core and System Performance .................................................... 15.8-7 15.8.7.3.1 Mathematical Model .............................................................. 15.8-7 15.8.7.3.2 Input Parameters and Initial Conditions ....................................... 15.8-7 15.8.7.3.3 Results ............................................................................... 15.8-7 15.8.7.3.4 Consideration of Uncertainties .................................................. 15.8-8 15.8.7.4 Barrier Performance ................................................................. 15.8-8 15.8.7.5 Radiological Consequences ........................................................ 15.8-8 15.8.8 INADVERTENT OPENING OF RELIEF VALVE ............................. 15.8-9 15.8.8.1 Identification of Causes and Frequency Classification ........................ 15.8-9 15.8.8.1.1 Identification of Causes .......................................................... 15.8-9 15.8.8.1.2 Frequency Classification ......................................................... 15.8-9 15.8.8.2 Sequence of Events and System Operation ...................................... 15.8-9 15.8.8.2.1 Sequence of Events ............................................................... 15.8-9 15.8.8.2.1.1 Identification of Operator Actions ........................................... 15.8-9 15.8.8.2.1.2 System Operation ............................................................... 15.8-9 15.8.8.2.2 The Effect of Single Failures and Operator Errors .......................... 15.8-9 15.8.8.3 Core and System Performance .................................................... 15.8-10 15.8.8.3.1 Mathematical Model .............................................................. 15.8-10 15.8.8.3.2 Input Parameters and Initial Conditions ....................................... 15.8-10 15.8.8.3.3 Results ............................................................................... 15.8-10 15.8.8.3.4 Consideration of Uncertainties .................................................. 15.8-11 15.8.8.4 Barrier Performance ................................................................. 15.8-11 15.8.8.5 Radiological Consequences ........................................................ 15.8-11 15.8.9 PRESSURE REGULATOR FAILURE - OPEN (PREGO)..................... 15.8-11 15.8.9.1 Identification of Causes and Frequency Classification ........................ 15.8-11 15.8.9.1.1 Identification of Causes .......................................................... 15.8-11 15.8.9.1.2 Frequency Classification ......................................................... 15.8-11 LDCN-09-007                                      15-xviii

COLUMBIA GENERATING STATION                                      Amendment 63 FINAL SAFETY ANALYSIS REPORT                                     December 2015 Chapter 15 ACCIDENT ANALYSES TABLE OF CONTENTS (Continued)
Section                                                                                            Page 15.8.9.2 Sequence of Events and System Operation ...................................... 15.8-11 15.8.9.2.1 Sequence of Events ............................................................... 15.8-11 15.8.9.2.1.1 Identification of Operator Actions ........................................... 15.8-12 15.8.9.2.1.2 System Operation ............................................................... 15.8-12 15.8.9.2.3 The Effect of Single Failures and Operator Errors .......................... 15.8-12 15.8.9.3 Core and System Performance .................................................... 15.8-12 15.8.9.3.1 Mathematical Model .............................................................. 15.8-12 15.8.9.3.2 Input Parameters and Initial Conditions ....................................... 15.8-12 15.8.9.3.3 Results ............................................................................... 15.8-13 15.8.9.3.4 Consideration of Uncertainties .................................................. 15.8-13 15.8.9.4 Barrier Performance ................................................................. 15.8-13 15.8.9.5 Radiological Consequences ........................................................ 15.8-13 15.8.10 SINGLE REACTOR RECIRCULATION SYSTEM PUMP OPERATION ................................................................ 15.8-14 15.8.11 REFERENCES ........................................................................ 15.8-15 LDCN-10-004                                      15-xix

COLUMBIA GENERATING STATION                                    Amendment 63 FINAL SAFETY ANALYSIS REPORT                                   December 2015 Chapter 15 ACCIDENT ANALYSES LIST OF TABLES Number                                   Title                                                Page 15.0-1      Results Summary of Transient Events Applicable to Columbia Generating Station .............................................................. 15.0-17 15.0-1A     Summary of Transient Peak Value Results Single-Loop Operation .... 15.0-20 15.0-2      Input Parameters and Initial Conditions for Transients................... 15.0-21 15.0-2A     Input Parameters and Initial Conditions for Transients and Accidents for Single-Loop Operation........................................ 15.0-24 15.0-2B     Input Parameters and Initial Conditions for ARTS/MELLLA and GNF Reload Transient ......................................................... 15.0-26 15.0-3      Summary of Accidents ......................................................... 15.0-28 15.0-4      /Q (s/m3) values for the EAB and LPZ .................................... 15.0-29 15.0-5      Control Room Atmospheric Dispersion Factors (sec/m3) ................ 15.0-30 15.1-1      Sequence of Events for Figure 15.1-1 ....................................... 15.1-17 15.1-1A     Sequence of Events for Figure 15.1-3 ....................................... 15.1-18 15.1-2      Sequence of Events for Figure 15.1-2 ....................................... 15.1-19 15.1-3      Sequence of Events for Inadvertent Safety/Relief Valve Opening ..... 15.1-20 15.1-4      Sequence of Events for Inadvertent Residual Heat Removal Shutdown Cooling Operation ................................................. 15.1-21 15.2-1      Sequence of Events for Figure 15.2-1 ....................................... 15.2-35 15.2-2      Sequence of Events for Figure 15.2-2.1 .................................... 15.2-36 15.2-3      Sequence of Events for Figure 15.2-2.2 .................................... 15.2-37 15.2-4      Sequence of Events for Figure 15.2-3 ....................................... 15.2-38 LDCN-10-004                                  15-xx

COLUMBIA GENERATING STATION                                  Amendment 61 FINAL SAFETY ANALYSIS REPORT                                 December 2011 Chapter 15 ACCIDENT ANALYSES LIST OF TABLES (Continued)
Number                                 Title                                                Page 15.2-5      Sequence of Events for Figure 15.2-4 ....................................... 15.2-39 15.2-6      Sequence of Events for Figure 15.2-5 ....................................... 15.2-40 15.2-7      Sequence of Events for Figure 15.2-6 ....................................... 15.2-41 15.2-8      Trip Signals Associated with Loss-of-Condenser Vacuum .............. 15.2-42 15.2-9      Sequence of Events for Figure 15.2-7 ....................................... 15.2-43 15.2-10     Sequence of Events for Figure 15.2-8 ....................................... 15.2-44 15.2-11     Sequence of Events for Figure 15.2-9 ....................................... 15.2-45 15.2-12     Sequence of Events for Failure of Residual Heat Removal Shutdown Cooling .............................................................. 15.2-46 15.2-13     Evaluation of Failure of Residual Heat Removal Shutdown Cooling .............................................................. 15.2-47 15.3-1      Sequence of Events for Figure 15.3-1 ....................................... 15.3-13 15.3-2      Sequence of Events for Figure 15.3-2 ....................................... 15.3-14 15.3-3      Sequence of Events for Figure 15.3-3 ....................................... 15.3-15 15.3-4      Sequence of Events for Figure 15.3-4 ....................................... 15.3-16 15.3-5      Sequence of Events for Figure 15.3-5 ....................................... 15.3-17 15.3-6      Sequence of Events for Pump Seizure (for Single Loop Operation) ... 15.3-18 15.4-1      Sequence of Events - Rod Withdrawal Error in Power Range .......... 15.4-21 LDCN-10-029                               15-xxi

COLUMBIA GENERATING STATION                                     Amendment 59 FINAL SAFETY ANALYSIS REPORT                                    December 2007 Chapter 15 ACCIDENT ANALYSES LIST OF TABLES (Continued)
Number                                    Title                                                Page 15.4-2      Sequence of Events for an Abnormal Startup of an Idle Recirculation Loop ............................................................. 15.4-22 15.4-3      Reactor Recirculation Pump Flow Increase Input Parameters and Initial Conditions................................................................ 15.4-23 15.4-4      Control Rod Drop Accident Evaluation Parameters ...................... 15.4-24 15.4-5      Control Rod Drop Accident Activity Airborne in the Condenser (Curies) ............................................................. 15.4-26 15.4-6      Control Rod Drop Accident Activity Airborne to the Environment (Curies) .......................................................... 15.4-29 15.4-7      Control Rod Drop Accident Radiological Effects (rem) ................. 15.4-32 15.5-1      Input Parameters and Initial Conditions HPCS Injection ................ 15.5-5 15.6-1      Instrument Line Break Accident - Parameters Tabulated for Postulated Accident Analyses................................................. 15.6-13 15.6-2      Instrument Line Failure ........................................................ 15.6-15 15.6-3      Instrument Line Failure Radiological Effects .............................. 15.6-16 15.6-4      Sequence of Events for Steam Line Break Outside Containment....... 15.6-17 15.6-5      Steam Line Break Accident - Parameters Tabulated for Postulated Accident Analyses................................................. 15.6-18 15.6-6      Steam Line Break Accident Activity Release to Environment (Curies) .......................................................... 15.6-20 15.6-7      Steam Line Break Accident Radiological Effects of a Puff Release ... 15.6-21 LDCN-05-009                                  15-xxii

COLUMBIA GENERATING STATION                                     Amendment 59 FINAL SAFETY ANALYSIS REPORT                                   December 2007 Chapter 15 ACCIDENT ANALYSES LIST OF TABLES (Continued)
Number                                    Title                                                Page 15.6-8      Loss-of-Coolant Accident - Parameters Tabulated for Postulated Accident Analysis ................................................. 15.6-22 15.6-9      Loss-of-Coolant Accident Primary Containment Activity (Curies) .... 15.6-25 15.6-10     Loss-of-Coolant Accident Secondary Containment Activity (Curies) - 20 Minute Drawdown .................................. 15.6-26 15.6-11     Loss-of-Coolant Accident Activity Released to the Environment (Curies) - 20 Minute Drawdown ............................ 15.6-27 15.6-12     Loss-of-Coolant Accident (Design Basis Analysis)
Radiological Effects ............................................................ 15.6-28 15.6-13     Sequence of Events for Feedwater Line Break Outside Containment...................................................................... 15.6-29 15.6-14     Feedwater Line Break Accident - Parameters Tabulated for Postulated Accident Analysis............................................. 15.6-30 15.6-15     Feedwater Line Break Accident Activity Release to Environment (Curies) .......................................................... 15.6-32 15.6-16     Feedwater Line Break Accident Biological Effects of a Puff Release...................................................................... 15.6-33 15.7-1      Liquid Radwaste Tanks Failure - Parameters and Concentrations ..... 15.7-9 15.7-2      Fuel Handling Accident Parameters Tabulated for Postulated Accident Analysis ................................................. 15.7-10 15.7-3      Fuel Handling Accident Activity Airborne in Secondary Containment (Curies)........................................................... 15.7-12 15.7-4      Fuel Handling Accident Activity Released to the Environment (Curies) .......................................................... 15.7-13 LDCN-05-009                                 15-xxiii

COLUMBIA GENERATING STATION                                      Amendment 63 FINAL SAFETY ANALYSIS REPORT                                     December 2015 Chapter 15 ACCIDENT ANALYSES LIST OF TABLES (Continued)
Number                                      Title                                                Page 15.7-5      Fuel Handling Accident (Design Basis Analysis)
Radiological Effects ............................................................ 15.7-14 15.8-1      Anticipated Transients Without Scram Analysis Initial Conditions .... 15.8-17 15.8-1A     Anticipated Transients Without Scram Analysis for MELLLA Initial Conditions and Equipment Performance Characteristics ................. 15.8-17a 15.8-2      Anticipated Transients Without Scram Analysis Equipment Performance Characteristics .................................................. 15.8-18 15.8-3      Summary of Anticipated Transients Without Scram Results ............ 15.8-19 15.8-4      Sequence of Events for Loss of Feedwater ................................. 15.8-20 15.8-5      Sequence of Events for Main Steam Line Isolation Valve Closure (Long Term Transient) .............................................. 15.8-21 15.8-6      Deleted ............................................................................ 15.8-22 15.8-7      Sequence of Events for Inadvertent Open Relief Valve .................. 15.8-23 15.8-8      Sequence of Events for Pressure Regulator Failure Open (Long Term Transient) ......................................................... 15.8-24 LDCN-10-004                                    15-xxiv

COLUMBIA GENERATING STATION                     Amendment 60 FINAL SAFETY ANALYSIS REPORT                   December 2009 Chapter 15 ACCIDENT ANALYSES LIST OF FIGURES Number                                  Title 15.0-1      Scram Position and Reactivity Characteristics 15.0-2      Illustration of Single Recirculation Loop Operation Flows 15.1-1      Feedwater Controller Failure, Maximum Demand 15.1-2      Pressure Regulator Failure - Open at 106.2% Uprated Power, 100% Flow (Sheets 1 through 11) 15.1-3      Feedwater Controller Failure, Maximum Demand, EOC RPT OOS, Single Loop Operation and 75% Uprated Power, 57% Flow (Sheets 1 through 4) 15.2-1      Pressure Regulatory Failure - Down Scale Failure at 104.1% Uprated Power, 106% Flow 15.2-2.1    Generator Load Rejection with Bypass On - Original Rated Power (Sheet 1) 15.2-2.2    Generator Load Rejection with BP Failure 15.2-3      Turbine Trip, Trip Scram, Bypass, and RPT - On 15.2-4      Turbine Trip with Bypass Failure 15.2-5      Main Steam Line Isolation Valve Closure at 106.2% Uprated Power, 100% Rated Flow 15.2-6      Loss of Condenser Vacuum at 104.1% Uprated Power, 100% Rated Flow 15.2-7      Loss of Auxiliary Power Transformers - 106.2% Uprated Power, 100% Rated Flow 15.2-8      Loss of All Grid Connections - 104.1% Uprated Power, 100% Rated Flow 15.2-9      Loss of All Feedwater Flow - 106.2% Uprated Power, 100% Rated Flow LDCN-08-035                                15-xxv

COLUMBIA GENERATING STATION                       Amendment 60 FINAL SAFETY ANALYSIS REPORT                     December 2009 Chapter 15 ACCIDENT ANALYSES LIST OF FIGURES (Continued)
Number                            Title 15.2-10 Automatic Depressurization System/Residual Heat Removal Cooling Loops (Sheets 1 and 2) 15.2-11 Summary of Paths Available to Achieve Cold Shutdown 15.2-12 Activity C1 Alternate Shutdown Cooling Path Utilizing Residual Heat Removal Loop B 15.2-13 Residual Heat Removal Loop C 15.2-14 Residual Heat Removal Loop A (B) (Suppression Pool Cooling/Rated Pump Flow Test Mode) 15.2-15 Activity C2 Alternate Shutdown Cooling Path Utilizing Residual Heat Removal Loop A 15.2-16 Vessel Temperature and Pressure Versus Time (Activity C1.b.1 or C2) 15.2-17 Vessel Temperature and Pressure Versus Time (Activity C1.b.2) 15.2-18 Suppression Pool Temperature Versus Time (with 87&deg;F Service Water Temperature) (Activity C1.b.1 or C.2) 15.2-19 Suppression Pool Temperature Versus Time (with 87&deg;F Service Water Temperature) (Activity C1.b.2) 15.3-1  One Recirculation Pump Trip at 106.2% Uprated Power, 100% Flow (Sheets 1 through 5) 15.3-2  Two Recirculation Pump Trip at 106.2% Uprated Power, 100% Flow (Sheets 1 through 5) 15.3-3  Recirculation Flow Control Failure - Decreasing Flow in One Loop at 106.2% Uprated Power, 100% Flow (Sheets 1 through 5) 15-xxvi

COLUMBIA GENERATING STATION                        Amendment 60 FINAL SAFETY ANALYSIS REPORT                      December 2009 Chapter 15 ACCIDENT ANALYSES LIST OF FIGURES (Continued)
Number                                 Title 15.3-4      Recirculation Flow Control Failure - Decreasing Flow in Two Loops, (5%/Sec Ramp) at 106.2% Uprated Power, 100% Flow (Sheets 1 through 5) 15.3-5      Recirculation Pump Seizure at 106% Uprated Power, 100% Flow (Sheets 1 through 5) 15.3-6      SLO Recirculation Pump Seizure Results 15.4-1      Abnormal Startup of an Idle Recirculation Loop at 57.9% Uprated Power, 34.1% Flow (Sheets 1 through 5) 15.4-2      Leakage Path Model for Rod Drop Accident (Original Rated Power) 15.5-1      Inadvertent Start of High-Pressure Core Spray Pump at 102% Uprated Power, 88% Flow 15.6-1      Leakage Path for Instrument Line Break 15.6-2      Steam Flow Schematic for Steam Break Outside Containment 15.6-3      Leakage Path for LOCA 15.6-4      Leakage Path for Feedwater Line Break Outside Containment 15.7-1      Leakage Path for Fuel Handling Accident 15.8-1      Loss of Feedwater Event (Sheets 1 through 5) 15.8-2      Main Steam Isolation Valve Closure Event (Sheets 1 through 5) 15.8-3      Main Steam Isolation Valve Closure Event with Four SRVs Out-of-Service (Sheets 1 through 5) 15.8-4      Inadvertent Opening of Relief Valve Event (Sheets 1 through 5) 15.8-5      Pressure Regulator Failure - Open Event (Sheets 1 through 5)
LDCN-08-035                              15-xxvii

COLUMBIA GENERATING STATION                            Amendment 63 FINAL SAFETY ANALYSIS REPORT                           December 2015 Chapter 15 ACCIDENT ANALYSES 15.0    GENERAL This chapter discusses the effects of anticipated process disturbances and postulated component failures, their consequences, and the capabilities built into the plant to control or accommodate such failures and events. The analyses have been reviewed and revised, as needed, for the:
Reactor power uprate Installation of the adjustable speed drive for the reactor recirculation pumps Implementation of an alternative source term APRM/RBM Technical Specification (ARTS) improvement program Maximum Extended Load Line Limit Analysis (MELLLA)
Cycle specific changes These changes to the plant licensing and design basis and their impact are discussed in this chapter.
The scope of the situations analyzed includes anticipated (expected) operational occurrences, off-design abnormal (unexpected) transients that induce system operating condition disturbances, postulated accidents of low probability, and hypothetical events of extremely low probability. For each reload, the events are evaluated by the fuel vendor(s). The events identified as limiting during the evaluation are analyzed and the sections are revised.
The plant was originally licensed at 3323 MWt. In 1995, an amendment to the plant Operating License authorized an increase in power to 3486 MWt. The power uprate analysis was performed in accordance with the NRC-approved General Electric Company (GE) generic power uprate program for boiling water reactors (BWRs).
The postulated events in this chapter have been analyzed for power uprate conditions. The only exceptions to using uprated power are some non-limiting single loop operation (SLO) transients that were not reanalyzed as part of the GE power uprate transient analysis. Their text and figures are clearly marked with ORIGINAL POWER designation. Limiting events in terms of setting the fuel operating limits (e.g., Loss of Feedwater Heating, Generator Load Rejection Without Bypass) are reanalyzed on a cycle specific basis and therefore, may include fuel vendor results and references.
The events in this chapter have been analyzed for application of the adjustable speed drives (ASD) in place of the former reactor recirculation control system that used flow control valves (FCV). The uprated power for Columbia Generating Station is 3486 MWt which is 4.9%
higher than the original licensed power of 3323 MWt. All transient initial conditions are specified in Table 15.0-2, 15.0-2A, 15.0-2B or the individual transient event description sections. Several performance improvement packages have been included in the analysis:
LDCN-10-004                                     15.0-1

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015
: 1.      Final Feedwater Temperature Reduction (FFWTR) and Feedwater Heaters Out-Of-Service (FWHOOS) - Analyses were performed at a reduced feedwater temperature at rated thermal power for operations at end-of-cycle and during the cycle for limiting transients.
: 2.      Increased Core Flow (ICF) - Increased core flow allows for operation at 106% of the rated core flow. The limiting transients were performed for the end-of-cycle with control rods fully withdrawn. This envelopes the operation at increased core flow condition throughout the cycle.
3a. Extended Load Line Limit Analysis (ELLLA) - The consequences of the transients were evaluated to determine if operating limit adjustments are necessary for operation in the extended operating domain and compared with the evaluation at rated thermal power and increased core flow region. This comparison ensures bounding of the results at the extended operating domain.
3b. Maximum Extended Load Line Limit Analysis (MELLLA) - The consequences of the transients were evaluated to determine if operating limit adjustments are necessary for operation in the maximum extended operating domain and compared with the evaluation at rated thermal power and increased core flow region. This comparison ensures bounding of the results at the maximum extended operating domain.
: 4.      Single Loop Operation (SLO) - Limiting transients were re-analyzed for operation at SLO. Using adjustable speed drives (ASD), GE determined the maximum active loops recirculation flow at 105% of rated pump speed with resultant analyzed power and core flow conditions of 75% UP and 57% of rated core flow for SLO. Prior to power uprate, a comprehensive SLO analysis was performed. For non-limiting events, this analysis has been retained for completeness and historical purposes. These analyses are clearly marked with ORIGINAL POWER designation.
: 5.      End-of-Cycle RPT Out-of-Service (RPT OOS) - The recirculation pump trip (RPT) mitigates several transients that are more severe at end-of-cycle. The limiting transients were re-analyzed with RPT OOS at various power/flow conditions.
: 6.      Turbine Bypass Out-of-Service - Limiting transient events have been analyzed with turbine bypass valves out-of-service at limiting power and flow conditions.
: 7.      Average Power Range Monitor, Rod Block Monitor Technical Specifications (ARTS) -
The ARTS improvement program improves fuel thermal limits protection at off-rated conditions with a more rigorous application of power and flow dependent Minimum Critical Power Ratio (MCPR) and Linear Heat Generation Rate (LHGR) limits. The ARTS improvement program eliminates the Technical Specification requirement for total peaking factor setdown at off-rated conditions. The ARTS program includes modification of the Rod Block Monitor (RBM), from flow-based to power-based LDCN-10-004                                    15.0-2

