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{{#Wiki_filter:SEABROOK STATION UPDATED FINAL SAFETY ANALYSIS REPORT CHAPTER 7 INSTRUMENTATION AND CONTROLS SECTIONS 7.1    Introduction 7.2    Reactor Trip System 7.3    Engineered Safety Features Actuation System 7.4    Systems Required For Safe Shutdown 7.5    Safety-Related Display Instrumentation 7.6    All Other Systems Required For Safety 7.7    Control Systems Not Required For Safety
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SEABROOK                    INSTRUMENTATION AND CONTROLS                    Revision 19 STATION                                  Introduction                        Section 7.1 UFSAR                                                                        Page 1
 
==7.1    INTRODUCTION==
 
This chapter presents the various plant instrumentation and control systems by relating the functional performance requirements, design bases, system descriptions, design evaluations, and test and inspections for each. The information provided in this chapter emphasizes those instruments and associated equipment which constitute the protection system as defined in IEEE Standard 279-1971 "IEEE Standard: Criteria for Protection System for Nuclear Power Generating Stations."
The primary purpose of the instrumentation and control systems is to provide automatic protection and exercise proper control against unsafe and improper reactor operation during steady-state and transient power operations (ANS Conditions I, II, III) and to provide initiating signals to mitigate the consequences of faulted condition (ANS Condition IV). ANS conditions are discussed in Chapter 15. Consequently, the information presented in this chapter emphasizes those instrumentation and control systems which are central to assuring that the reactor can be operated to produce power in a manner that ensures no undue risk to the health and safety of the public.
It is shown that the applicable criteria and codes, such as General Design Criteria and IEEE Standards, which are concerned with the safe generation of nuclear power are met by these instrumentation and control systems. (See Table 7.1-1 for a listing of applicable criteria.)
Review of Section 8.3, Onsite Power Systems, serves as necessary and sufficient background for evaluating the electrical integrity of plant instrumentation systems. Figure 8.3-2, Figure 8.3-3 and Figure 8.3-4 provide an overview of the distribution system with emphasis on vital and nonvital instrument buses and electrical separation divisions.
Definitions Terminology used in this chapter is based on the definitions given in IEEE Standard 279-1971.
In addition, the following definitions apply:
: a.      Degree of Redundancy - The difference between the number of channels monitoring a variable and the number of channels which, when tripped, will cause an automatic system trip.
: b.      Minimum Degree of Redundancy - The degree of redundancy below which operation is prohibited, or otherwise restricted by the Technical Specifications.
: c.      Cold Shutdown Condition - When the reactor is sub-critical by at least 1 percent k/k and Tavg is 200°F. Tavg is defined as the average temperature across the reactor vessel, as measured by the hot and cold leg temperature detectors.
 
SEABROOK              INSTRUMENTATION AND CONTROLS                      Revision 19 STATION                            Introduction                          Section 7.1 UFSAR                                                                    Page 2
: d. Hot Shutdown Condition - When the reactor is sub-critical, by an amount greater than or equal to the margin as specified in the applicable Technical Specification, and Tavg is greater than or equal to the temperature as specified in the applicable Technical Specification.
: e. Phase A Containment Isolation - Closure of all nonessential process lines which penetrate Containment, initiated by the safety injection signal.
: f. Phase B Containment Isolation - Closure of remaining process lines, initiated by containment Hi-3 pressure signal (process lines do not include Engineered Safety Features lines).
: g. Single Failure - Any single event within the protection system which results in a loss of proper protective action at the system level when required. Single failure includes single credible malfunctions or events that cause a number of consequential component, module or channel failures.
: h. DNBR - (Departure from Nucleate Boiling Ratio) - The ratio of the critical heat flux (defined as the transition from nucleate boiling to film boiling) to the actual local heat flux.
: i. System Response Times:
: 1.      Reactor Trip System Response Time The time interval from when the monitored parameter exceeds its trip setpoint at the channel sensor until loss of stationary gripper coil voltage.
: 2.      Engineered Safety Features Actuation System Response Time The time interval from when the monitored parameter exceeds its ESF actuation setpoint at the channel sensor until the ESF equipment is capable of performing its safety function (i.e., the valves travel to their required positions, pump discharge pressures reach their required values, etc.).
Times shall include diesel generator starting and sequence loading delays where applicable.
 
SEABROOK              INSTRUMENTATION AND CONTROLS                      Revision 19 STATION                          Introduction                          Section 7.1 UFSAR                                                                    Page 3