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                         December 2015 setpoints, to improve the rod movement flexibility at less than rated power conditions, and establish an optimized configuration that improves the system response with respect to bundle power.
Additional updates address the implementation of the use of alternative source terms (AST) as described in the Regulatory Guide 1.183, July 2000, Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors. This methodology is based on the advances that have been made in understanding the timing, magnitude, and the chemical form of fission product releases from severe nuclear power plant accidents. The accidents that were reanalyzed by Energy Northwest with the AST:
Loss of coolant accident (LOCA)
Fuel handling accident (FHA)
Control rod drop accident (CRDA)
Main steam line break, outside containment, accident (MSLB)
The radiological consequences of these accidents were determined based on AST approved for use under 10 CFR 50.67. In accordance with the guidance provided in Regulatory Guide 1.183, the licensing and design basis are revised to reflect the application of full scope AST methodology (with the exception that the TID-14844 will continue to be used as the basis for equipment qualification (EQ) and radiation zone maps/shielding calculations). The accidents analyzed as part of the implementation of AST are subject to the limits specified in 10 CFR 50.67 and guidelines of Regulatory Guide 1.183.
15.0.1      ANALYTICAL OBJECTIVE The spectrum of postulated initiating events is divided into categories based on the type of disturbance and the expected frequency of the initiating occurrence. The limiting events in each combination of category and frequency are quantitatively analyzed.
15.0.2      ANALYTICAL CATEGORIES Transient and accident events contained in this report are provided in individual categories as specified by Regulatory Guide 1.70, Revision 2. The results of the events are summarized in Table 15.0-1. Events evaluated are assigned to one of the following applicable categories:
: a. Decrease in reactor coolant temperature:
Reactor vessel water (moderator) temperature reduction results in an increase in core reactivity. This could lead to fuel-cladding damage.
: b. Increase in reactor pressure:
Nuclear system pressure increases threaten to rupture the reactor coolant pressure boundary (RCPB). Increasing pressure also collapses the voids in the LDCN-10-004                                  15.0-3

COLUMBIA GENERATING STATION                          Amendment 63 FINAL SAFETY ANALYSIS REPORT                         December 2015 core-moderator, thereby increasing core reactivity and power level that could threaten fuel cladding due to overheating.
: c. Decrease in reactor coolant system flow rate:
A reduction in the core coolant flow rate could overheat the cladding as the coolant becomes unable to adequately remove the heat generated by the fuel.
: d. Reactivity and power distribution anomalies:
Transient events included in this category are those that could cause rapid increases in power due to increased core flow disturbance events. Increased core flow reduces the void content of the moderator increasing core reactivity and power level.
: e. Increase in reactor coolant inventory:
Increasing coolant inventory could result in excessive moisture carryover to components such as the main turbine, feedwater turbines, etc.
: f. Decrease in reactor coolant inventory:
Reductions in coolant inventory could threaten the fuel as the coolant becomes less able to remove heat generated in the core.
: g. Radioactive release from subsystems and components:
Loss of integrity of a radioactive containment component is postulated.
: h. Anticipated transients without scram:
To determine the capability of plant design to accommodate an extremely low probability event, a multi-system maloperation situation is postulated.
15.0.2.1     Single Loop Operation (SLO)
Operation with one recirculation loop results in a maximum power output that is 20% to 30% below that which is attainable for two-pump operation. Therefore, the consequences of abnormal operation transients from one-loop operation will be considerably less severe than those analyzed from a two-loop operational mode because of the associated reduction in operation power level.
15.0-4

COLUMBIA GENERATING STATION                            Amendment 63 FINAL SAFETY ANALYSIS REPORT                           December 2015 For pressurization, flow decrease, and cold water increase transients, results presented bound both the thermal and overpressure consequences of one-loop operation. The consequences of flow decrease transients are also bounded by the full power analysis. A single pump trip from one-loop operation is less severe than a two-pump trip from full power because of the reduced initial power level.
Cold water increase transients can result from either recirculation flow controller failure or introduction of colder water into the reactor vessel by events such as loss of feedwater heater.
For the former, the flow-dependent MCPR values are derived assuming both recirculation loop controllers fail. This condition produces the maximum possible power increase and, hence, maximum MCPR for transients initiated from less than rated power and flow. When operating with only one recirculation loop, the flow and power increase associated with this failure with only one recirculation loop will be less than that associated with both loops; therefore, the MCPR values derived with the two-pump assumption are conservative for SLO.
The latter event, loss of feedwater heating, is generally the most severe cold water increase event with respect to increase in core power. This event is caused by positive reactivity insertion from core inlet subcooling and it is relatively insensitive to initial power level.
A generic statistical loss of feedwater heater analysis using different initial power levels and other core design parameters concluded one-pump operation with lower initial power level is conservatively bounded by the full power two-pump analysis. Inadvertent restart of the idle recirculation pump has been analyzed and is applicable for SLO.
From the above discussions, the transient consequence from SLO is bounded by previously submitted full power analyses. The maximum power level that can be attained with one-loop operation is only restricted by the MCPR and overpressure limits established from a full-power analysis.
The following most limiting transients of coldwater increase, pressurization and flow decrease events are analyzed for SLO and the results are shown in Table 15.0-1A:
: a. Feedwater flow controller failure (maximum demand),
: b. Generator load rejection with bypass failure, and
: c. One pump seizure accident.
LDCN-10-004                                   15.0-4a

COLUMBIA GENERATING STATION                          Amendment 63 FINAL SAFETY ANALYSIS REPORT                         December 2015 15.0.3      EVENT EVALUATION 15.0.3.1       Identification of Causes and Frequency Classification Situations and causes that lead to the initiating event analyzed are described within the analytical categories. The frequency of occurrence of each event is summarized based on operating plant history for the transient event. Events for which inconclusive data exist are discussed separately within each event section.
Each initiating event within the major groups is assigned to one of the following frequency groups:
: a.      Incidents of moderate frequency - these are incidents that may occur during a calendar year to once per lifetime. This event is referred to as an anticipated (expected) operational transient.
: b.      Infrequent incidents - these are incidents that may occur during the life of the particular plant. This event is referred to as an abnormal (unexpected) operational transient.
: c.      Limiting faults - these are occurrences that are not expected to occur but are postulated because their consequences may result in the release of significant amounts of radioactive material. This event is referred to as a design basis (postulated) accident.
15.0-5

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 15.0.3.1.1    Unacceptable Results for Incidents of Moderate Frequency [Anticipated (Expected) Operational Transients]
The following are unacceptable safety results for incidents of moderate frequency:
: a. Release of radioactive material to the environs that exceeds the limits of 10 CFR 20,
: b. Reactor operation induced fuel cladding failure,
: c. Nuclear system stresses in excess of that allowed for the transient classification by applicable industry codes, and
: d. Containment stresses in excess of that allowed for the transient classification by applicable industry codes.
15.0.3.1.2    Unacceptable Results for Infrequent Incidents [Abnormal (Unexpected)
Operational Transients]
The following are unacceptable safety results for infrequent incidents:
: a. Release of radioactivity that results in dose consequences that exceed a small fraction of 10 CFR 50.67 values,
: b. Fuel damage that would preclude resumption of normal operation after a normal restart,
: c. Generation of a condition that results in consequential loss of function of the reactor coolant system, and
: d. Generation of a condition that results in a consequential loss of function of a necessary containment barrier.
15.0.3.1.3    Unacceptable Results for Limiting Faults [Design-Basis (Postulated)
Accidents]
The following are unacceptable safety results for limiting faults:
: a. Radioactive material release that results in dose consequences that exceed the requirements of 10 CFR 50.67, 15.0-6

COLUMBIA GENERATING STATION                              Amendment 60 FINAL SAFETY ANALYSIS REPORT                            December 2009
: b.      Failure of fuel cladding that would cause changes in core geometry such that core cooling would be inhibited,
: c.      Nuclear system stresses in excess of those allowed for the accident classification by applicable industry codes,
: d.      Containment stresses in excess of those allowed for the accident classification by applicable industry codes when containment is required, and
: e.      Radiation exposure to plant operations personnel in the main control room in excess of 5 rem total effective dose equivalent (TEDE) for the duration of the accident.
15.0.3.2       Sequence of Events and Systems Operation Each transient or accident is discussed and evaluated in terms of
: a.      A step-by-step sequence of events from initiation to final stabilized condition (e.g., termination of the accident),
: b.      The extent to which normally operating plant instrumentation and controls are assumed to function,
: c.      The extent to which plant and reactor protection systems are required to function,
: d.      The credit taken for the functioning of normally operating plant systems,
: e.      The operation of engineered safety systems that is required, and
: f.      The effect of a single failure or an operator error on the event.
The transient or accident discussion is specific to the event in that it is limited to the events and system operations related to the reactor core performance and postulated damage. In general, the step-by-step description ends when the analysis has demonstrated that the core performance results are within established limits. The stabilized condition does not imply that all actions to stabilize plant parameters or to recover from the transient or accident have been completed by plant personnel. In the stabilized condition, either the core has demonstrated compliance with requirements or the postulated or deterministic damage is complete. At this point, the transient or accident is terminated. After termination of the event, the operator actions or system operations are not event specific. The required actions and expected system operations, needed to establish cold shutdown or to initiate recovery actions, are symptom based and described in 15.0-7

COLUMBIA GENERATING STATION                           Amendment 60 FINAL SAFETY ANALYSIS REPORT                          December 2009 procedures. The events associated with a radiological release and radiological consequences of the transient or accident are also discussed.
15.0.3.2.1      Single Failures or Operator Errors 15.0.3.2.1.1 General. The events considered in this section were evaluated and are provided in this chapter in accordance with Regulatory 1.70, Revision 2.
15.0.3.2.1.2 Initiating Event Analysis.
: a.      The undesired opening or closing of any single valve (a check valve is not assumed to close against normal flow),
: b.      The undesired starting or stopping of any single component,
: c.      The malfunction or maloperation of any single control device,
: d.      Any single electrical component failure, or
: e.      Any single operator error.
Operator error is defined as an active deviation from written operating procedures or nuclear plant standard operating practices. The set of actions is limited as follows:
: a.      Those actions that could be performed by one person,
: b.      Those actions that would have constituted a correct procedure had the initial decision been correct, and
: c.      Those actions that are subsequent to the initial operator error and have an effect on the designed operation of the plant, but are not necessarily directly related to the operator error.
Examples of single operator errors are as follows:
: a.      An increase in power above the established flow control power limits by control rod withdrawal in the specified sequences,
: b.      The selection and complete withdrawal of a single control rod out of sequence,
: c.      An incorrect calibration of an average power range monitor (APRM), and 15.0-8

COLUMBIA GENERATING STATION                            Amendment 63 FINAL SAFETY ANALYSIS REPORT                           December 2015
: d.      Manual isolation of the main steam lines as a result of operator misinterpretation of an alarm or indication.
15.0.3.2.1.3 Single Active Component Failure or Single Operator Error Analysis.
: a.      The undesired action or maloperation of a single active component, or
: b.      Any single operator error where operator errors are defined as in Section 15.0.3.2.1.2.
15.0.3.3        Core and System Performance Fuel thermal and hydraulic design are described in Section 4.4.
The fuel cladding integrity safety limit is set so that no fuel damage is calculated to occur if the limit is not violated. Exceeding unacceptable results criteria for fuel cladding integrity for anticipated operational transients is avoided by meeting the following criteria provided in the NRC Standard Review Plan (NUREG-0800) Section 4.4:
: a.      The expected number of fuel rods in boiling transition should not exceed 0.1%
of the fuel rods in the core. This criterion is met by ensuring that the MCPR for any anticipated operational transient is calculated to be not less than the safety limit MCPR values given in the cycle-specific Core Operating Limits Report (COLR).
: b.      No fuel centerline melting nor uniform total cladding strain in excess of 1% will occur. This criterion is met by compliance with the operating limits for LHGR given in the cycle-specific COLR.
The operating limit for MCPR is developed as follows:
The MCPR calculated during the transient is compared to the safety limit. The MCPR safety limit is established using the critical power evaluation methods and includes consideration of the operating domain and manufacturing uncertainties and a conservative core power distribution as inputs. The operating limit MCPR is established such that the transient CPR for the dynamic anticipated operational occurrences and quasi steady-state anticipated operational occurrences are included in the evaluation. Thus, the operating limit MCPR is specified to maintain an adequate margin to boiling transition.
The MCPR operating limit is the maximum of (a) the applicable exposure dependent, full power and full flow MCPR limit, (b) the applicable exposure and power dependent MCPR limit, and (c) the flow dependent MCPR limit as specified in the cycle-specific COLR. This stipulation ensures that the safety limit MCPR will not be violated throughout the CGS LDCN-10-004                                     15.0-9

COLUMBIA GENERATING STATION                            Amendment 63 FINAL SAFETY ANALYSIS REPORT                           December 2015 operating regime. Full power MCPR limits are specified to define operating limits at rated power and a range of flow conditions that support extended load line operation. Power dependent MCPR limits are specified to define operating limits at other than rated power conditions. A flow dependent MCPR limit is specified to define operating limits at other than rated flow conditions.
With implementation of ARTS, the APRM total peaking factor setdown requirement is eliminated and power-dependent LHGR limits are substituted to ensure adherence to the fuel thermal mechanical design bases. Flow dependent LHGR limits are added to ensure adherence to all fuel thermal mechanical design bases during recirculation flow increase events.
ELLLA operation extends the power and flow operating regime for CGS above the rated rod line for SLO and two-loop recirculation pump operation (TLO). MELLLA further extends the power and flow operating regime but only for TLO. The COLR defines the ELLLA boundary for SLO and MELLLA boundary for TLO. The cycle specific Supplemental Reload Licensing Report (Reference 15.0-1) documents the reload analyses.
The CGS cycle-specific COLR provides the average planar linear heat generation rate (APLHGR) limits, the MCPR limits, and the linear heat generation rate (LHGR) limits as required by the Technical Specifications.
15.0.3.3.1        Mathematical Model Unless otherwise stated in the Mathematical Model description for the event being discussed, the following mathematical model was used to perform the Chapter 15 transient analyses.
Transients are analyzed using the transient analysis models described in Reference 15.0-5.
The three-dimensional transient analysis model TRACG was used to analyze transients involving significant reactor pressurization (i.e., limiting events). The point-kinetics transient analysis model REDY and the one-dimensional transient analysis model ODYN were used for transients not involving significant reactor pressurization (i.e., non-limiting events). The transient analysis model determines the transient pressure, power, heat flux, and average core flow which are required as input to both the hot channel analysis and to the transient critical power methodology. The TRACG transient analysis model also calculates the transient peak reactor vessel pressure to demonstrate conformance to the reactor pressure vessel safety limit, which is based on the reactor pressure vessel design pressure.
TRACG is a best-estimate code for analysis of BWR transients (Reference 15.0-5). It is based on a multi-dimensional, two-fluid model for the reactor thermal-hydraulics, and a three-dimensional neutron kinetics model for the reactor core. TRACG has a modular structure and flexible geometry capability. It contains a set of basic thermal-hydraulic components, such as vessel, channel, pipe, and tee components which are used as the building blocks to construct the system simulation. In addition to the basic thermal-hydraulic component models, TRACG contains a set of component models for the recirculation pumps, jet pumps, fuel channels, LDCN-10-004, 15-011                           15.0-10

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                         December 2015 steam separators, and dryers. TRACG also contains a control system model capable of simulating major BWR control systems.
The input data to the transient analysis model come from two sources: (1) the plant model or base deck, and (2) the BWR three-dimensional simulator PANACEA. The plant model provides the necessary input data for the simulation of the plant, including the plant and control systems performance characteristics. The BWR three-dimensional simulator supplies the core state, the neutron kinetics cross sections, and other data necessary to characterize the reactor core.
The TRACG analysis process begins by performing channel grouping and selecting limiting (hot) channels from the PANACEA wrapup file. After updating the TRACG Basedeck with any cycle specific OPL-3 changes, a TRACG Steady-State Initialization case, restarting from the PANACEA wrapup, is then run to establish initial conditions for the subsequent transient case. The Steady-State Initialization includes key parameters such as core power, core flow, vessel steam flow, core inlet subcooling, reactor dome pressure, vessel narrow range water level, steamline pressure drop, and turbine control valve initial position. These TRACG calculated steady state parameters are then compared with the corresponding PANACEA heat balance value or the cycle specific OPL-3 form to confirm that the steady state results are within methodology defined acceptance criteria. A TRACG Null Transient case is then run to establish the TRACG flux convergence criterion. Finally, the TRACG transient cases are run to calculate the limiting (hot) channel CPR/ICPR, pressure margins, and Limiting (hot) channel power and nodal integrated powers.
The GESAM SLMCPR calculational process, which includes the GEXL correlation, is then used to calculate the OLMCPR, based on plant specific transient bias and uncertainty inputs, the cycle specific SLMCPR, and the TRACG calculated CPR/ICPR. The limiting hot channel power and nodal integrated powers are then normalized and used for input to perform the plant/cycle/event specific fuel rod thermal/mechanical evaluation, which is a separate calculation.
The above mathematical models describe the models used in the introduction of GNF2 fuel.
Cycle specific analyses are performed using vendor specific models for the vendor supplying the reload fuel for the current cycle as described elsewhere in this chapter.
15.0.3.3.2      Input Parameters and Initial Conditions for Analyzed Events This section discusses the important input parameters used in the analysis for the event discussed. In some cases, the discussion references Table 15.0-2 (or 2A or 2B).
15.0.3.3.3      Consideration of Uncertainties Except for total core flow and TIP reading, the uncertainties used in the statistical analysis to determine the MCPR fuel cladding integrity safety limit are not dependent on whether coolant flow is provided by one or two recirculation pumps. Uncertainties used in the two-loop LDCN-15-011                                   15.0-11

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                         December 2015 operation analysis are documented in the FSAR. A 6% core flow measurement uncertainty has been established for single loop operation (compared to 2.5% for two-loop operation). This value conservatively reflects the one standard deviation (one sigma) accuracy of the core flow measurement system documented in Reference 15.0-2. In SLO, measurement and prediction uncertainties for radial power distribution and axial power distribution also increase. In the current methodology, axial power uncertainty is not an important parameter. The net effect of these revised uncertainties is an incremental increase in the required MCPR fuel cladding integrity safety limit. The MCPR safety limit for SLO is given in the cycle specific COLR.
15.0.3.3.3.1 Core Flow Uncertainty Analysis The uncertainty analysis procedure used to establish the core flow uncertainty for one-pump operation is essentially the same as for two-pump operation, with some exceptions. The core flow uncertainty analysis is described in Reference 15.0-2. The analysis of one-pump core flow uncertainty is summarized below.
For SLO, the total core flow can be expressed as follows (see Figure 15.0-2):
WC  WA  WI where:
WC  total core flow WA  active loop flow, and WI  inactive loop (true) flow.
By applying the propagation of errors method to the above equation, the variance of the total flow uncertainty can be approximated by:
2                          2 2W   2Wsys 1   2 W          a    2            C2 C
1  a A rand 1  a WI rand where:
W         = uncertainty of total core flow; C
Wsys     = uncertainty systematic to both loops; W         = random uncertainty of active loop only; A rand 15.0-12

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                       December 2015 WI         = random uncertainty of inactive loop only; rand C           = uncertainty of C coefficient; and a       = ratio of inactive loop flow (WI) to active loop flow (WA).
From an uncertainty analysis, the conservative, bounding values of Wsys ,  W       ,  WI      , and  C A rand        rand are 1.6%, 2.6%, 3.5% and 2.8% respectively. Based on the above uncertainties and a bounding value of 0.36* for a, the variance of the total flow uncertainty is approximately:
2                         2 2W  1.6 C
2           1 1  0.36 2.6 2 1  0.36 0.36  3.5 2  2.8 2  5.0% 2 When the effect of 4.1% core bypass flow split uncertainty at 12% (bounding case) bypass flow fraction is added to the above total core flow uncertainty, the active coolant flow uncertainty is:
2 2                                       0.12  4.1% 2  51 active coolant   5.0%                                . % 2 2
1  0.12 which is less than the 6% core flow uncertainty assumed in the statistical analysis.
In summary, core flow during one-pump operation is measured in a conservative way and its uncertainty has been conservatively evaluated.
15.0.3.3.4         Results This section discusses the results, in terms of core and system performance, of the event analyzed. The COLR provides operating limits that are the results of analytical evaluations that impact core operating parameters for the current cycle. In addition, critical parameters for the complete set of transients analyzed are shown in Table 15.0-1. From the data in Table 15.0-1, an evaluation of the limiting event for that particular category and parameter can This flow split ratio varies from about 0.13 to 0.36. The 0.36 value is a conservative bounding value. The analytical expected value of the flow split ratio for CGS is 0.23.
15.0-13

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                         December 2015 be made. The limiting events are reanalyzed for the current operating cycle. Table 15.0-3 provides a summary of accidents that may have radiological consequences.
15.0.3.4       Barrier Performance This section addresses the performance of the RCPB and the containment system during transients and accidents.
During transients that occur with no release of coolant to the containment, only RCPB performance is considered. If release to the containment occurs as in the case of limiting faults, then challenges to the containment are evaluated as well.
Piping systems within the secondary containment structure (i.e., the reactor building) have been analyzed for pipe break effects including jet impingement, jet reaction, pipe whip, and subcompartment pressurization. Where necessary, these loads were included in the design of the structure to ensure that the secondary containment can perform its required functions as defined in Section 6.2.3.
15.0.3.5       Radiological Consequences This section addresses the radiological release consequences during the incidents of moderate frequency (anticipated operational transients), infrequent incidents (abnormal operational transients), and limiting faults (design basis accidents [DBA]) events. For all events where consequences are limiting a detailed quantitative evaluation is presented. For nonlimiting events, a qualitative evaluation is presented or the results are referenced from a more limiting or enveloping case or event.
For limiting faults (DBA), conservative assumptions considered to be acceptable to the NRC for the purpose of worst case bounding of the event and determining the adequacy of the plant design to meet 10 CFR 50.67 requirements are assumed. This is referred to as the design basis analysis.
The atmospheric dispersion coefficients are presented in Tables 15.0-4 and 15.0-5. Reference will be made to these tables in the discussion of the analyses.
15.

==0.4      REFERENCES==

15.0-1          Supplemental Reload Licensing Report for Columbia (most recent version referenced in COLR).
15.0-2          General Electric Company, General Electric BWR Thermal Analysis Basis (GETAB); Data, Correlation, and Design Application, NEDO-10958-A, January 1977.
15.0-14

COLUMBIA GENERATING STATION                      Amendment 63 FINAL SAFETY ANALYSIS REPORT                     December 2015 15.0-3      GE Nuclear Energy, WNP-2 Power Uprate Transient Analysis Task Report, GE-NE-208-08-0393, Revision 0, September 1993 (Proprietary).
15.0-4      GE-Hitachi Report, Evaluation of Steam Flow Induced Error Impact on the L3 Setpoint Analysis Limit, GEH-NE-0000-0077-4603, December 2007.
15.0-5      General Electric Company, General Electric Standard Application for Reactor Fuel, NEDE-24011-P-A, and supplement for United States, NEDE-24011-P-A-US (most recent approved version referenced in COLR).
LDCN-15-011                             15.0-15

LDCN-15-011 Table 15.0-1 Results Summary of Transient Events Applicable to Columbia Generating Stationa Maximum     Maximum    Maximum      Maximum Core Maximum          Dome        Vessel    Steam Line   Average Surface Paragraph    Figure                                                   Neutron Flux     Pressure    Pressure    Pressure    Heat Flux (% of                Frequency I.D.       I.D.                     Description                     (%NBR)           (psig)      (psig)       (psig)        Initial)       DCPRb,c,e   Category 15.1                   DECREASE IN REACTOR COOLANT TEMPERATURE COLUMBIA GENERATING STATION 15.1.1                 Loss of Feedwater Heating, Manual Flow                                                                                 0.11           (d)
Control 15.1.2       15.1-1    Feedwater Controller Failure, Max Demand        314            1183         1210                                       0.30k          (d) 15.1.3       15.1-2    Pressure Regulator Fail-Open                    131            1151         1172        1151         100               <0.01 15.1.4                 Inadvertent Opening of Safety or Relief Valve   104            1020         1061        1012         100               <0.01          (d) 15.1.6                 RHR Shutdown Cooling Malfunction                See text                                                                              (d)
Decreasing Temperature 15.0-17 FINAL SAFETY ANALYSIS REPORT 15.2                   INCREASE IN REACTOR PRESSURE 15.2.1                 Pressure Regulator Fail-Closed                  163            1188         1220        1187         106               n/a            (d) 15.2.2       15.2-1    Generator, Load Rejection, Bypass-Onf           See text                                                                              (d) k 15.2.2       15.2-2    Generator Load Rejection, Bypass-Off            330            1244         1270                                       0.32           (d) 15.2.3       15.2-3    Turbine Trip, Bypass-Onf                        See text                                                                              (d) 15.2.3       15.2-4    Turbine Trip, Bypass-Off                        278            1238         1260        1235         111               0.30           (d) 15.2.4       15.2-5    Inadvertent MSIV Closure                        206            1200         1234        1198         100               0.022          (d) 15.2.5       15.2-6    Loss of Condenser Vacuum                        256            1173         1199        1166         111               0.12           (d) 15.2.6       15.2-7    Loss of Auxiliary Power Transformers            106h           1169         1185        1166         100               <0.01          (d) 15.2.6       15.2-8    Loss of All Grid Connections                    196            1173         1196        1166         106               0.079          (d) 15.2.7       15.2-9    Loss of all Feedwater Flow                      106h           1142         1152        1142         100               <0.01          (d) 15.2.8                 Feedwater Piping Break                          See Section 15.6.6 15.2.9                 Failure of RHR Shutdown Cooling                 See text Amendment 63 December 2015

LDCN-15-011 Table 15.0-1 Results Summary of Transient Events Applicable to Columbia Generating Stationa (Continued)
Maximum         Maximum          Maximum       Maximum Core Maximum           Dome            Vessel          Steam Line    Average Surface Paragraph    Figure                                                 Neutron Flux      Pressure        Pressure          Pressure     Heat Flux (% of                 Frequency I.D.       I.D.                      Description                  (%NBR)            (psig)          (psig)             (psig)         Initial)        DCPRb,c,e   Category 15.3                   DECREASE IN REACTOR COOLANT SYSTEM FLOW RATE 15.3.1       15.3-1    Trip of One Recirculation Pump Motor          106h            1020             1059              1012         100                <0.01           (d)
COLUMBIA GENERATING STATION 15.3.1       15.3-2    Trip of Both Recirculation Pump Motors        106h            1077             1088              1076         100                <0.01           (d) 15.3.2       15.3-3    Speed Decrease of One Main Recirc Motor       106h            1020             1059              1012         100                <0.01           (d) h 15.3.2       15.3-4    Speed Decrease of Two Main Recirc Motors      106             1061             1072              1061         100                <0.01           (d) 15.3.3       15.3-5    Seizure of One Recirculation Pump             106h            1099             1110              1098         100                <0.01            (i) 15.3.4                 Recirc Pump Shaft Break                       See 15.3.3 15.4                   REACTIVITY AND POWER DISTRIBUTION ANOMALIES 15.0-18 FINAL SAFETY ANALYSIS REPORT 15.4.1.1               RWE - Refueling                               See text                                                                                            (j) 15.4.1.2               RWE - Startup                                 See text                                                                                            (j) 15.4.2                 RWE - At Power                                See text                                                                                           (d) 15.4.3                 Control Rod Misoperation                      See Sections 15.4.1 and 15.4.2 15.4.4       15.4-1    Abnormal Startup of Idle Recirculation Loop   124c            1004             1026              998          190                0.53            (d) 15.4.5       15.4-2    Speed Increase of One Main Recirc Motor       136c            990              1009              986          127                0.15            (d) 15.4.5                 Speed Increase of Both Main Recirc Motors     153c            1006             1033              1001         149                0.27            (d) 15.4.7                 Misplaced Bundle Accident                     See text                                                                                            (j) 15.4.9                 Rod Drop Accident                                                                                                                                 (i) 15.5                   INCREASE IN REACTOR COOLANT INVENTORY 15.5.1       15.5-1    Inadvertent HPCS Pump Startf                  102h            1020             1052              1012         100                <0.01g          (d) 15.5.3                 BWR Transients                                See appropriate events in Sections 15.1 and 15.2 a                                                                                                                                                                                     Amendment 63 Results reflect GE14 fuel introduction, and updates from GNF2 introduction some of which are dependent on fuel design and core loading pattern.
December 2015 Compliance with the event acceptance criteria is demonstrated by cycle-dependent analysis of potentially limiting events just prior to the operation of that cycle. The results are reported in the Supplemental Reload Licensing Report (Reference 15.0-1).

LDCN-15-011 Table 15.0-1 Results Summary of Transient Events Applicable to Columbia Generating Stationa (Continued) b MCPR operating limits are based on the delta-CPR (DCPR) results from the limiting transient event and the MCPR safety limit defined in the Technical Specifications.
c Option B DCPR results are reported.
d Moderate frequency.
COLUMBIA GENERATING STATION e
Unless otherwise noted, this value is only for GE14 fuel.
f Non-limiting event under power uprate conditions (event not reanalyzed).
g ODYN results without the adjustment factors delineated in the ODYN Report NEDO-24154, NEDC-24154P.
h No increase from initial value.
15.0-19 FINAL SAFETY ANALYSIS REPORT i
Limiting fault.
j Infrequent incident.
k This value is only for the more limiting GNF2 fuel and does not include plant specific TRACG bias and uncertainty.
Amendment 63 December 2015

COLUMBIA GENERATING STATION                  Amendment 63 FINAL SAFETY ANALYSIS REPORT                 December 2015 Table 15.0-1A Summary of Transient Peak Value Results Single-Loop Operation Maximum  Maximum Neutron  System Paragraph/                                             Flux   Pressure   Frequency Figure                    Description              (% NBR)    (psig)   Category Initial condition                          75      1020        N/A 15.1.2/      Feedwater flow controller failure          89      1118        (a) 15.1-3       (maximum demand) uprated power 15.2.2       Generator load rejection - uprated        131      1184        (a) power 15.3.3/      Seizure of active recirculation pump       75      1017        (b) 15.3-6 a
Moderate frequency incident.
b Limiting fault.
LDCN-15-011                                   15.0-20

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 Table 15.0-2 Input Parameters and Initial Conditions for Transients REDY (ASD Events)    REDYa            ODYN
: 1. Thermal power level, MWt Licensed value                               3486           3323           3486 Analysis value                               3702           3464           3629
: 2. Steam flow, lbs/hr analysis value                16.09 x 106    14.98 x 106    15.73 x 106
: 3. Core flow, lbs/hr                                108.5 x 106    108.36 x 106   95.5-115.0 x 106
: 4. FW flow rate, lb/sec analysis value              4471           4161           4362
: 5. Feedwater temperature, &deg;F                        426            424            426
: 6. Vessel dome pressure, psig                       1020           1020           1020
: 7. Vessel core pressure, psig                       1031           1031           1031
: 8. Turbine bypass capacity, %NBR                    22.7           25             22.7
: 9. Core coolant inlet enthalpy, Btu/lb              528.3          529.3          529.6
: 10. Turbine inlet pressure, psig                     992            975            997
: 11. Fuel lattice                                     8 x 8/9 x 9    8x8            Simulated 8x8/9x9
: 12. Core average fuel cladding gap conductance, Btu/sec-ft2-&deg;F                                   0.3608         0.1667         Fuel specific
: 13. Core leakage flow, %                             10.20          11.84          Cycle specific
: 14. Required MCPR operating limit                    (b)            1.24           (c)
: 15. MCPR safety limit                                (b)            1.06           (c)
: 16. Doppler coefficient (-)&#xa2;/&deg; Nominal EOC-1                                0.311          0.227          (d)
Analysis data ASD events
: 1. Increase power                            0.295          0.215
: 2. Decrease power                            0.327
: 17. Void coefficient (-)&#xa2;/% Rated Nominal EOC-1                                               7.48           (d)
Analysis data for power increase events      15.93          12.70          (d)
Analysis data for power decrease events      12.10          7.065          (d)
: 18. Core average rated void fraction,
    % (Steady state)                                 41.24          41.32          43.1
: 19. Scram reactivity, $k analysis data               Figure 15.0-1  Figure 15.0-1  (d)
: 20. Control rod drive speed, position versus time    Figure 15.0-1  Figure 15.0-1  Figure 15.0-1
: 21. Jet pump ratio, M                                2.36           2.41           2.39 15.0-21

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 Table 15.0-2 Input Parameters and Initial Conditions for Transients (Continued)
REDY (ASD Events)       REDYa         ODYN
: 22. Safety/relief valve capacity,% NBR safety valve capacity @ 1241 psig                 108.6             111.5         108.6 Relief valve capacity @ setpoint values in item 25 of this table                             @ 1121 psig 98.3  101.8          98.3
                                                         @ 1131 psig 99.1  102.8          99.1
                                                         @ 1141 psig 100.0 103.7         100
                                                         @ 1151 psig 100.9 104.6         100.9
                                                         @ 1161 psig 101.7 105.5         101.7 Manufacturer                                                        Crosby        Crosby Quantity installed                                                  18            18
: 23. Relief function delay, sec                        0.4               0.4           0.4
: 24. Relief function response, sec                     0.15              0.1           0.15
: 25. Setpoints for safety/relief valves Safety function, psig                        1200, 1210        1177, 1187,   1200, 1210 1221, 1231        1197, 1207,   1221, 1231 1241              1217          1241 Relief function, psig                        1121, 1131        1091, 1101,   1121, 1131 1141, 1151        1111, 1121,   1141, 1151 1161              1131          1161
: 26. Number of valve groupings simulated Safety function, number                                        5             5 Relief function, number                                        5             5
: 27. High flux trip analysis setpoint (123 x 1.041),% NBR                               128.0             126.20        128e
: 28. High pressure scram setpoint, psig                1086              1071          1086
: 29. Vessel level trips, inches with respect to dryer skirt bottom Level 8 - (L8), in.                          59.5              55.5          59.5 Level 4 - (L4), in.                                            31.5          30 Level 3 - (L3), in.                          7.5i              12.5i         (f)
Level 2 - (L2), in.                                            (-38)         (f)
: 30. APRM thermal trip analysis setpoint (117 x 1.041)% NBR @ 100% core flow               121.8             122.030       121.8e
: 31. Recirculation pump trip delay, sec                0.190             0.140         0.190
: 32. Recirculation pump trip inertia time constant for analysis, sec                                     6g                6g            6g
: 33. RPS response time delay                           (h)               (h)           (h)
LDCN-10-003                                         15.0-22

COLUMBIA GENERATING STATION                        Amendment 61 FINAL SAFETY ANALYSIS REPORT                       December 2011 Table 15.0-2 Input Parameters and Initial Conditions for Transients (Continued) a REDY values reflect the pre-uprate initial conditions. Only limiting events were analyzed for power uprate conditions with FCV.
b See COLR.
c Not applicable to reload 7/cycle 8 simulation.
d ODYN values are calculated within the code.
e The thermal multiplier (1.041 = 3629/3486) is used to give a conservative margin that is proportional to the core power.
f Parameter not used in the analysis.
g The inertia time constant is defined by the expression:
2  JO n t
g TO where t    = inertia time constant (sec)
Jo   = pump motor inertia (lb-ft2) n    = rated pump speed (rps) g    = gravitational constant (ft/sec2)
To   = pump shaft torque (lb-ft) h The maximum overall response time as addressed in the LCS is utilized for each scram encountered in the Chapter 15 events.
i The impact of steam flow induced error on the analytical limit does not impact event descriptions or conclusions (Reference 15.0-4).
LDCN-10-003                                   15.0-23

COLUMBIA GENERATING STATION                       Amendment 61 FINAL SAFETY ANALYSIS REPORT                     December 2011 Table 15.0-2A Input Parameters and Initial Conditions for Transients and Accidents for Single-Loop Operation Original Rated Power         Uprated Power
: 1. Thermal power analysis value (MWt)            2596.9             2615
: 2. Flow Steam (1b/hr)                            10.79 x 106        10.76 x 106 Core (lb/hr)                             59.0 x 106         61.85 x 106 Core bypass (lb/hr)                      5.88 x 106         6.22 x 106 Feedwater (lb/hr)                        10.79 x 106        10.76 x 106 Turbine bypass (lb/hr)                   5.88 x 106         N/A Turbine bypass (% rated)                 N/A                23%
: 3. Core Inlet Enthalpy (Btu/lb)                  510.8              513.7
: 4. Pressure Vessel dome (psia)                       1020               1008 Vessel core (psia)                       1029.7             1017.7 Turbine inlet (psia)a                    960.5              1000
: 5. Jet pump ratio (M)                            3.2                3.4
: 6. Safety/relief valve capacity
        % NBR @ 1,164 psig                       107.1              N/A Manufacturer                             Crosby             Crosby Quantity installed                       18                 18
        % NBR @ 1241 psig                        N/A                108.6
: 7. Relief function Delay (sec)                              0.4                0.4 Response (sec)                           0.1                0.15 15.0-24

COLUMBIA GENERATING STATION                        Amendment 61 FINAL SAFETY ANALYSIS REPORT                       December 2011 Table 15.0-2A Input Parameters and Initial Conditions for Transients and Accidents for Single-Loop Operation (Continued)
Original Rated Power           Uprated Power
: 8. Setpoints for safety/relief valves Safety function (psig)                   1177, 1187, 1197, 1200, 1210, 1221, 1207, 1217          1231, 1241 Relief function (psig)                   1106, 1116, 1126, 1121, 1131, 1141, 1136, 1146          1151, 1161
: 9. Number of valve groupings simulated Safety function (number)                 5                   5 Relief function (number)                 5                   5
: 10. Setpoints High flux trip analysis (1.21 x 1.043)   126.2               128
(% NBR)
High pressure scram (psig)               1071                1086 APRM thermal trip (% NBR @               122.03              121.8 100% core flow)
: 11. Vessel level trips (ft above instrument zero)
Level 8 - (L8) (ft)                      4.542 Level 4 - (L4) (ft)                      2.625 Level 3 - (L3) (ft)                      1.083b Level 2 - (L2) (ft)                      (-)4.167
: 12. RPT delay (sec)                               0.19                0.19 2
13a. RPT inertia for analysis (lb/ft )              24,500              N/A 13b. RPT inertia time constant (sec)                N/A                 6 a
Pressure specified at rated power condition. Off-rated power pressure drop is calculated by transient analysis code.
b The impact of steam flow induced error on the analytical limit does not impact event descriptions or conclusions (Reference 15.0-4).
LDCN-10-003                                   15.0-25

COLUMBIA GENERATING STATION                   Amendment 63 FINAL SAFETY ANALYSIS REPORT                 December 2015 Table 15.0-2B Input Parameters and Initial Conditions for ARTS/MELLLA and GNF Reload Transient Analyses Parameter                                  Value
: 1. Thermal power level, MWt                                             3486
: 2. Steam flow, lbs/hr analysis value                                 15.01 x 106
: 3. Core flow, lbs/hr                                             87.6 - 115.0 x 106
: 4. FW flow rate, lb/sec analysis value                                 4161.6
: 5. Feedwater temperature, &deg;F                                            421.2
: 6. Vessel dome pressure, psig                                           1020
: 7. Vessel core pressure, psig                                           1032
: 8. Turbine bypass capacity, %NBR                                        23.75
: 9. Core coolant inlet enthalpy, Btu/lb (rated flow)                     527.2
: 10. Turbine inlet pressure, psig                                          990
: 11. Fuel lattice                                                  10 x 10 mixed core
: 12. Required MCPR operating limit                                     See COLR
: 13. MCPR safety limit                                                 See COLR
: 14. Control rod drive speed, position versus timea
: 15. Jet pump ratio, M                                                    2.285
: 16. Safety/relief valve capacity, % NBR safety valve capacity      See Table 5.2-3 Manufacturer                                                 Crosby Quantity installed                                              18
: 17. Relief valve function delay, sec                                                      0.4 response, sec                                                  0.15
: 18. Safety valve function delay, sec                                                      0.0 response, sec                                                  0.3 LDCN-10-004                                15.0-26

COLUMBIA GENERATING STATION                        Amendment 61 FINAL SAFETY ANALYSIS REPORT                       December 2011 Table 15.0-2B Input Parameters and Initial Conditions for GNF Reload Transient (Continued)
Parameter                                         Value
: 19. Setpoints for safety/relief valves                               # in Group     Setpoint Safety function, psig                                          2b           1200 4b           1210 4            1221 4            1231 4            1241 Relief function, psig                                          2b           1156 4b           1166 4            1176 4            1186 4            1196
: 20. Number of valve groupings simulated Safety function, number (actual/credited)                           5/3 Relief function, number (actual/credited)                           5/3
: 21. High flux trip analysis setpoint,% NBR                                    123.0
: 22. High pressure scram setpoint, psig                                        1086
: 23. Vessel level trips, inches with respect to instrument zero Level 8 - (L8), in.                                                  59.5 Level 4 - (L4), in.                                                   30 Level 3 - (L3), in.                                                  2.5c Level 2 - (L2), in.                                            -90 LOCA
                                                                           -70 Non LOCA
: 24. APRM thermal trip analysis setpoint                                    Not credited
: 25. Recirculation pump trip delay, sec                                        0.200
: 26. RPS response time delay                                                 See LCS a
See Section 4.6.1.1.2.5.3.
b Valve group function not credited in safety analyses.
c This allows the correction due to steam flow induced error (Reference 15.0-4).
LDCN-10-003                                  15.0-27

COLUMBIA GENERATING STATION              Amendment 61 FINAL SAFETY ANALYSIS REPORT             December 2011 Table 15.0-3 Summary of Accidents Paragraph                                               Failed Fuel I.D.                            Title               Calculated Value 15.3.3    Seizure of one recirculation pump                None 15.3.4    Recirculation pump shaft break                   None 15.4.9    Rod drop accident                               850 rods 15.6.2    Instrument line break                            None 15.6.4    Steam system pipe break outside containment      None 15.6.5    Loss-of-coolant accident within RCPB             100%
15.6.6    Feedwater line break                             None 15.7.1    Main condenser gas treatment system failure       N/A 15.7.3    Liquid radwaste tank failure                      N/A 15.7.4    Fuel handling accident                          250 rods 15.8      Anticipated transients without scram             None 15.0-28

COLUMBIA GENERATING STATION                  Amendment 61 FINAL SAFETY ANALYSIS REPORT                 December 2011 Table 15.0-4
       /Q (s/m3) values for the EAB and LPZ Time Period     EAB /Q (s/m3)      LPZ /Q (s/m3) 0 - 2 hrs         1.81 E-4           4.95 E-5 2 - 8 hrs                            4.95 E-5 8 - 24 hrs                            3.69 E-5 1-4d                                1.95 E-5 4 - 30 d                             7.81 E-6 15.0-29

COLUMBIA GENERATING STATION                   Amendment 61 FINAL SAFETY ANALYSIS REPORT                 December 2011 Table 15.0-5 Control Room Atmospheric Dispersion Factors (sec/m3)
Hours         Turbine    Secondary   SGT System Building   Containment    Release Filtered Intake Release Path      0-2            8.81E-4     2.82E-4      1.43E-4 2-8            3.75E-4     2.17E-4      1.05E-4 8 - 24         1.93E-4     8.77E-5      4.14E-5 24 - 96        1.50E-4     7.42E-5      3.52E-5 96 - 720       1.44E-4     6.40E-5      3.03E-5 Unfiltered Intake Release Path    0-2            4.70E-3     7.02E-4      6.95E-4 2-8            2.00E-3     3.19E-4      3.36E-4 8 - 24         1.03E-3     1.30E-4      1.28E-4 24 - 96        8.01E-4     1.05E-4      9.72E-5 96 - 720       7.69E-4     9.00E-5      7.69E-5 15.0-30

Amendment 53 November 1998 1.0                                                                                              40
                                                                                                                 $40.21
                                                                                                                 $37.05 End of Cycle 1 Scram Curve 0.8 Control Fraction (Per Unit Insertion) 67B Scram Rod Drive                                                                    30 Scram Reactivity ($)
0.6 20 0.4 Scram Curve Used in Analysis                           10 0.2 0                                                                                               0 0        1         2         3         4            5          6          7            8 Time (sec) 67 Scram Analysis EOC 1 Scram Curve Revised Portion of Scram Speed Used in ODYN Analysis Scram Position and Reactivity Columbia Generating Station                                         Characteristics Final Safety Analysis Report Draw. No. 900547.61       Rev.       Figure   15.0-1 Form No. 960690

Amendment 58 December 2005 Core WC WA WI WC - Total Core Flow WA - Active Loop Flow W - Inactive Loop Flow Illustration of Single Recirculation Loop Columbia Generating Station                            Operation Flows Final Safety Analysis Report Draw. No. 910402.42        Rev.        Figure 15.0-2 Form No. 960690FH LDCN-05-019

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 15.1    DECREASE IN REACTOR COOLANT TEMPERATURE 15.1.1      LOSS OF FEEDWATER HEATING 15.1.1.1       Identification of Causes and Frequency Classification 15.1.1.1.1      Identification of Causes A feedwater heater can be lost in at least two ways:
: a.      Steam extraction line to heater is closed, and
: b.      Steam is bypassed around heater.
The first case produces a gradual cooling of the feedwater. In the second case, the steam bypasses the heater and no heating of that feedwater occurs. In either case, the reactor vessel receives cooler feedwater. The maximum number of feedwater heaters that can be tripped or bypassed by a single event represents the most severe transient for analysis considerations.
This event has been conservatively estimated to incur a loss of up to 100&deg;F of the feedwater heating capability of the plant and causes an increase in core inlet subcooling. This increases core power due to the negative void reactivity coefficient.
15.1.1.1.2      Frequency Classification This event is considered to be an incident of moderate frequency and is analyzed under worst case conditions of a 100&deg;F loss at full power.
15.1.1.2       Sequence of Events and Systems Operation The loss of feedwater heating leads to a gradual decrease in the temperature of the feedwater entering the reactor vessel. The decrease in feedwater temperature results in an increase in the core inlet subcooling which collapses voids, and increases the core average power. The gradual power change allows fuel thermal response to maintain pace with the increase in neutron flux. For this analysis, it was assumed that the initial feedwater temperature dropped 100&deg;F.
In establishing the expected sequence of events and simulating the plant performance, it was assumed that normal functioning occurred in the plant instrumentation and controls, plant protection, and reactor protection systems. Engineered safety feature (ESF) system initiation is not anticipated or required to prevent or mitigate the transient.
The Average Power Range Monitor (APRM) Simulated Thermal Power trip setpoint provides protection against transients such as the Loss of Feedwater Heating where thermal power increases slowly. While the sequence of events may produce sufficiently high LDCN-10-004                                   15.1-1

COLUMBIA GENERATING STATION                         Amendment 60 FINAL SAFETY ANALYSIS REPORT                        December 2009 flux levels to initiate an APRM reactor protection system trip, no credit is taken for a reactor trip in the analysis of the event. A description of the APRM system and operation is provided in Sections 7.2.1.1.1.2 and 7.6.1.4.3.
15.1.1.2.1      The Effect of Single Failures and Operator Errors The loss of feedwater heating generally leads to an increase in reactor power level. The APRM system is the mitigating system and is designed to be single failure proof. Therefore, single failures are not expected to result in a more severe event than analyzed.
15.1.1.3       Core and System Performance 15.1.1.3.1      Mathematical Model The analytical dynamic behavior has been determined using the steady state boiling water reactor (BWR) simulator code PANACEA (Reference 15.1-2). This code does not provide plots of the dynamic behavior of basic parameters as a function of time nor does it provide information for a sequence of events table. Therefore, no figures or tables are available.
Reference 15.1-6 approves the use of PANACEA for modeling the Loss of Feedwater Heating event.
The loss of feedwater heating (LFWH) event analysis supports an assumed 100&deg;F decrease in the feedwater temperature. The result is an increase in core inlet subcooling, which collapses voids, thereby, increasing the core power and shifting the axial power distribution toward the bottom of the core. As a result of the axial power shift and increased core power, voids begin to build up at the bottom of the core, acting as negative feedback to the void collapse process.
The negative feedback moderates the core power increase. The PANACEA code is used to determine the change in minimum critical power ratio (MCPR) during the event. Analyses were performed for a range of cycle exposures to ensure that appropriate limits are set.
Although there is a substantial increase in core thermal power during the event, the increase in steam flow is much less because a large part of the added power is used to overcome the increase in inlet subcooling. The increase in steam flow is accommodated by the pressure control system by the turbine control (governor) valves or the turbine bypass valves, so no pressurization occurs (Reference 15.1-3).
15.1.1.3.2      Input Parameters and Initial Conditions These analyses have been performed, unless otherwise noted, with plant conditions tabulated in Table 15.0-2B.
LDCN-08-035                                    15.1-2

COLUMBIA GENERATING STATION                          Amendment 60 FINAL SAFETY ANALYSIS REPORT                         December 2009 15.1.1.3.3       Results The LFWH transient is analyzed for each reload core to quantify the reduction in thermal margins. The results of the analysis are provided in the cycle specific Supplemental Reload Licensing Report (Reference 15.1-3).
15.1.1.3.4       Considerations of Uncertainties Factors such as exposure and magnitude of feedwater temperature change are assumed to be at the worst configuration so that any deviations seen in the actual plant operation reduce the severity of the event.
15.1.1.4       Barrier Performance The consequences of this event do not result in any temperature or pressure transient in excess of the criteria for which the fuel, pressure vessel, or containment are designed. Therefore, barrier integrity and function is maintained.
15.1.1.5       Radiological Consequences Since this event does not result in any additional fuel failures or any release of primary coolant to either the secondary containment or to the environment, there are no radiological consequences associated with this event.
15.1.2      FEEDWATER CONTROLLER FAILURE - MAXIMUM DEMAND 15.1.2.1       Identification of Causes and Frequency Classification 15.1.2.1.1       Identification of Causes This event is postulated on the basis of a single failure of a control device, specifically one that can directly cause an increase in coolant inventory by increasing the feedwater flow. The most severe applicable event is a feedwater controller failure (FWCF) during maximum flow demand. The feedwater controller is forced to its upper limit at the beginning of the event.
The event is evaluated for both single and two reactor recirculation loop operations. Because the two-loop operation event is bounding, the core performance analysis is limited to the feedwater controller failure during two-loop operation. However, the MCPR operating limit for single loop operation (SLO) is obtained by adding the CPR from two-loop operation to the MCPR safety limit (SLMCPR) for SLO.
15.1.2.1.2       Frequency Classification This event is considered to be an incident of moderate frequency.
LDCN-08-035                                    15.1-3

COLUMBIA GENERATING STATION                            Amendment 59 FINAL SAFETY ANALYSIS REPORT                           December 2007 15.1.2.2        Sequence of Events and Systems Operation The increase in feedwater flow, due to a failure of the feedwater control system to maximum demand, results in an increase in the water level and a decrease in the coolant temperature at the core inlet. The increase in core inlet subcooling causes an increase in core power. As the feedwater flow continues at maximum demand, the water level continues to rise and eventually reaches the high water level trip setpoint. The initial water level is conservatively assumed to be at the low level normal operating range of 30 inches above instrument zero to delay the high-level trip and maximize the core inlet subcooling that results from the FWCF. The high water level trip causes the turbine throttle (stop) valves to close in order to prevent damage to the turbine from excessive liquid inventory in the steam line. The valve closures create a compression wave that travels to the core causing a void collapse and subsequent rapid power excursion. In addition to the turbine throttle valve closure, the turbine governor valves also close in the fast closure mode. The closure of the governor (control) turbine valves initiates a reactor scram and a recirculation pump trip. Because of the partially opened initial position of the governor valves, they will close faster than the throttle valves and initiate the pressurization portion of the event. The turbine bypass valves are assumed operable and provide some pressure relief. The core power excursion is mitigated in part by the pressure relief, but the primary mechanisms for termination of the event are reactor scram and revoiding of the core.
The high-pressure core spray (HPCS) system and reactor core isolation cooling (RCIC) system initiate on a low reactor water level (L2) to maintain long-term water level control following tripping of feedwater pumps. The analysis of this event assumes normal functioning of plant instrumentation and controls, plant protection and reactor protection systems.
Table 15.1-1 lists the sequence of events for Figure 15.1-1. The figure shows the changes in variables during this transient.
15.1.2.2.1       Sequence of Events and Systems Operation - Single Loop Operation The simulated feedwater controller transient is shown in Figure 15.1-3 for the case of 75% power, 57% core flow. The high-water level turbine trip and feedwater pump trip are initiated at approximately 8.4 sec. A scram occurs simultaneously with the turbine trip and limits the neutron flux peak and fuel thermal transient so no fuel damage occurs.
Table 15.1-1A lists the sequence of events for Figure 15.1-3. The figures show the changes in important variables during this transient.
Identification of Operator Actions
: a.      Observe high feedwater pump trip has terminated the failure event, 15.1-4

COLUMBIA GENERATING STATION                            Amendment 63 FINAL SAFETY ANALYSIS REPORT                           December 2015
: b.       Switch the feedwater controller from auto to manual control to try to regain a correct output signal, and
: c.       Conduct follow-up assessment.
15.1.2.2.2      The Effect of Single Failures and Operator Errors The first sensed event to initiate corrective action to the transient is the vessel high water level (L8) trip. Multiple level sensors are used to sense and detect when the water level reaches the L8 setpoint. At this point in the logic, a single failure will not initiate or prevent a turbine trip signal. Turbine trip signal transmission, however, is not built to single failure criterion. The result of a failure at this point would have the effect of delaying, but not impacting, the pressurization signature.
Scram trip signals from the turbine are designed such that a single failure will neither initiate nor impede a reactor scram trip initiation.
15.1.2.3        Core and System Performance 15.1.2.3.1       Mathematical Model The predicted dynamic behavior has been determined using a computer simulated, analytical model of a direct-cycle BWR. This model is described in detail in Reference 15.1-3. Results from the two-loop operation bound the SLO event. Therefore, the discussion of core and system performance is limited to the description of the analysis for two-loop operation.
The nonlinear computer simulated analytical model is designed to predict associated transient behavior of the reactor. Some of the significant features of the model are the following:
: a.       An integrated three-dimensional neutron kinetics core model is assumed which includes a detailed description of hydraulic feedback effects, axial power shape changes, and reactivity feedbacks;
: b.       The fuel is represented by a separate channel grouping scheme based on the distinct characteristics of the fuel bundles in the core;
: c.       The four physical steam lines are modeled as two steam lines, one a single steam line and the other as three lumped steam lines. The modeled steam lines are connected with a tee component and another tee connected downstream which is connected to a valve component modeling the Turbine Bypass Valves (TBVs). Also associated with these steam lines are valve components modeling the inboard and outboard main steam isolation valves, the Safety/Relief valves, and the Turbine Control Valves. Pressure boundary condition components are LDCN-15-011                                       15.1-5

COLUMBIA GENERATING STATION                            Amendment 63 FINAL SAFETY ANALYSIS REPORT                           December 2015 connected to the downstream sides of the S/RVs, and the TBVs. A flow boundary condition component represents the steam mass flow rate through the TCVs. This mass flow rate is calculated by the TRACG control system logic.
The open area fraction of the S/RVs and TBVs is determined by the TRACG control system logic. TRACG control systems are used extensively in modeling plant component and system behavior.;
: d. The code is based on a multidimensional twofluid model for the reactor thermal hydraulics. The basic twophase, twofluid model consists of the volume and time averaged conservation equations for mass, momentum, and energy for each phase. Thus, the model does not assume thermal or mechanical equilibrium between the phases;
: e. A control system model capable of simulating major BWR controls systems, such as feedwater flow, recirculation flow, reactor water level, pressure, and load demand; and
: f. The ability to simulate necessary reactor protection system functions is provided.
15.1.2.3.2     Input Parameters and Initial Conditions These analyses have been performed with the plant conditions in Table 15.0-2B.
All rods out scram characteristics are assumed. The safety/relief valve (SRV) action is conservatively assumed to occur with higher than nominal setpoints. The transient is simulated by programming an upper limit failure in the feedwater system such that 139% feedwater flow occurs at the nominal reactor operating pressure of 1035 psia.
An increase in feedwater flow will cause a corresponding drop in feedwater temperature.
However, the relatively large time constant of the feedwater heaters (order of minutes) plus the flow transport time (10 sec from heaters to vessel and 3 sec from sparger to core) would preclude any effect of temperature reduction on the transient since the transient is essentially over in about 20 sec. Therefore, feedwater temperature is assumed to remain constant.
15.1.2.3.3     Results The simulated feedwater controller transient is shown in Figure 15.1-1. The high water level turbine trip and feedwater pump trip are initiated as stated in Table 15.1-1. Results reflect GNF2 fuel introduction, some of which are dependent on fuel design and core loading pattern.
Compliance with the event acceptance criteria is demonstrated by cycle-dependent analysis of potentially limiting events just prior to the operation of that cycle. The results are reported in the Supplemental Reload Licensing Report (Reference 15.1-3).
LDCN-15-011                                    15.1-6

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                        December 2015 Because the total change in feedwater flow is greatest from reduced power conditions, the feedwater controller failure (FWCF) transient was analyzed for several reduced power states.
The power dependent MCPR limits are established to protect the fuel during the FWCF event.
15.1.2.3.4       Consideration of Uncertainties All systems used for protection in this event were assumed to have the most conservative response characteristics. Therefore, actual plant behavior is expected to lead to a less severe transient.
15.1.2.4        Barrier Performance The consequences of this event do not result in any temperature or pressure transient in excess of the criteria for which the fuel, pressure vessel, or containment are designed. Therefore, barrier integrity and function is maintained.
15.1.2.5        Radiological Consequences The consequence of this event does not result in fuel failure. It does result in the discharge of normal coolant activity to the suppression pool by means of SRV operation, which is contained in the primary containment. This event does not result in an uncontrolled release to the environment, so the plant operator can choose to hold the activity in containment or discharge it when conditions permit. If purging of the containment is chosen, the release would be in accordance with established requirements.
15.1.3       PRESSURE REGULATOR FAILURE - OPEN 15.1.3.1        Identification of Causes and Frequency Classification 15.1.3.1.1       Identification of Causes The total steam flow rate to the main turbine resulting from a pressure regulator malfunction in the Digital Electro-Hydraulic (DEH) control system is limited by a maximum flow limiter imposed at the turbine controls. This limiter is set to limit maximum steam flow demand to approximately 130% NBR.
If the triple redundant DEH control system fails such that the turbine control (governor) valves fully open and the turbine bypass valves partially open, the maximum steam flow is established.
15.1.3.1.2       Frequency Classification This event is categorized as an incident of moderate frequency.
15.1-7

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 15.1.3.2       Sequence of Events and Systems Operation 15.1.3.2.1      Sequence of Events Table 15.1-2 lists the sequence of events for Figure 15.1-2. Figure 15.1-2 depicts how the high water level turbine trip and isolation valve closure stops vessel depressurization and produces a normal shutdown of the reactor.
15.1.3.2.2      Systems Operation Depressurization results in formation of voids in the reactor coolant and causes a decrease in reactor power almost immediately. In this simulation, the depressurization rate is large enough such that water level swells to the sensed level trip setpoint (L8), initiating main turbine and feedwater turbine trips. Position switches on the turbine stop (throttle) valves initiate a reactor scram and RPT and shut down the reactor. After the turbine trip, the failed DEH control system signals the bypass to open to full bypass flow of 25% NBR steam flow. After the pressurization resulting from the turbine stop (throttle) valve closure, the pressure increase opens the relief valves and pressure drops and continues to drop until turbine inlet pressure is below the low turbine pressure isolation setpoint when main steam line isolation limits the duration and severity of the depressurization.
In order to properly simulate the expected sequence of events, the analysis of this event assumed normal functioning of plant instrumentation and controls, plant protection, and reactor protection systems except as otherwise noted.
Initiation of HPCS and RCIC system functions will occur when the vessel water level reaches the L2 setpoint although this is not included in the analysis. Normal startup and actuation can take up to 30 sec before effects are realized. If these events occur, they will follow some time after the primary concerns of fuel thermal margin and overpressure effects have occurred and are expected to be less severe than those already experienced by the system.
15.1.3.2.3      The Effect of Single Failures and Operator Errors This transient leads to a loss of pressure control such that the increased steam flow demand causes a depressurization. Instrumentation for pressure sensing of the turbine inlet pressure is designed to be single failure proof for initiation of MSIV closure.
Reactor scram sensing, originating from limit switches on the MSIVs, is designed to be single failure proof. It is, therefore, concluded that the basic phenomenon of pressure decay is adequately terminated.
15.1-8

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 15.1.3.3       Core and System Performance 15.1.3.3.1      Mathematical Model The point-kinetics REDY model described in Section 15.0.3.3.1 is used to simulate this event.
15.1.3.3.2      Input Parameters and Initial Conditions This transient is simulated by setting the DEH control system demand signal to a high value, which causes the turbine control (governor) valves to open fully and the turbine bypass valves to open partially. A DEH control failure with 130% steam flow demand signal was simulated as a worst case since 130% is the normal maximum flow limit in order to conform with Table 15.1-2.
A 5-sec isolation valve closure is assumed when the turbine pressure decreases below the turbine inlet low pressure setpoint for main steam line isolation initiation.
Reactor scram is initiated when the isolation valves reach the 10% closed position. This is the maximum travel from the full open position allowed by specification.
This analysis has been performed, unless otherwise noted, with the plant conditions listed in Table 15.0-2.
15.1.3.3.3      Results Results are summarized in Table 15.0-1.
No significant reductions of fuel thermal margins occur. No significant thermal stresses are imposed on the reactor coolant pressure boundary (RCPB).
15.1.3.3.4      Consideration of Uncertainties If the maximum flow limiter were set higher or lower than normal, a faster or slower loss in nuclear steam pressure would result. The rate of depressurization may be limited by the bypass capacity, but it is unlikely. For example, the turbine valves will open to the valves-wide-open state admitting slightly more than the rated steam flow, and with the limiter in this analysis set to fail at 130%, it is expected that less than 25% would be bypassed. This is, therefore, not a limiting factor for the plant. If the rate of depressurization does change, it will be terminated by the low turbine inlet pressure trip setpoint.
Depressurization rate has a proportional effect upon the voiding action in the core and the flashing in the vessel bulk water regions. If the rate is low enough, the water level may not swell to the high water level trip setpoint and the isolation will occur earlier when pressure at 15.1-9

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 the turbine decreases below 850 psia. The reactor will scram as a result of the MSIV closure.
Since power is being depressed as the pressure decreases (due to additional voiding in the core), this transient is less severe when a slower depressurization rate is assumed. Therefore, the assumed L8 trip provides the most restrictive margins on MCPR and peak vessel pressure.
15.1.3.4       Barrier Performance Barrier performance analyses were not required since the consequences of this event do not result in any temperature or pressure transient in excess of the criteria for which fuel, pressure vessel, or containment are designed. Peak pressure in the bottom of the vessel is below the ASME code upset limit for the RCPB.
15.1.3.5       Radiological Consequences The consequence of this event does not result in fuel failure. It does result in the discharge of normal coolant activity to the suppression pool by means of SRV operation, which is contained in the primary containment. This event does not result in an uncontrolled release to the environment, so the plant operator can choose to hold the activity in containment or discharge it when conditions permit. If purging of the containment is chosen, the release would be in accordance with established requirements.
15.1.4      INADVERTENT SAFETY/RELIEF VALVE OPENING The event is defined as the inadvertent opening of an SRV which stays in the open position.
It was determined that this event is not limiting from a core performance standpoint.
15.1.4.1       Identification of Causes and Frequency Classification 15.1.4.1.1      Identification of Causes Cause of inadvertent opening is attributed to malfunction of the valve or an operator initiated opening. Opening and closing circuitry at the individual valve level (as opposed to groups of valves) is subject to a single failure impact. It is therefore simply postulated that a failure occurs and the event is analyzed accordingly. Detailed discussion of the valve is provided in Section 5.2.2.
15.1.4.1.2      Frequency Classification This event is categorized as an incident of moderate frequency.
15.1-10

COLUMBIA GENERATING STATION                         Amendment 61 FINAL SAFETY ANALYSIS REPORT                        December 2011 15.1.4.2       Sequence of Events and Systems Operation 15.1.4.2.1      Sequence of Events Table 15.1-3 lists the sequence of events.
15.1.4.2.2      Systems Operation In this transient, the analysis assumes normal functioning of plant instrumentation and controls, specifically, the relief valve discharge line temperature sensors and the suppression pool temperature sensors and reactor pressure vessel level control systems. The opening of an SRV allows steam to be discharged into the suppression pool. The sudden increase in the rate of steam flow leaving the reactor vessel causes a mild depressurization transient. The pressure regulator senses the nuclear system pressure decrease and within a few seconds closes the turbine control (governor) valve far enough to stabilize reactor vessel pressure at a slightly lower value and reactor power settles at nearly the initial power level. Additionally, although not credited in the analysis to mitigate the consequences of this transient, minimum reactor and plant protection systems, emergency core cooling system flow, and RHR suppression pool cooling, are available.
15.1.4.2.3      The Effect of Single Failures and Operator Errors From a core performance standpoint, a single failure or operator error would simply activate the reactor protection system resulting in a plant shutdown. A single failure or operator error cannot increase the severity of this event.
The instrumentation which detects and audibly alarms the resulting suppression pool temperature rise, and the RHR containment heat removal system are designed to meet the single failure criteria. The operator must manually initiate suppression pool cooling.
15.1.4.3       Core and System Performance 15.1.4.3.1      Mathematical Model The one-dimensional ODYN model described in Section 15.0.3.3.1 is used to simulate this event.
15.1.4.3.2      Input Parameters and Initial Conditions These analyses have been performed, unless otherwise noted, with plant conditions tabulated in Table 15.0-2, the ODYN column. A discussion of the SRV is provided in Section 5.2.2.
15.1-11

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.1.4.3.3      Results Thermal margins decrease only slightly through the transient, and no fuel damage results from the transient. The MCPR is essentially unchanged and, therefore, the safety limit margin is unaffected.
15.1.4.4       Barrier Performance The transient resulting from a stuck open relief valve is a mild depressurization which is within the range of normal load following. Therefore, there is no significant effect on RCPB and containment design pressure limits.
Since quenchers are used as steam discharge devices on the steam relief lines, no unstable condensation oscillations are expected which could damage the containment vessel. This is discussed in Appendix 3A.
Therefore, barrier integrity and function is maintained.
15.1.4.5       Radiological Consequences While the consequence of this event does not result in fuel failure, it does result in the discharge of normal coolant activity to the suppression pool by means of SRV operation.
Since this activity is contained in the primary containment there will be no exposures to operating personnel. Since this event does not result in an uncontrolled release to the environment the plant operator can choose to hold the activity in containment or discharge it to the environment when conditions permit. If purging of the containment is chosen, the release would be in accordance with established requirements.
15.1.5      SPECTRUM OF STEAM PIPING FAILURES INSIDE AND OUTSIDE OF CONTAINMENT IN A PRESSURIZED WATER REACTOR This event is not applicable to BWR plants.
15.1.6      INADVERTENT RESIDUAL HEAT REMOVAL SHUTDOWN COOLING OPERATION This transient is classified as a nonlimiting event for both original and uprated power conditions. Therefore, no further analysis has been performed.
15.1-12

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.1.6.1        Identification of Causes and Frequency Classification 15.1.6.1.1       Identification of Causes At design power conditions no conceivable malfunction in the shutdown cooling system could cause temperature reduction.
In startup or cooldown operation, where the reactor is at or near critical, a very slow increase in reactor power could result. A shutdown cooling malfunction leading to a moderator temperature decrease could result from misoperation of the cooling water controls for the RHR heat exchangers. The resulting temperature decrease would cause a slow insertion of positive reactivity into the core. If the operator did not act to control the power level, a high neutron flux reactor scram would terminate the transient without violating fuel thermal limits and without any measurable increase in nuclear system pressure.
15.1.6.1.2       Frequency Classification This event is categorized as an incident of moderate frequency.
15.1.6.2        Sequence of Events and Systems Operation 15.1.6.2.1       Sequence of Events A shutdown cooling malfunction leading to a moderator temperature decrease could result from misoperation of the cooling water controls for RHR heat exchangers. The resulting temperature decrease causes a slow insertion of positive reactivity into the core. Scram will occur before any thermal limits are reached if the operator does not take action. The sequence of events for this event is shown in Table 15.1-4.
15.1.6.2.2       System Operation A shutdown cooling malfunction causing a moderator temperature decrease must be considered in all operating states. However, this event is not considered while at power operation since pressure is too high to permit operation of RHR shutdown cooling.
No unique safety actions are required to avoid unacceptable safety results for transients as a result of a reactor coolant temperature decrease induced by misoperation of the shutdown cooling heat exchangers. In startup or cooldown operation, where the reactor is at or near critical, the slow power increase resulting from the cooler moderator temperature would be controlled by the operator in the same manner normally used to control power in the source or intermediate power ranges.
15.1-13

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.1.6.2.3       Effect of Single Failures and Operator Action No single failures can cause this event to be more severe.
If the operator takes action, the slow power rise will be controlled in the normal manner. If no operator action is taken, a scram will terminate the power increase before thermal limits are reached.
15.1.6.3       Core and System Performance The increased subcooling caused by misoperation of the RHR shutdown cooling mode could result in a slow power increase due to the reactivity insertion. This power rise would be terminated by a flux scram before fuel thermal limits are approached. Therefore, only a qualitative description is provided here.
15.1.6.4       Barrier Performance The consequences of this event do not result in any temperature or pressure transient in excess of the criteria for which the fuel, pressure vessel, or containment are designed. Therefore, barrier integrity and function is maintained.
15.1.6.5       Radiological Consequences Since this event does not result in any fuel failures, no analysis of radiological consequences is required for this event.
15.

==1.7      REFERENCES==

15.1-1           For Power Uprate: GE Nuclear Energy, WNP-2 Power Uprate Transient Analysis Task Report, GE-NE-208-08-0393, September 1993 (Proprietary).
15.1-2           NEDE-30130-P-A, Steady State Nuclear Methods, April 1985.
15.1-3           Supplemental Reload Licensing Report for Columbia (most recent version referenced in COLR).
15.1-4           NEDC-24154-P-A, Qualification of the One-Dimensional Core Transient Model for Boiling Water Reactors, Volumes 1, 2, 3 and 4, February 2000.
15.1-5           GE Nuclear Energy, WNP-2 Power Uprate Project NSSS Engineering Report, GE-NE-208-17-0993, Revision 1, December 1994.
15.1-14

COLUMBIA GENERATING STATION                       Amendment 63 FINAL SAFETY ANALYSIS REPORT                      December 2015 15.1-6      General Electric Standard Application for Reactor Fuel, NEDE-24011-P-A and Supplement for United States, NEDE-24011-P-A-US (most recent approved revision referenced in COLR).
15.1-7      NEDE-32906P-A, TRACG Application for Anticipated Operational Occurrences Transient Analyses, Revision 3, September 2006.
LDCN-15-011                             15.1-15

COLUMBIA GENERATING STATION                          Amendment 63 FINAL SAFETY ANALYSIS REPORT                         December 2015 Table 15.1-1 Typical Sequence of Events for Figure 15.1-1 Feedwater Controller Failure 100% Reactor Power / 106% Core Flow Time (sec)                                    Event 0         Initiate simulated failure of 139% upper limit on feedwater flow.
10.06     L8 vessel level setpoint trips main turbine and feedwater pumps. Turbine bypass operation initiated.
10.16     Turbine control (governor) or stop (throttle) valves fully closed.
10.08     Reactor scram trip actuated from main turbine control (governor) valve fast closure.
10.16     Turbine bypass valves start to open.
10.27     Recirculation pump motor circuit breakers open causing decrease in core flow to natural circulation.
LDCN-15-011                             15.1-17

COLUMBIA GENERATING STATION                         Amendment 61 FINAL SAFETY ANALYSIS REPORT                        December 2011 Table 15.1-1A Sequence of Events for Figure 15.1-3 Feedwater Controller Failure Single Loop Operation 75% Power / 57% Flow Time (sec)                                     Event 0         Initiate an upper limit failure of 146% of rated feedwater flow.
8.39      L8 vessel level setpoint trips main turbine and feedwater pumps.
8.39      Recirculation pump trip (RPT) actuated by stop valve position switches.
8.40      Reactor scram trip actuated from main turbine stop valve position switches.
8.49      Turbine stop valves closed and main turbine bypass valves start to open.
8.58      Recirculation pump motor circuit breakers open causing decrease in core flow to natural circulation.
15.1-18

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 Table 15.1-2 Sequence of Events for Figure 15.1-2 Pressure Regulator Failure - Open Uprated Power Time (sec)                                     Event 0          Simulate maximum limit on steam flow, (130%) to main turbine.
0.2        Main turbine bypass valves open.
3.31       Vessel water level (L8) trip initiates turbine and feedwater trips.
3.32       Main turbine stop valves reach 90% open position initiating a reactor scram.
3.50       Both recirculation pumps trip.
6.15       Feedwater recirculation valves trip.
6.95       Group 3 relief valves actuated.
7.40       Group 4 relief valves actuated.
10a          Pressure relief valves closed.
57.98a       Main steam line isolation valves closed on turbine inlet pressure (approximately 850 psia).
77           High-pressure core spray and RCIC system initiation on low level (L2).
a Estimated.
15.1-19

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 Table 15.1-3 Sequence of Events for Inadvertent Safety/Relief Valve Opening Uprated Power Time                                        Event 0         Initiate opening of one SRV which remains open throughout the event.
1a        Reactor dome pressure decreases.
3a        DEH turbine control system pressure regulator initiates closure of the turbine control (governor) valves to stabilize reactor vessel pressure.
8+        Reactor power settles near the initial power level.
a Approximately.
15.1-20

COLUMBIA GENERATING STATION                       Amendment 61 FINAL SAFETY ANALYSIS REPORT                      December 2011 Table 15.1-4 Sequence of Events for Inadvertent Residual Heat Removal Shutdown Cooling Operation Original Rated Power Timea                                        Event 0                 Residual heat removal shutdown cooling inadvertently activated.
0-10 minutes      Slow rise in reactor power.
  +10 minutes       Operator may take action to limit power rise. Flux scram will occur if no action is taken.
a Approximately.
15.1-21

Amendment 63 December 2015 Feedwater Controller Failure, Maximum Demand Columbia Generating Station                      System Response Final Safety Analysis Report                 100% Power, 106% Flow Draw. No. 910402.34      Rev. 1  Figure 15.1-1.1 Form No. 960690 LDCN-15-011

Amendment 53 November 1998 Pressure Regulator Failure - Open at 106.2%
Columbia Generating Station                 Uprated Power, 100%Flow Final Safety Analysis Report Draw. No. 020361.57      Rev. Figure 15.1-2.1

Amendment 53 November 1998 Pressure Regulator Failure - Open at 106.2%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.58     Rev. Figure 15.1-2.2

Amendment 53 November 1993 Pressure Regulator Failure Open at 106.2%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.59     Rev. Figure 15.1-2.3

Amendment 53 November 1998 Pressure Regulator Failure - Open at 106.2%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.60     Rev. Figure 15.1-2.4

Amendment 53 November 1998 Pressure Regulator Failure Open at 106.2%
Columbia Generating Station                Uprated Power, 100%Flow Final Safety Analysis Report Draw. No. 020361.61     Rev. Figure 15.1-2.5

Amendment 53 November 1998 Pressure Regulator Failure Open at 106.2%
Columbia Generating Station                Uprated Power, 100%Flow Final Safety Analysis Report Draw. No. 020361.62     Rev. Figure 15.1-2.6

Amendment 53 November 1998 Pressure Regulator Failure - Open at 106.2%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.63     Rev. Figure 15.1-2.7

Amendment 53 November 1998 Pressure Regulator Failure - Open at 106.2%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.64     Rev. Figure 15.1-2.8

Amendment 53 November 1998 Pressure Regulator Failure - Open at 106.2%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.65     Rev. Figure 15.1-2.9

Amendment 53 November 1998 Pressure Regulator Failure - Open at 106.2%
Columbia Generating Station                Uprated Power, 100% Flow Final Safety Analysis Report Draw. No. 020361.66     Rev. Figure 15.1-2.10

Amendment 53 November 1998 Pressure Regulator Failure - Open at 106.2%
Columbia Generating Station                Uprated Power, 100%Flow Final Safety Analysis Report Draw. No. 020361.67     Rev.      Figure 15.1-2.11

Amendment 57 December 2003 Ave Surface Heat Flux Neutron Flux                           Core Inlet Flow 20 15 Time (Sec) 10 5
0 150         100                           50                       0 (Percent of Rated)
Feedwater Controller Failure, Maximum Demand, Columbia Generating Station                                     EOC RPT OOS, Single Loop Operation and 75%
Final Safety Analysis Report                                               Uprated Power, 57% Flow Draw. No. 910402.41        Rev. Figure   15.1-3.1 Form No. 960690 LDCN-03-003

Amendment 57 December 2003 Level (Inch Ref SIP Skirt)
Vessel Steamflow   Turbine Steamflow   Feedwater Flow 20 15 Time (Sec) 10 5
0 200   100 0
                                                                                                                                                         -100 Feedwater Controller Failure, Maximum Demand, Columbia Generating Station                                         EOC RPT OOS, Single Loop Operation and 75%
Final Safety Analysis Report                                                   Uprated Power, 57% Flow Draw. No. 910402.40   Rev. Figure   15.1-3.2 Form No. 960690 LDCN-03-003

Amendment 57 December 2003 Vessel Pres Rise (PSI)                                           Bypass Valve Flow Safety Valve Flow   Relief Valve Flow 20 15 Time (Sec) 10 5
0 300   200                           100 0
Feedwater Controller Failure, Maximum Demand, Columbia Generating Station                                                 EOC RPT OOS, Single Loop Operation and 75%
Final Safety Analysis Report                                                           Uprated Power, 57% Flow Draw. No. 910402.39         Rev. Figure   15.1-3.3 Form No. 960690 LDCN-03-003

Amendment 57 December 2003 Void Reactivity   Doppler Reactivity   Scram Reactivity   Total Reactivity 20 15 Time (Sec) 10 5
0 1           0                           -1                     -2 Reactivity Components Feedwater Controller Failure, Maximum Demand, Columbia Generating Station                                                      EOC RPT OOS, Single Loop Operation and 75%
Final Safety Analysis Report                                                                Uprated Power, 57% Flow Draw. No. 910402.38    Rev. Figure   15.1-3.4 Form No. 960690 LDCN-03-003

COLUMBIA GENERATING STATION                           Amendment 59 FINAL SAFETY ANALYSIS REPORT                          December 2007 15.2     INCREASE IN REACTOR PRESSURE 15.2.1       PRESSURE REGULATOR FAILURE - CLOSED This transient is classified as a nonlimiting event for both original and uprated power conditions. Therefore, cycle specific analyses are not performed for this event. The analysis results presented in the section are based on uprated power conditions and a representative reload core (Cycle 8) as documented in Reference 15.2-5.
15.2.1.1         Identification of Causes and Frequency Classification 15.2.1.1.1        Identification of Causes A triple redundant control system is provided to maintain primary system pressure control.
The pressure upstream of the main turbine stop (throttle) valves is sensed by three redundant throttle pressure transmitters and the control system uses a median select logic to determine which pressure transmitter is used to control throttle pressure. The pressure control system compares the detected throttle pressure to a pressure setpoint to control the position of the main turbine control (governor) valves in order to control pressure.
It is assumed for purposes of this transient analysis that a single failure occurs on the controlling pressure transmitter which erroneously causes the DEH control system to close the turbine control (governor) valves and thereby increases reactor pressure. If this occurs, the self diagnostics ability and triple redundant control system is available.
15.2.1.1.2        Frequency Classification This event is categorized as an incident of moderate frequency.
15.2.1.2         Sequence of Events and Systems Operation 15.2.1.2.1        Sequence of Events A failure of a DEH control system component that causes the turbine control (governor) valves or turbine bypass valves to move towards the closed position will momentarily result in an initial pressure increase because the reactor is still generating the initial steam flow. The DEH control system is self diagnostic. It will detect the faulty component and disable it. The control system is redundant and will continue to perform its functions, and will restore steady state operation.
For a failure that causes the DEH turbine control pressure regulator to initiate a demand signal to close the turbine control (governor) valves (requires multiple component failures), there will be an increase in system pressure and reactor power. A scram will be initiated when the high LDCN-06-057, 07-011                             15.2-1

COLUMBIA GENERATING STATION                              Amendment 59 FINAL SAFETY ANALYSIS REPORT                             December 2007 neutron flux scram setpoint is reached. The pressure rises to the pressure relief setpoint, part of the relief valves open, discharging steam to the suppression pool. The plant response is given in Table 15.2-1.
15.2.1.2.2        Systems Operation Normal plant instrumentation and control is assumed to function except for the pressure regulator failure. The event is analyzed from 104.1% uprated power and 106% of rated core flow. The event results in a high flux trip initiated by the reactor protection system.
15.2.1.2.3        The Effect of Single Failures and Operator Errors The first assumed failure produces a slight pressure increase in the reactor until the DEH control system adjusts to the single failure and gains control. No other action is significant in restoring normal operation. If subsequent failures occur such that the DEH control system further closes the turbine control (governor) valves the reactor pressure could rise to the point where a flux or pressure scram trip would be initiated to shutdown the reactor. This event is less severe than the turbine trip for the following reasons:
: a.        For the DEH control system failure-closure event the reactor scrams on high neutron flux or pressure but the recirculation pumps do not trip. As a result, core flow remains at 100% or greater throughout the critical portion of the transient with respect to the critical power ratio (CPR). This provides improved heat transfer capability in relation to the turbine trip transient; and
: b.        Since the turbine control (governor) valves close in response to a pressure error signal, their closure rate is not as fast as the turbine stop (throttle) or control (governor) valve response to a trip signal. This produces a slower pressurization rate for the DEH control system failure relative to the turbine trip event. This in turn results in a lower peak neutron flux and therefore a lower peak surface heat flux than the turbine trip event.
15.2.1.3         Core and System Performance 15.2.1.3.1        Mathematical Model The one-dimensional ODYN model described in Section 15.0.3.3.1 is used to simulate this event.
LDCN-06-057, 07-011                               15.2-2

COLUMBIA GENERATING STATION                           Amendment 59 FINAL SAFETY ANALYSIS REPORT                          December 2007 15.2.1.3.2       Input Parameters and Initial Conditions The analyses have been performed with plant conditions at 104.1% of uprated power and 106% of rated core flow. The input parameters are given in detail in Table 15.0-2 under the ODYN column.
15.2.1.3.3       Results The closure of the turbine governor (control) valves results in a rise in reactor pressure, collapsing the coolant voids which in turn increases the neutron flux. One sec after the initiation of the event the neutron flux increases to the high flux setpoint signal and initiates a reactor scram. Two sec into the event the pressure in the reactor reaches the ATWS high pressure trip setpoint, initiating a recirculation pump trip signal. As the pressure in the reactor system continues to rise, the relief valves begin to open starting with Group 3. The maximum pressure is reached at 3.25 sec and is calculated to be 1220 psig at the bottom of the reactor vessel. Table 15.2-1 provides the sequence of events and Figure 15.2-1 depicts the plant parameters responses. Key transient peak values are presented in Table 15.0-1. This event is nonlimiting in that the pressurization event is less severe than the Generator Load Rejection with Bypass Failure and Turbine Trip with Bypass Failure events.
15.2.1.3.4       Consideration of Uncertainties The uncertainties included in the initial power and flow considerations maximize the consequences of the plant response. The independent pressure regulators normally respond such that failure of one would be compensated by the other regulator with plant not experiencing a trip.
15.2.1.4        Barrier Performance The consequences of this event do not result in any temperature or pressure transient (see Table 15.0-1) in excess of the criteria for which the fuel, pressure vessel, or containment are designed. Therefore, barrier integrity and function is maintained.
15.2.1.5        Radiological Consequences Since this event does not result in any fuel failures or any release of primary coolant to either the secondary containment or to the environment, there are no radiological consequences associated with this event.
LDCN-07-011                                      15.2-3

COLUMBIA GENERATING STATION                           Amendment 59 FINAL SAFETY ANALYSIS REPORT                          December 2007 15.2.2      GENERATOR LOAD REJECTION 15.2.2.1       Identification of Causes and Frequency Classification 15.2.2.1.1      Identification of Causes Fast closure of the turbine control (governor) valves (TCVs) is initiated whenever electrical grid disturbances occur which result in significant loss of electrical load on the generator. The TCVs are required to close as rapidly as possible to prevent excessive overspeed of the turbine-generator rotor. Closure of the main TCVs will cause a sudden reduction in steam flow which results in an increase in system pressure, which may cause a reactor shutdown due to a high flux or high steam pressure condition.
15.2.2.1.2      Frequency Classification 15.2.2.1.2.1 Generator Load Rejection. This event is categorized as an incident of moderate frequency.
15.2.2.1.2.2 Generator Load Rejection with Bypass Failure. This event is categorized as a moderate frequency event.
15.2.2.2       Sequence of Events and System Operation The generator load rejection with bypass failure event is the most limiting (with respect to thermal margin) of the class of transients characterized by rapid vessel pressurization, including load rejection with the bypass valves operating. The generator load rejection causes a TCV (governor valve) fast closure, which initiates a reactor scram and a recirculation pump trip (RPT). The compression wave produced by the TCV fast closure travels through the steam lines into the vessel and pressurizes the reactor vessel and core. Bypass flow to the condenser, which would mitigate the pressurization effect, is conservatively not allowed. The excursion of core power due to void collapse is primarily terminated by reactor scram and void growth due to RPT. The recirculation pump speed remains constant until tripped by the RPT system.
Events caused by low water level trips, including closure of main steam line isolation valves (MSIVs), and initiation of high-pressure core spray (HPCS) and reactor core isolation cooling (RCIC) are not included in the simulation. Should these events occur, they will follow after the primary concerns of fuel thermal margin and overpressure effects have occurred, and are expected to be less severe than those already experienced by the system.
LDCN-07-011                                   15.2-4

COLUMBIA GENERATING STATION                             Amendment 59 FINAL SAFETY ANALYSIS REPORT                            December 2007 15.2.2.2.1       Sequence of Events 15.2.2.2.1.1 Generator Load Rejection - Turbine Control Valve Fast Closure. This transient is classified as a nonlimiting event for both original and uprated power conditions. Therefore, the original rated power (3323 MWt) analysis has not been updated.
A loss of generator electrical load from high power conditions produces the sequence of events listed in Table 15.2-2.
15.2.2.2.1.2 Generator Load Rejection with Failure of Bypass. A loss of generator electrical load at 3486 MWt with bypass failure produces the sequence of events listed in Table 15.2-3.
15.2.2.2.2       System Operation 15.2.2.2.2.1 Generator Load Rejection with Bypass. To properly simulate the expected sequence of events, the analysis of this event assumes normal functioning of plant instrumentation and controls, plant protection, reactor pressure vessel (RPV) safety/relief valves (SRV), and reactor protection systems (RPS) unless stated otherwise. The bypass valve opening characteristics reflect the specified delay together with the specified opening characteristic required for bypass system operation.
Turbine control valve fast closure initiates a scram trip signal for power levels greater than 30% nuclear boiler rated (NBR). In addition, recirculation pump trip (RPT) is initiated. Both of these trip signals satisfy single failure criterion and credit is taken for these protection features.
The pressure relief system, which operates the SRVs independently when system pressure exceeds relief valve instrumentation setpoints is assumed to function normally during the time period analyzed.
15.2.2.2.2.2 Generator Load Rejection with Failure of Bypass. Same as Section 15.2.2.2.2.1 except that failure of the main turbine bypass valves is assumed for the entire transient. In addition, the pressure relief system, which operates the SRVs independently when system pressure exceeds relief valve instrumentation setpoints, fails to operate. Pressure relief is provided by the safety function of the SRVs.
15.2.2.2.3       The Effect of Single Failures and Operator Errors Mitigation of pressure increase, the basic nature of this transient, is accomplished by the RPS functions. Turbine control valve trip scram and RPT are designed to satisfy the single failure criterion. An evaluation of the most limiting single failure (i.e., failure of the bypass system) was considered in this event.
LDCN-07-011                                      15.2-5

COLUMBIA GENERATING STATION                            Amendment 63 FINAL SAFETY ANALYSIS REPORT                           December 2015 15.2.2.3       Core and System Performance 15.2.2.3.1      Mathematical Model 15.2.2.3.1.1 Generator Load Rejection with Bypass. The predicted dynamic behavior for the generator load reject with bypass valves operable has been determined using a computer simulated, analytical model of a generic direct-cycle BWR. This model is described in detail in Reference 15.2-4.
The nonlinear computer simulated analytical model is designed to predict associated transient behavior of the reactor. Some of the significant features of the model are the following:
: a.      A point kinetic model is assumed with reactivity feedbacks from control rods (absorption), voids (moderation), and Doppler (capture) effects.
: b.      The fuel is represented by three four-node cylindrical elements, each enclosed in a cladding node. One of the cylindrical elements is used to represent core average power and fuel temperature conditions, providing the source of Doppler feedback. The other two are used to represent hot spots in the core, to simulate peak fuel center temperature and cladding temperature.
: c.      Four primary system pressure nodes are simulated. The nodes represent the core exit pressure, vessel dome pressure, steam line pressure (at a point representative of the safety/relief valve location), and turbine inlet pressure.
: d.      The active core void fraction is calculated from a relationship between core exit quality, inlet subcooling, and pressure. This relationship is generated from multimode core steady-state calculations. A second-order void dynamic model, with the void boiling sweep time calculated as a function of core flow and void conditions, is also utilized.
: e.      Principal controller functions such as feedwater flow, recirculation flow, reactor water level, pressure and load demand are represented together with their dominant nonlinear characteristics.
: f.      The ability to simulate necessary reactor protection system functions is provided.
15.2.2.3.1.2 Generator Load Rejection with Bypass Failure. The predicted dynamic behavior for the load rejection with bypass inoperable has been determined using a computer simulated, analytical model of a direct-cycle BWR that is discussed in Section 15.1.2.3.1. This model is described in detail in Reference 15.2-10.
LDCN-15-011                                    15.2-6

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 15.2.2.3.2      Input Parameters and Initial Conditions These analyses have been performed, unless otherwise noted, with the plant conditions tabulated in Table 15.0-2 for the load rejection with bypass and in Table 15.0-2B for load rejection with bypass failure.
The turbine digital electrohydraulic control system power/load imbalance device detects load rejection before a measurable speed change takes place.
The closure characteristics of the TCVs are assumed such that the valves operate in the full arc (FA) mode and have a full stroke closure time, from fully open to fully closed, of 0.15 sec.
In FA mode, at 100% power, the TCVs are not fully open, so the analysis assumes a closure time that is a fraction of the full stroke time proportional to the TCV initial position.
15.2.2.3.3      Results Analyses were performed to analyze combinations of RPT operable/inoperable and Option A and Option B scram speeds (Reference 15.2-3). The excursion of core power due to void collapse is primarily terminated by reactor scram and void growth due to RPT.
15.2.2.3.3.1 Generator Load Rejection with Bypass. Figure 15.2-2.1 shows the results of the generator trip from original rated power. Peak neutron flux rises 156.8% above NBR conditions.
The average surface heat flux peaks at 102.9% of the initial value and minimum critical power ratio (MCPR) does not significantly decrease below its initial value.
15.2.2.3.3.2 Generator Load Rejection with Failure of Bypass. Figure 15.2-2.2 shows that, for the case of bypass failure, peak neutron flux reaches about 330% power. Results reflect GNF2 fuel introduction, some of which are dependent on fuel design and core loading pattern.
Compliance with the event acceptance criteria is demonstrated by cycle-dependent analysis of potentially limiting events just prior to the operation of that cycle. The results are reported in the Supplemental Reload Licensing Report (Reference 15.2-3). As discussed in Section 15.0.2.1, when this event is initiated during single loop operation, the consequences are less severe than the consequences analyzed for the two loop operation.
15.2.2.3.4      Consideration of Uncertainties The full stroke closure time of the TCV of 0.15 sec is conservative. Typically, the actual closure time is closer to 0.2 sec. The less time it takes to close, the more severe the pressurization effect.
LDCN-15-011                                     15.2-7

COLUMBIA GENERATING STATION                          Amendment 63 FINAL SAFETY ANALYSIS REPORT                         December 2015 All systems used for protection in this event were assumed to have the poorest allowable response. Expected plant behavior is, therefore, expected to reduce the actual severity of the transient.
15.2.2.4       Barrier Performance 15.2.2.4.1      Generator Load Rejection Peak pressure remains within normal operating range and no threat to the barrier exists.
15.2.2.4.2      Generator Load Rejection with Failure of Bypass The peak dome pressure reaches 1244 psig. The peak reactor coolant pressure boundary (RCPB) pressure reaches 1270 psig. The peak pressure remains well below the nuclear barrier transient pressure limit of 1375 psig.
15.2.2.5       Radiological Consequences While the consequences of this event do not result in fuel failures, the result includes the discharge of normal coolant activity to the suppression pool by means of safety/relief valve (SRV) operation. Since this activity is contained in the primary containment, there will be no exposure to the public. Since this event does not result in an uncontrolled release to the environment, the plant operator can choose to hold the activity in containment or filter the discharge prior to release to the environment when conditions permit in accordance with established requirements.
15.2.3      TURBINE TRIP 15.2.3.1       Identification of Causes and Frequency Classification 15.2.3.1.1      Identification of Causes A variety of turbine or nuclear system malfunctions will initiate a turbine trip. Some examples are moisture separator high levels, operator lockout, loss of control fluid pressure, low condenser vacuum, and reactor high water level.
15.2.3.1.2      Frequency Classification 15.2.3.1.2.1 Turbine Trip. This event is categorized as an incident of moderate frequency.
In defining the frequency of this event, turbine trips which occur as a by-product of other transients such as loss of condenser vacuum or reactor high level trip events are not included.
However, spurious low vacuum or high level trip signals which cause an unnecessary turbine trip are included in defining the frequency.
LDCN-15-011                                   15.2-8

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 15.2.3.1.2.2 Turbine Trip with Failure of Bypass. This transient disturbance is categorized as a moderate frequency incident.
15.2.3.2       Sequence of Events and Systems Operation 15.2.3.2.1      Sequence of Events 15.2.3.2.1.1 Turbine Trip. This transient is classified as a nonlimiting event for both original and uprated power conditions. Therefore, the original rated power (3323 MWt) analysis has not been updated. Turbine trip at high power produces the sequence of events listed in Table 15.2-4.
15.2.3.2.1.2 Turbine Trip with Failure of Bypass. Turbine trip at high power with bypass failure produces the sequence of events listed in Table 15.2-5.
15.2.3.2.2      Systems Operation 15.2.3.2.2.1 Turbine Trip. All plant control systems maintain normal operation unless specifically designated to the contrary.
Turbine stop (throttle) valve closure initiates a reactor scram trip by means of valve position signals to the protection system.
Turbine stop valve closure initiates RPT thereby terminating the jet pump drive flow.
The pressure relief system, which operates the relief valves independently when system pressure exceeds relief valve instrumentation setpoints, is assumed to function normally during the time period analyzed.
The severity of turbine trips from lower initial power levels decreases to the point where a scram can be avoided if auxiliary power is available from an external source and the power level is within the bypass capability.
15.2.3.2.2.2 Turbine Trip with Failure of Bypass. Same as Section 15.2.3.2.2.1 except that failure of the main turbine bypass system is assumed for the entire transient time period analyzed. During the transient the SRVs open and close sequentially as the stored energy is dissipated until the pressure falls below the valve setpoints.
15.2.3.2.2.3 Turbine Trip at Low Power with Failure of Bypass. Same as Section 15.2.3.2.2.1 except that failure of the main turbine bypass system is assumed.
LDCN-10-029                                    15.2-9

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 Below 30% NBR power level, a main stop valve scram trip inhibit signal derived from the first stage pressure of the turbine is activated. This is done to eliminate the stop valve scram trip signal from scramming the reactor provided the bypass system functions properly. In other words, the bypass would be sufficient at this low power to accommodate a turbine trip without the necessity of shutting down the reactor. All other protection system functions remain functional as before and credit is taken for those protection system trips.
15.2.3.2.3      The Effect of Single Failures and Operator Errors 15.2.3.2.3.1 Turbine Trips at Power Levels Greater Than 30% Nuclear Boiler Rated.
Mitigation of pressure increase, the basic nature of this transient, is accomplished by the RPS functions. Main stop valve closure scram trip and RPT are designed to satisfy single failure criterion.
15.2.3.2.3.2 Turbine Trips at Power Levels Less Than 30% Nuclear Boiler Rated. Same as Section 15.2.3.2.3.1 except RPT and stop valve closure scram trip is normally inoperative.
Since protection is still provided by high flux, high pressure, etc., these will continue to function and scram the reactor should a single failure occur.
15.2.3.3      Core and System Performance 15.2.3.3.1      Mathematical Model 15.2.3.3.1.1 Turbine Trip with Bypass. The predicted dynamic behavior for the turbine trip has been determined using a computer simulated, analytical model of a generic direct-cycle BWR, as discussed in Section 15.2.2.3.1. This model is described in detail in Reference 15.2-4.
15.2.3.3.1.2 Turbine Trip with Bypass Failure. The three-dimensional TRACG model described in Section 15.0.3.3.1 is used to simulate this event.
15.2.3.3.2      Input Parameters and Initial Conditions These analyses have been performed, unless otherwise noted, with plant conditions tabulated in Table 15.0-2 for the turbine trip with bypass and Table 15.0-2B for the turbine trip with bypass failure.
The turbine trip analysis was performed at the 105% of the original rated steam flow. The turbine trip with bypass failure was analyzed at an initial condition of 100% rated power (3486 MWt) and 106% rated core flow.
Turbine stop (throttle) valves full stroke closure time is 0.1 sec.
LDCN-15-011                                   15.2-10

COLUMBIA GENERATING STATION                           Amendment 63 FINAL SAFETY ANALYSIS REPORT                          December 2015 A reactor scram is initiated by position switches on the stop valves when the valves are 90%
open or less. This stop valve scram trip signal is automatically bypassed when the reactor is below 30% NBR power level.
Reduction in core recirculation flow is initiated by position switches on the main stop valves, which actuate trip circuitry which trips the recirculation pumps.
15.2.3.3.3      Results 15.2.3.3.3.1 Turbine Trip. The results of a turbine trip with the bypass system operating normally are shown in Figure 15.2-3.
Neutron flux increases rapidly because of the void reduction caused by the pressure increase.
However, the flux increase is limited to 147.5% of rated by the stop valve scram and the RPT system. Peak fuel surface heat flux does not exceed 101.7% of its initial value.
15.2.3.3.3.2 Turbine Trip with Failure of Bypass. The results of a turbine trip with failure of the bypass system are shown in Figure 15.2-4.
The peak neutron flux reaches 278% of its rated value, and peak surface heat flux reaches 111% of its initial value.
Results reflect GE14 fuel introduction, some of which are dependent on fuel design and core loading pattern. The event was analyzed for GNF2 introduction, however the results were not reported because the event was not limiting. Compliance with the event acceptance criteria is demonstrated by cycle-dependent analysis of potentially limiting events just prior to the operation of that cycle. The results are reported in the Supplemental Reload Licensing Report (Reference 15.2-3) if the event is limiting.
15.2.3.3.3.3 Turbine Trip with Bypass Valve Failure, Low Power. This transient is less severe than a similar one at high power. Below 30% of rated power, the turbine stop valve closure and TCV (governor valve) closure scrams are automatically bypassed. At these lower power levels, turbine first stage pressure is used to initiate the scram logic bypass. The scram which terminates the transient is initiated by high vessel pressure. The bypass valves are assumed to fail; therefore, system pressure will increase until the pressure relief setpoints are reached. At this time, because of the relatively low power of this transient event, relatively few relief valves will open to limit reactor pressure. Peak pressures are not expected to greatly exceed the pressure relief valve setpoints and will be significantly below the reactor coolant pressure boundary (RCPB) transient limit of 1375 psig. Peak surface heat flux and peak fuel center temperature remain at relatively low values and MCPR remains well above the GETAB safety limit.
LDCN-15-011                                   15.2-11

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.3.3.4      Considerations of Uncertainties Uncertainties in these analyses involve protection system settings, system capacities, and system response characteristics. In all cases, the most conservative values are used in the analyses. For example:
: a.      Slowest allowable control rod scram motion is assumed,
: b.      Scram worth shape for all-rod-out conditions is assumed,
: c.      Minimum specified valve capacities are utilized for overpressure protection, and
: d.      Setpoints of the SRVs include errors and uncertainties (high) for all valves.
15.2.3.4      Barrier Performance 15.2.3.4.1      Turbine Trip Peak pressure in the bottom of the vessel reaches 1163 psig, which is below the American Society of Mechanical Engineers (ASME) Code limit of 1375 psig for the RCPB. Vessel dome pressure does not exceed 1136 psig.
15.2.3.4.2      Turbine Trip with Failure of Bypass The peak steam line pressure reaches 1235 psig. The peak reactor coolant pressure boundary (RCPB) pressure reaches 1260 psig. The peak pressure remains well below the nuclear barrier transient pressure limit of 1375 psig.
15.2.3.4.2.1 Turbine Trip with Failure of Bypass at Low Power. Qualitative discussion is provided in Section 15.2.3.3.3.3.
15.2.3.5      Radiological Consequences The consequence of this event does not result in fuel failure. It does result in the discharge of normal coolant activity to the suppression pool by means of SRV operation, which is contained in the primary containment. This event does not result in an uncontrolled release to the environment, so the plant operator can choose to hold the activity in containment or discharge it when conditions permit. If purging of the containment is chosen, the release would be in accordance with established requirements.
15.2.4      MAIN STEAM LINE ISOLATION VALVE CLOSURES This transient is classified as a nonlimiting event for both original and uprated power conditions. Therefore, cycle specific analyses are not performed for this event. The analysis results presented in the section are based on uprated power conditions and a representative reload core (Cycle 8) as documented in Reference 15.2-5.
15.2-12

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.4.1      Identification of Causes and Frequency Classification 15.2.4.1.1      Identification of Causes Various steam line and nuclear system malfunctions, or operator actions, can initiate MSIV closure. Examples are low-steam line pressure, high-steam line flow, low-water level, or manual action.
15.2.4.1.2      Frequency Classification 15.2.4.1.2.1 Closure of All Main Steam Line Isolation Valves. This event is categorized as an incident of moderate frequency. To define the frequency of this event as an initiating event and not the byproduct of another transient, only the following contribute to the frequency:
Manual action (purposely or inadvertent); spurious signals such as low pressure, low reactor water level, and low condenser vacuum; and equipment malfunctions such as faulty valves or operating mechanisms. A closure of one MSIV may cause an immediate closure of all the other MSIVs depending on reactor conditions. If this occurs, it is also included in this category. During the MSIV closure, position switches on the valves provide a reactor scram when the valves in three or more main steam lines are less than 90% open (except for interlocks which permit proper plant startup). Protection system logic permits the test closure of one valve without initiating scram from the position switches.
15.2.4.1.2.2 Closure of One Main Steam Line Isolation Valve. This event is categorized as an incident of moderate frequency. One MSIV at a time may be manually closed for testing purposes. Operator error or equipment malfunction may cause a single MSIV to be closed inadvertently. If reactor power is greater than about 75% when this occurs, a high flux or high steam line flow condition may result in a scram. If all MSIVs close as a result of the single event, the event is considered as a closure of all MSIVs. The results presented for this event assume all MSIVs close as a result of an unspecified initiating event.
15.2.4.2      Sequence of Events and Systems Operation 15.2.4.2.1      Sequence of Events Table 15.2-6 lists the sequence of events for Figure 15.2-5. When the MSIVs reach their 85% open position, a reactor scram is initiated by the reactor protection system. The valve closure results in a system pressure increase which in turn results in a spike in reactor neutron flux. The reactor vessel pressure increase also results in an ATWS recirculation pump trip (RPT). As the pressure increases, the relief valves begin to open terminating the pressure increase.
15.2-13

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.4.2.2       Systems Operation 15.2.4.2.2.1 Closure of All Main Steam Line Isolation Valves. The MSIV closures initiate a reactor scram trip by means of position signals to the protection system. Credit is taken for successful operation of the protection system.
The pressure relief system which initiates opening of the relief valves when system pressure exceeds relief valve instrumentation setpoints is assumed to function normally during the time period analyzed.
All plant control systems maintain normal operation unless specifically designated to the contrary.
15.2.4.2.2.2 Closure of One Main Steam Line Isolation Valve. A closure of a single MSIV will not initiate a reactor scram by means of the position signal to the protection system. This is because the valve position scram trip logic is designed to accommodate single valve operation and testability during normal reactor operation at limited power levels. Credit is taken for the operation of the pressure and flux signals to initiate a reactor scram.
All plant control systems maintain normal operation unless specifically designated to the contrary.
15.2.4.2.3       The Effect of Single Failures and Operator Errors Mitigation of pressure increase is accomplished by initiation of the reactor scram by means of MSIV position switches and the protection system. Relief valves also operate to limit system pressure. All of these aspects are designed to single failure criterion and additional single failures would not alter the results of this analysis.
Failure of a single relief valve to open is not expected to have any significant effect. Such a failure is expected to result in less than a 5 psi increase in the maximum vessel pressure rise.
The peak pressure will still remain considerably below 1375 psig.
15.2.4.3        Core and System Performance 15.2.4.3.1       Mathematical Model The point-kinetics REDY model described in Section 15.0.3.3.1 is used to simulate these transient events.
15.2-14

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.4.3.2       Input Parameters and Initial Conditions It is assumed the closure of all MSIVs occurs with the plant operating at 106% of uprated power and 100% core flow. The input parameters are defined with the plant conditions tabulated in Table 15.0-2 for power uprate.
The MSIVs close in 3 to 5 sec. The worst case, the 3-sec closure time, is assumed in this analysis.
Position switches on the valves initiate a reactor scram when the valves are less than 90% open as described in Section 7.2 (85% is assumed in the analysis). Closure of these valves inhibits steam flow to the feedwater turbines terminating feedwater flow.
Valve closure indirectly causes a trip of the main turbine and generator.
Because of the loss of feedwater flow, water level within the vessel decreases sufficiently to initiate trip of the recirculation pump and to initiate the HPCS and RCIC systems.
15.2.4.3.3       Results 15.2.4.3.3.1 Closure of All Main Steam Line Isolation Valves. The reactor scram is initiated at 0.45 sec when the MSIVs reach 85% open position. The nuclear system relief valves begin to open at 3.08 sec after the start of isolation. The valves close sequentially as the stored heat is dissipated but continue to discharge the decay heat intermittently. Table 15.2-6 provides the sequence of events and Figure 15.2-5 depicts the plant parameters responses. Key transient peak values are presented in Table 15.0-1. This event is non-limiting in that the pressurization event and change in CPR margin is less severe than the Generator Load Rejection with Bypass Failure and Turbine Trip with Bypass Failure events.
15.2.4.3.3.2 Closure of One Main Steam Line Isolation Valve. Only one isolation valve is permitted to be closed at a time for testing purposes to prevent scram. Normal test procedure requires an initial power reduction to approximately 65% to 70% of design conditions to avoid high-flux scram, high-pressure scram, or full isolation from a high-steam flow condition in the open steam lines. With a 3-sec closure of one MSIV during 105% of original rated power conditions, the steam flow disturbance raises vessel pressure and reactor power enough to initiate a high neutron flux scram. This transient is considerably milder than closure of all MSIVs at full power. No quantitative analysis is furnished for this event. No significant change in thermal margins is experienced and no fuel damage occurs. Peak pressure remains below SRV setpoints.
Inadvertent closure of one or all of the isolation valves while the reactor is shut down will produce no significant transient. Closures during plant heatup will be less severe than the maximum power cases (maximum stored and decay heat).
15.2-15

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.4.3.4      Considerations of Uncertainties Uncertainties in these analyses involve protection system settings, system capacities, and system response characteristics. In all cases, the most conservative values are used in the analyses. For example:
: a.      Slowest allowable control rod scram motion is assumed,
: b.      Scram worth shape for all-rod-out conditions is assumed,
: c.      Minimum specified valve capacities are used for overpressure protection, and
: d.      Setpoints of the SRVs are assumed to be 15 psi higher than the valves nominal setpoint.
15.2.4.4       Barrier Performance 15.2.4.4.1      Closure of All Main Steam Line Isolation Valves The nuclear system relief valves begin to open at approximately 3.1 sec after the start of isolation. The valves close sequentially as the stored heat is dissipated but continue to discharge the decay heat intermittently. Peak pressure at the vessel bottom reaches 1234 psig, clearly below the pressure limits of the RCPB. Peak pressure in the main steam line is 1198 psig.
15.2.4.4.2      Closure of One Main Steam Line Isolation Valve No significant effect is imposed on the RCPB, since if closure of the valve occurs at a high operating power level a flux or pressure scram will result. The main turbine bypass system will continue to regulate system pressure by means of the other three steam lines.
15.2.4.5       Radiological Consequences While the consequence of this event does not result in fuel failure, it does result in the discharge of normal coolant activity to the suppression pool via SRV operation. Since this activity is contained in the primary containment, there will be no exposure to the public. Since this event does not result in an uncontrolled release to the environment, the plant operator can choose to hold the activity in containment or discharge it to the environment when conditions permit. If purging of the containment is chosen, the release would be in accordance with established requirements.
15.2-16

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.5       LOSS-OF-CONDENSER VACUUM This transient is classified as a nonlimiting event for both original and uprated power conditions. Therefore, cycle specific analyses are not performed for this event. The analysis results presented in the section are based on uprated power conditions and a representative reload core (Cycle 8) as documented in Reference 15.2-5.
15.2.5.1       Identification of Causes and Frequency Classification 15.2.5.1.1      Identification of Causes Various malfunctions can cause a loss-of-condenser vacuum. The causes and estimated vacuum decay rates include failure or isolation of steam jet air ejectors (<1 in. Hg/mm), loss of sealing steam shaft gland seals (1 to 2 in. Hg/minute), opening of vacuum breaker valves (2 to 12 in. Hg/minute), and loss of one or more circulating water pumps (4 to 24 in. Hg/minute).
15.2.5.1.2      Frequency Classification This event is categorized as an incident of moderate frequency.
15.2.5.2       Sequence of Events and Systems Operation 15.2.5.2.1      Sequence of Events Table 15.2-7 lists the sequence of events for Figure 15.2-6.
15.2.5.2.2      Systems Operation It is conservatively assumed that condenser vacuum is lost at a rate of 2 inches of Hg per second. The bypass system is signaled to close approximately 10 inches of Hg less than the stop (throttle) valve closure vacuum setpoint level which means the bypass is available for approximately 5 sec before the turbine stop (throttle) valves close. The loss of vacuum initiates a main turbine trip and feedwater turbine trip. Upon reaching 90% close, the turbine throttle (stop) valves closure results in a reactor scram. As the reactor pressure increases, the relief valves will open. Subsequently, this results in the main steam line isolation valves to close. However, the effect of the MSIV closure is minimal since the turbine stop (throttle) valve and bypass valve closure have already terminated main steam line flow.
Tripping functions incurred by sensing main turbine condenser vacuum are designated in Table 15.2-8.
15.2-17

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.5.2.3      The Effect of Single Failures and Operator Errors Single failure will not effect the vacuum monitoring and turbine trip devices which are redundant. The protective sequences of the anticipated operational transient are shown to be single failure proof.
15.2.5.3       Core and System Performance 15.2.5.3.1      Mathematical Model The one-dimensional ODYN model described in Section 15.0.3.3.1 was used to simulate this transient event.
15.2.5.3.2      Input Parameters and Initial Conditions This analysis was performed with plant conditions tabulated in Table 15.0-2 and at 104.1% of uprated power and 100% core flow. Turbine stop (throttle) valves full stroke closure time used in this analysis is 0.1 second and a reactor scram is initiated by position switches on the stop valves when the valves are less than 90% open. The 2 inches of Hg per second assumed in the analysis is conservative with respect to normal loss of vacuum and no operator actions are assumed.
Thus, the bypass system is available for several seconds since the bypass is signaled to close at a vacuum level of about 10 in. Hg less than the stop valve closure.
15.2.5.3.3      Results The loss of condenser vacuum initiates a main turbine trip, which then initiates turbine bypass operation. The bypass is available for approximately 5 sec until both the turbine bypass valves and the main steam line isolation valves receive a signal to close on low condenser vacuum.
The effect of MSIV closure tends to be minimal since the closure of main turbine stop valves and subsequently the bypass valves have already shut off the main steam line flow.
Figure 15.2-6 shows the transient expected for this event. It is assumed that the plant is initially operating at 105% of uprated NBR steam flow conditions. Peak neutron flux reaches 256% of NBR power while average fuel surface heat flux reaches 111% of rated value. The SRVs open to limit the pressure rise then sequentially reclose as the stored energy is dissipated.
15.2.5.3.4      Consideration of Uncertainties The reduction or loss of vacuum in the main turbine condenser will sequentially trip the main and feedwater turbines and close the MSIVs and turbine bypass valves. While these are the major events occurring, other resultant actions will include scram (from stop valve closure) 15.2-18

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                        December 2011 and bypass opening with the main turbine trip. Because the protective actions are actuated at various levels of condenser vacuum, the severity of the resulting transient is dependent upon the rate at which the vacuum is lost. Normal loss of vacuum due to loss-of-cooling water pumps or steam jet air ejector problem produces a very slow rate of loss of vacuum (minutes, not seconds). If corrective actions by the reactor operators are not successful, then simultaneous trips of the main and feedwater turbines, and ultimately complete isolation by closing the bypass valves (opened with the main turbine trip) and the MSIVs, will occur.
A faster rate of loss of the condenser vacuum would reduce the anticipatory action of the scram and the overall effectiveness of the bypass valves since they would be closed more quickly.
Other uncertainties in these analyses involve protection system settings, system capacities, and system response characteristics. In all cases, the most conservative values are used in the analyses. For example:
: a.       Slowest allowable control rod scram motion is assumed,
: b.       Scram worth shape for all-rod-out conditions is assumed,
: c.       Minimum specified valve capacities are utilized for overpressure protection, and
: d.       Setpoints of the SRVs are assumed to be 15 psi higher than the valves nominal setpoint.
15.2.5.4        Barrier Performance The maximum calculated pressure for this event as presented in Table 15.0-1 is below the ASME Code limit of 1375 psig for the RCPB and the ASME Service Level C of 1500 psig.
The consequences of this event do not result in any temperature or pressure transient in excess of the criteria for which the fuel, pressure vessel, or containment are designed. Therefore, barrier integrity and function is maintained.
15.2.5.5        Radiological Consequences While the consequence of this event does not result in fuel failures, it does result in the discharge of normal coolant activity to the suppression pool by means of SRV operation. Since this activity is contained in the primary containment, there will be no exposure to the public.
Since this event does not result in an uncontrolled release to the environment, the plant operator can choose to hold the activity in containment or discharge it to the environment when conditions permit. If purging of the containment is chosen, the release would be in accordance with established requirements.
15.2-19

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.6      LOSS OF ALTERNATING CURRENT POWER This transient considers the loss of AC power to the plant from both an onsite cause (loss of auxiliary power transformer) and an offsite cause (loss of all grid connections).
This transient is classified as a nonlimiting event for both original and uprated power conditions. Therefore, cycle specific analyses are not performed for this event. The analysis results presented in the section are based on uprated power conditions and a representative reload core (Cycle 8) as documented in Reference 15.2-5.
15.2.6.1       Identification of Causes and Frequency Classification 15.2.6.1.1      Identification of Causes 15.2.6.1.1.1 Loss of Auxiliary Power Transformers. Causes for interruption or loss of the auxiliary power transformers can arise from normal operation or malfunctioning of transformer protection circuitry. These can include high transformer oil temperature, reverse of high current operation, and operator error which trips the transformer breakers.
15.2.6.1.1.2 Loss of All Grid Connections. Loss of all grid connections can result from major shifts in electrical loads, loss of loads, lightning, storms, wind, etc., which contribute to electrical grid instabilities. These instabilities will cause equipment damage if unchecked.
Protective relay schemes automatically disconnect electrical sources and loads to mitigate damage and regain electrical grid stability.
15.2.6.1.2      Frequency Classification 15.2.6.1.2.1 Loss of Auxiliary Power Transformers. This event is categorized as an incident of moderate frequency.
15.2.6.1.2.2 Loss of All Grid Connections. This event is categorized as an incident of moderate frequency.
15.2.6.2       Sequence of Events and Systems Operation 15.2.6.2.1      Sequence of Events 15.2.6.2.1.1 Loss of Auxiliary Power Transformers. Table 15.2-9 lists the sequence of events for Figure 15.2-7.
15.2.6.2.1.2 Loss of All Grid Connections. Table 15.2-10 lists the sequence of events for Figure 15.2-8.
15.2-20

COLUMBIA GENERATING STATION                         Amendment 61 FINAL SAFETY ANALYSIS REPORT                        December 2011 15.2.6.2.2      Systems Operation 15.2.6.2.2.1 Loss of Auxiliary Power Transformers. This event, unless otherwise stated, assumes and takes credit for normal functioning of plant instrumentation and controls, plant protection, and reactor protection systems.
The reactor is subjected to a complex sequence of events when the plant loses all auxiliary power. Estimates of the responses of the various reactor systems (assuming loss of the auxiliary transformers) provide the following simulation sequence:
: a.      Recirculation pumps and condenser circulatory water pumps trip off at time = 0. A 4 sec recirculation pump trip inertia time constant is assumed for this analysis;
: b.      Reactor scram and MSIV closure is initiated at 2 sec due to loss of power to the scram and MSIV relay solenoids; and
: c.      Feedwater turbines trip off at 4 sec due to MSIV closure at 2 sec.
Operation of the HPCS and RCIC are not simulated in this analysis. Their operation occurs at a time beyond the primary concerns of fuel thermal margin and overpressure effects of this analysis.
15.2.6.2.2.2 Loss of All Grid Connections. Same as Section 15.2.6.2.2.1 with the following additional concern.
The loss of all grid connections would add a generator load rejection to the above sequence at time, t=0. The load rejection immediately causes the TCVs (governor valves) to close, causes a scram, and initiates RPT [already tripped at reference time t = 0].
15.2.6.2.3      The Effect of Single Failures and Operator Errors Loss of the auxiliary power transformers in general leads to a reduction in power level due to rapid pump coastdown with pressurization effects due to MSIV closure resulting from loss of power to the solenoids. Additional failures of the other systems assumed to protect the reactor would not result in an effect different from those reported. Failures of the protection systems have been considered and satisfy single failure criteria and, as such, no change in analyzed consequences is expected.
15.2-21

COLUMBIA GENERATING STATION                        Amendment 61 FINAL SAFETY ANALYSIS REPORT                       December 2011 15.2.6.3      Core and System Performance 15.2.6.3.1     Mathematical Model The point-kinetics REDY model described in Section 15.0.3.3.1 was used to simulate this event.
15.2.6.3.2     Input Parameters and Initial Conditions 15.2.6.3.2.1 Loss of Auxiliary Power Transformers. It is assumed the loss of the auxiliary power transformer occurs with the plant operating at 106% of uprated power and 100% core flow. The input parameters are defined with the plant conditions tabulated in Table 15.0-2 except as noted below.
: a.      The recirculation pump trip inertia time constant is 4 sec.
: b.      The relay-type Reactor Trip System (RTS) circuitry generates a reactor scram and Main Steam Isolation Valves (MSIV) closure signal due to loss of power to the scram and MSIV solenoids. This occurs 2 sec after the loss of offsite power.
: c.      The feedwater pumps trip due to MSIV closure 2 sec after the MSIV begin to close as a result of the loss of power to the MSIV solenoids.
15.2.6.3.2.2 Loss of All Grid Connections. It is assumed the loss of all grid connections occurs with the plant operating at 104% of uprated power and 100% core flow. The input parameters are defined with the plant conditions tabulated in Table 15.0-2 except as noted below.
: a.      The recirculation pump trip inertia time constant is 4 sec.
: b.      The relay-type Reactor Trip System (RTS) circuitry generates a Main Steam Isolation Valves (MSIV) closure signal due to loss of power to the MSIV solenoids. This occurs 2 sec after the loss of offsite power.
: c.      The feedwater pumps trip due to MSIV closure 2 sec after the MSIV begin to close as a result of the loss of power to the MSIV solenoids.
15.2.6.3.3     Results 15.2.6.3.3.1 Loss of Auxiliary Power Transformers. Initially the offsite power is cutoff causing both recirculation pumps to trip. The loss of power to the scram and MSIV solenoids causes a reactor scram, MSIV isolation and a feedwater pump trip 2 sec after the MSIV 15.2-22

COLUMBIA GENERATING STATION                            Amendment 61 FINAL SAFETY ANALYSIS REPORT                           December 2011 isolation. Subsequently, the feedwater recirculation valves trip and the relief valves begin to open due to the rising pressure caused by the main steam line isolation. Table 15.2-9 provides the sequence of events and Figure 15.2-7 depicts the plant parameters responses. Key transient peak values are presented in Table 15.0-1. This event is non-limiting in that the pressurization event and change in MCPR margin are less severe than the Generator Load Rejection with Bypass Failure and Turbine Trip with Bypass Failure events.
15.2.6.3.3.2 Loss of All Grid Connections. Loss of all grid connections is a more general form of loss of auxiliary power. It essentially takes on the characteristic response of the standard full load rejection discussed in Section 15.2.2. Initially the offsite power is cutoff to the grid causing the turbine-generator to detect a loss of electrical load, and a power-load unbalance. The turbine generator overspeed protection control (OPC) initiates a control (governor) valve fast closure, turbine bypass valves opening and a reactor scram. At the same time both recirculation pump motors trip. Subsequently, MSIV isolation occurs and both feedwater pumps trip. The rising pressure due to the isolation of the steam line causes the relief valves to open. Table 15.2-10 provides the sequence of events and Figure 15.2-8 depicts the plant parameter responses. Key transient peak values are presented in Table 15.0-1. This event is non-limiting in that the pressurization event and change in MCPR margin are less severe than the Generator Load Rejection with Bypass Failure and Turbine Trip with Bypass Failure events.
15.2.6.3.4      Consideration of Uncertainties The most conservative characteristics of protection features are assumed. Any actual deviations in plant performance are expected to make the results of this event less severe.
Operation of the HPCS and RCIC systems are not included in the simulation of the first 50 sec of this transient. Startup of the pumps occurs in the latter part of this time period but the system has no significant effect on the results of this transient.
Following main steam line isolation and prior to RHR initiation the reactor pressure is expected to increase until the SRV setpoints are reached. During this time the valves operate in a cyclic manner to discharge decay heat to the suppression pool.
15.2.6.4       Barrier Performance 15.2.6.4.1      Loss of Auxiliary Power Transformers Safety/relief valves open in the pressure relief mode of operation as the pressure increases beyond their setpoints. The pressure in the dome is limited to a maximum value of 1169 psig well below the vessel pressure limit of 1375 psig.
15.2-23

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.6.4.2      Loss of All Grid Connections Safety/relief valves open in the pressure relief mode of operation as the pressure increases beyond their setpoints. The pressure in the dome is limited to a maximum value of 1173 psig well below the vessel pressure limit of 1375 psig.
15.2.6.5       Radiological Consequences The consequence of this event does not result in fuel failure. It does result in the discharge of normal coolant activity to the suppression pool by means of SRV operation, which is contained in the primary containment. This event does not result in an uncontrolled release to the environment, so the plant operator can choose to hold the activity in containment or discharge it when conditions permit. If purging of the containment is chosen, the release would be in accordance with established requirements.
15.2.7      LOSS-OF-FEEDWATER FLOW This transient is classified as a nonlimiting event for both original and uprated power conditions. Therefore, cycle specific analyses are not performed for this event. The analysis results presented in the section are based on uprated power conditions and a representative reload core (Cycle 8) as documented in Reference 15.2-5. The analysis has not been updated for the change in MSIV isolation setpoint from Level 2 to Level 1 because the analysis is bounding and conclusions of the analysis are not affected (Reference 15.2-8).
15.2.7.1       Identification of Causes and Frequency Classification 15.2.7.1.1      Identification of Causes A loss of feedwater flow could occur from pump failures, feedwater controller failures, operator errors, or reactor system variables such as a high vessel water level (L8) trip signal.
15.2.7.1.2      Frequency Classification This event is categorized as an incident of moderate frequency.
15.2.7.2       Sequence of Events and Systems Operation 15.2.7.2.1      Sequence of Events Feedwater flow terminates at approximately 5 sec. Subcooling decreases causing a reduction in core power level and pressure. As power level is lowered, the turbine steam flow starts to drop off. Water level continues to drop until the vessel level (L3) scram trip setpoint is reached, whereupon the reactor is shut down.
LDCN-09-007                                    15.2-24

COLUMBIA GENERATING STATION                            Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 Main steam line isolation initiation occurs due to vessel water dropping to the L2 trip. Also at this time, the recirculation system is tripped and HPCS and RCIC operation is initiated.
Operation of the HPCS and RCIC systems is not included in the simulation of the first 50 seconds of this transient since startup of the pumps occurs in the latter part of this time period. Therefore, the system has no significant effects on the results of this transient.
Table 15.2-11 lists the sequence of events for Figure 15.2-9.
15.2.7.2.2      Systems Operation Loss of feedwater flow results in a proportional reduction of vessel inventory causing the vessel water level to drop. The first corrective action is the low level (L3) scram trip actuation. Reactor protection system responds after this trip to scram the reactor. The low level (L3) scram trip function meets single failure criterion.
Vessel water level (L2) trip initiates main steam line isolation, recirculation pump trip and HPCS/RCIC system operation (not simulated). The recirculation pump motor circuit breakers then open causing decrease in core flow to natural circulation.
15.2.7.2.3      The Effect of Single Failures and Operator Errors The nature of this event results in a lowering of vessel water level. Key corrective efforts to shut down the reactor are automatic and designed to satisfy single failure criterion. Therefore, any additional failure in these shutdown methods would not aggravate or change the simulated transient.
The potential exists for a single relief valve failing to close once it is opened. This would result in a complete depressurization of the reactor. Either the RCIC or the HPCS system is capable of maintaining adequate core coverage and will provide long-term inventory control.
For the complete loss of feedwater flow event, operation of RCIC or HPCS is sufficient to avoid initiation of ADS on low vessel level (L1).
15.2.7.3       Core and System Performance 15.2.7.3.1      Mathematical Model The point-kinetics REDY model described in Section 15.0.3.3.1 was used to simulate this event.
15.2-25

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 15.2.7.3.2      Input Parameters and Initial Conditions The simultaneous trip of both feedwater pumps is assumed to occur while the plant is operating at 106% uprated power and 100% core flow. These analyses have been performed, unless otherwise noted, with plant conditions tabulated in Table 15.0-2.
15.2.7.3.3      Results Table 15.2-11 provides the sequence of events and Figure 15.2-9 depicts the plant parameter responses. Key transient peak values are presented in Table 15.0-1. This event is non-limiting in that the pressurization event and change in MCPR are less severe than the Generator Load Rejection with Bypass Failure and Turbine Trip with Bypass Failure events.
15.2.7.3.4      Consideration of Uncertainties End-of-cycle scram characteristics are assumed.
This transient is most severe from high power conditions, because the rate of level decrease is greatest and the amount of stored decay heat to be dissipated is highest.
15.2.7.4       Barrier Performance Peak pressure in the bottom of the vessel reaches 1152 psig, which is below the ASME Code limit of 1375 psig for the RCPB. Vessel dome pressure does not exceed 1142 psig. The consequences of this event do not result in any temperature or pressure transient in excess of the criteria for which the fuel, pressure vessel, or containment are designed. Therefore, barrier integrity and function are maintained.
15.2.7.5       Radiological Consequences The consequence of this event does not result in fuel failure. It does result in the discharge of normal coolant activity to the suppression pool by means of SRV operation, which is contained in the primary containment. This event does not result in an uncontrolled release to the environment, so the plant operator can choose to hold the activity in containment or discharge it when conditions permit. If purging of the containment is chosen the release will be in accordance with established requirements.
15.2.8      FEEDWATER LINE BREAK See Section 15.6.6.
15.2-26

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.9       FAILURE OF RESIDUAL HEAT REMOVAL SHUTDOWN COOLING This transient is classified as a nonlimiting event for both original and uprated power conditions.
Normally, in evaluating component failures associated with the RHR shutdown cooling mode of operation, active pumps or instrumentation (all of which are redundant for the safety related portions of the RHR system) would be assumed to be the component failure. For purposes of a worst case analysis, a valve on the single recirculation suction line to the otherwise redundant RHR shutdown cooling loops is assumed to fail. Manual attempts to open the valve are assumed unsuccessful. Discovery is conservatively assumed to occur at 100 psig. This envelops discovery at normal RHR shutdown cooling operating limits (see Section 5.4.7).
This failure disables the shutdown cooling mode but does not affect the remaining RHR modes of operation. Reference 15.2-1 establishes additional assumptions.
15.2.9.1        Identification of Causes and Frequency Classification 15.2.9.1.1       Identification of Causes The plant is operating at 105% of original NBR steam flow when an event occurs, e.g., a long-term loss of offsite power, causing a plant shutdown. Reactor vessel depressurization is initiated to bring the reactor pressure to approximately 100 psig. Concurrent with the loss of offsite power a failure of a valve in the shutdown cooling suction line occurs which prevents the operator from establishing the normal shutdown cooling path through the RHR shutdown cooling lines. An additional failure is assumed which completely disables the RHR equipment in one division. The operator then establishes a shutdown cooling path for the vessel through the SRV valves.
15.2.9.1.2       Frequency Classification This event is categorized as an incident of moderate frequency.
15.2.9.2        Sequence of Events and Systems Operation 15.2.9.2.1       Sequence of Events The sequence of events for this event is shown in Table 15.2-12.
15.2-27

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 15.2.9.2.1.1 Identification of Operator Actions. For the early part of the transient, the operator actions are to restore and maintain reactor water level. The operator should reestablish reactor cooling by one or more of the following:
: a.      Maintain reactor water inventory with the RCIC (when single failure is not assumed to be a loss of Division 1 dc power) and HPCS systems,
: b.      At approximately 10 minutes into the transient, initiate suppression pool cooling, it is assumed that only one RHR heat exchanger is available,
: c.      Initiate RPV shutdown depressurization by manual actuation of the SRVs,
: d.      Attempts to open one of the two RHR shutdown cooling suction valves are assumed unsuccessful (reactor pressure is approximately 100 psig), and
: e.      Continue RPV depressurization by opening SRVs and establish a reactor cooling path as described in the notes for Figure 15.2-10.
Time required to initiate the necessary steps to maintain reactor pressure and level control is approximately 10 minutes.
15.2.9.2.2      Systems Operation Plant instrumentation and control is assumed to be functioning normally except as noted. In this evaluation credit is taken for the plant and reactor protection systems and/or the ESF used.
15.2.9.2.3      The Effect of Single Failures and Operator Errors The worst case single failure (loss of division power) has already been analyzed in this event.
Therefore, no single failure or operator error can increase the consequences of this event.
15.2.9.3       Core and System Performance The earliest time the shutdown cooling system can be actuated is 2 to 3 hr after shutdown is initiated. During this time MCPR remains high and nucleate boiling heat transfer is not exceeded at any time. Therefore, the core thermal safety margin remains essentially unchanged. The 10-minute time period approximated for operator action is an estimate of how long it would take the operator to initiate the necessary actions. It is not a time by which action must be initiated.
The transient behavior of the core during this event has been evaluated in Section 15.2.6.
15.2-28

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 15.2.9.4       Results For most single failures that could result in loss of shutdown cooling, no unique safety actions are required. In these cases, shutdown cooling is simply reestablished using the redundant shutdown cooling loop. In cases where the RHR shutdown cooling suction line valves cannot be opened, alternate paths are available to accomplish the shutdown cooling function (Figure 15.2-11). An evaluation has been performed assuming a failure that disables the RHR shutdown cooling suction line valves.
This evaluation demonstrates the capability to safely transfer fission product decay heat and other residual heat from the reactor core at a rate such that specified acceptable fuel design limits and the design conditions of the RCPB are not exceeded.
The alternate cooldown path chosen to accomplish the shutdown cooling function uses the RHR and ADS or normal relief valve systems (see Reference 15.2-1 and Figure 15.2-10).
The alternate shutdown systems are capable of performing the function of transferring heat from the reactor to the environment using only safety systems. The systems are capable of bringing the reactor to a cold shutdown in approximately 36 hr or less after the transient occurs.
The systems have suitable redundancy in components such that even for onsite electrical power operation (offsite power is not available), the safety function of the systems can be accomplished assuming an additional single failure. The systems can be fully operated from the main control room.
The design evaluation is divided into two phases: (a) full power operation to approximately 100 psig vessel pressure, and (b) approximately 100 psig vessel pressure to cold shutdown (14.7 psia 200&deg;F) conditions.
15.2.9.4.1      Full Power to Approximately 100 psig Independent of the event that initiated plant shutdown (whether it be a normal plant shutdown or a forced plant shutdown), the reactor is normally brought to approximately 100 psig using either the main condenser or, in the case where the main condenser is unavailable, the HPCS and RCIC systems together with the nuclear boiler pressure relief system and the RHR heat exchanger in the suppression pool cooling mode.
For evaluation purposes, however, it is assumed that plant shutdown is initiated by a transient event (loss of offsite power) which results in relief valve actuation and subsequent suppression pool heatup. For this postulated condition, the reactor is shut down and the reactor vessel pressure is reduced to approximately 100 psig. Manual operation of the SRVs is used to depressurize the reactor vessel. Reactor vessel makeup water is automatically provided by means of the RCIC (until reduced vessel pressure is reached) and HPCS systems. While in 15.2-29

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 this condition, the RHR system (suppression pool cooling mode) is used to maintain the suppression pool temperature within shutdown limits.
These systems are designed to routinely perform their functions for both normal and forced plant shutdown. Since the HPCS and RHR systems are divisionally separated and the HPCS and RCIC systems are divisionally separated, no single failure together with the loss of offsite power, is capable of preventing reaching the 100 psig level.
15.2.9.4.2       Approximately 100 psig to Cold Shutdown The following assumptions are used for the analyses of the procedures for attaining cold shutdown from a pressure of approximately 100 psig:
: a.      The vessel is at 100 psig and saturated conditions,
: b.      A worst-case single failure is assumed to occur (i.e., loss of a division of emergency power), and
: c.      There is no offsite power available.
In the event that the RHRs shutdown suction line is not available because of single failure, the first action to be taken will be to control reactor pressure. If a single electrical failure caused the suction line to fail in the closed position, a hand wheel is provided on the valve to allow manual operation. If for some reason the normal shutdown cooling suction line cannot be restored to service, the capabilities described below will satisfy the normal shutdown cooling requirements and thus fully comply with GDC 34.
The RHR shutdown cooling line valves are in two divisions (Division 1 - the outboard valve, and Division 2 - the inboard valve) to satisfy containment isolation criteria. For evaluation purposes, the worst-case failure is assumed to be the loss of a division of emergency power, since this also prevents electrical actuation of one shutdown cooling line valve. Engineered safety features equipment and safe shutdown RCIC equipment (until reduced reactor pressure is reached) available for accomplishing the shutdown cooling function include (for the selected path):
ADS (dc Division 1 and dc Division 2)
RHR Loop A (Division 1)
HPCS (Division 3) 15.2-30

COLUMBIA GENERATING STATION                          Amendment 61 FINAL SAFETY ANALYSIS REPORT                         December 2011 RCIC (dc Division 1)
LPCS (Division 1)
Since availability or failure of Division 3 equipment does not affect the normal shutdown mode, normal shutdown cooling is easily available through equipment powered from only Divisions 1 and 2. It should be noted that, HPCS is always available for coolant injection if either of the other two divisions fails. For failure of Division 1 or 2, the following systems are assumed functional:
: a.      Division 1 Fails, Division 2 and 3 Functional Failed Systems         Functional Systems RHR Loop A             HPCS LPCS                   ADS RCIC                   RHR Loops B and C Assuming the single failure is a failure of Division 1 emergency power, the safety function is accomplished by establishing one of the cooling loops described in Activity C1 of Figure 15.2-10.
: b.      Division 2 Fails, Division 1 and 3 Functional Failed Systems         Functional Systems RHR Loop B and C HPCS ADS RHR Loop A LPCS RCIC (until reduced reactor pressure is reached)
Assuming the single failure is the failure of Division 2, the safety function is accomplished by establishing one of the cooling loops described in Activity C2 of Figure 15.2-10.
Figures 15.2-12 through 15.2-15 show RHR loops A, B, and/or C (simplified).
15.2.9.4.3      Temperature Response - 3462 MWt The reactor vessel temperature and pressure response versus time for the core conditions defined in Table 15.2-13 (105% of original rated steam flow, 3462 MWt rated power) are presented in Figures 15.2-16 and 15.2-17. Figure 5.2-16 presents the results for 15.2-31

COLUMBIA GENERATING STATION                            Amendment 61 FINAL SAFETY ANALYSIS REPORT                          December 2011 Activity C1.b.1 or C2 described in Figure 15.2-10. Figure 5.2-17 presents the results for Activity C1.b.2. The bulk suppression pool temperature responses from the same analysis are presented in Figures 15.2-18 and 15.2-19. Figure 5.2-18 presents the results for Activity C1.b.1 or C2 and Figure 5.2-19 presents the results for Activity C1.b.2.
15.2.9.4.4      Temperature Response - 3702 MWt Reference 15.2-7 analyzed the same two scenarios (Activities C2 and C1.b.2) for 106.2% of power uprate conditions (3702 MWt) to determine the peak bulk suppression pool temperature and the time required to cool the reactor vessel to cold shutdown (14.7 psia and 200&deg;F). The analysis at power uprate conditions calculated a relative 4&deg;F increase in the peak bulk pool temperature due to the power uprate. However, the peak temperature calculated was lower than the temperatures presented in this section due to the use of more realistic assumptions.
These assumptions include a more realistic decay heat model, lower initial suppression pool temperature (90&deg;F), and more realistic treatment of pump heat addition.
15.2.9.5       Barrier Performance As noted above, the consequences of this event do not result in any temperature or pressure transient in excess of the criteria for which the fuel, pressure vessel, or containment are designed. Release of coolant to the containment occurs by means of SRV actuation.
15.2.9.6       Radiological Consequences The consequence of this event does not result in fuel failure. It does result in the discharge of normal coolant activity to the suppression pool by means of SRV operation, which is contained in the primary containment. This event does not result in an uncontrolled release to the environment, so the plant operator can choose to hold the activity in containment or discharge it when conditions permit. If purging of the containment is chosen, the release would be in accordance with established requirements.
15.2.10     REFERENCES 15.2-1          Letter - R. S. Boyd to I. F. Stuart; dated November 12, 1975. 

==Subject:==

Requirements delineated for RHRS - Shutdown Cooling System - Single Failure Analysis.
15.2-2          NEDC-24154-P-A, Qualification of the One-Dimensional Core Transient Model for Boiling Water Reactors, Volumes 1, 2, 3 and 4, February 2000.
15.2-3          Supplemental Reload Licensing Report for Columbia (most recent version referenced in COLR).
15.2-32

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                       December 2015 15.2-4      R. B. Linford, Analytical Methods of Plant Transient Evaluations for the General Electric Boiling Water Reactor, NEDO 10802, April 1973.
15.2-5      For Power Uprate: GE Nuclear Energy, WNP-2 Power Uprate Transient Analysis Task Report, GE-NE-208-08-0393, September 1993 (Proprietary).
15.2-6      Deleted.
15.2-7      GE Nuclear Energy, WNP-2 Power Uprate Project NSSS Engineering Report, GE-NE-208-17-0993, Revision 1, December 1994 (Proprietary).
15.2-8      AREVA NP, Inc., Columbia Generating Station MSIV Closure Level Setpoint Change - Loss of Feedwater Flow Transient Analysis, 51-9084418-000, July 2008.
15.2-9      GE Hitachi Nuclear Energy, License Amendment Request for Proposed Changes to Columbia Technical Specifications: Changing Group 1 Isolation Valves Low Reactor Water Level Isolation Signal from the Current Level 2 to Level 1, 0000-0081-6730-R1, July 2008.
15.2-10     NEDE-32906P-A, TRACG Application for Anticipated Operational Occurrences Transient Analyses, Revision 3, September 2006.
LDCN-15-011                             15.2-33

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                        December 2011 Table 15.2-1 Sequence of Events for Figure 15.2-1 Pressure Regulator Failure - Closed 104.1% Uprated Power - 106% Flow Time (sec)                                Event 0        Failure of the pressure regulator causes closure of the turbine control valves.
1.0      Scram signal initiated at high neutron flux.
2.0      Recirculation pump motor circuit breakers open causing decrease in core flow to the natural circulation.
2.56     Group 3 relief valves actuated.
2.67     Group 4 relief valves actuated.
2.77     Group 5 relief valves actuated.
2.84     Turbine control valves close.
15.2-35

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                       December 2011 Table 15.2-2 Sequence of Events for Figure 15.2-2.1 Generator Load Rejection with Bypass On Original Rated Power Time (sec)                                    Event
(-)0.015a    Turbine generator detection of loss of electrical load.
0         Turbine generator overspeed protection control (OPC) devices trip to initiate turbine control (governor) valve fast closure.
0         Turbine generator OPC trip initiates main turbine bypass system operation.
0         Fast control valve closure initiates scram trip.
0         Fast control valve closure initiates an RPT.
0.07      Turbine control valves closed.
0.11      Turbine bypass valves start to open.
0.19      Recirculation pump motor circuit breakers open causing decrease in core flow to natural circulation.
1.70      Group 1 relief valves actuated.
1.86      Group 2 relief valves actuated.
2.01      Group 3 relief valves actuated.
2.27      Group 4 relief valves actuated.
a Approximately.
15.2-36

COLUMBIA GENERATING STATION                         Amendment 63 FINAL SAFETY ANALYSIS REPORT                      December 2015 Table 15.2-3 Typical Sequence of Events for Figure 15.2-2.2 Generator Load Rejection with Bypass Failure 100% Power 106% Flow Time (sec)                                         Event
(-)0.003a          Turbine generator detection of loss of electrical load.
0               Turbine generator OPC devices trip to initiate turbine control (governor) valve fast closure.
0               Turbine bypass valves fail to operate.
0.03            Time of scram trip.
0.15            Turbine control valves fully closed.
0.20            Time of RPT trip.
0.28            Start of control blade motion.
(b)               Group 1 MSRVs actuated (safety function).
(b)               Group 2 MSRVs actuated (safety function).
2.83            Group 3 MSRVs actuated (safety function).
3.17            Group 4 MSRVs actuated (safety function).
a Approximately.
b Not used - out of service for this analysis.
LDCN-15-011                                    15.2-37

COLUMBIA GENERATING STATION                           Amendment 61 FINAL SAFETY ANALYSIS REPORT                        December 2011 Table 15.2-4 Sequence of Events for Figure 15.2-3 Turbine Trip, Trip Scram - Bypass and RPT On Original Rated Power Time (sec)                                           Event 0                Turbine trip initiates closure of main stop (throttle) valves.
0                Turbine trip initiates bypass operation.
0.01             Main turbine stop valves reach 90% open position and initiate reactor scram trip.
0.01             Main turbine stop valves reach 90% open position and initiate an RPT.
0.10             Turbine stop valves closed.
0.10             Turbine bypass valves start to open to regulate pressure.
0.20             Recirculation pump motor circuit breakers open causing decrease in core flow to natural circulation.
1.63             Group 1 relief valves actuated.
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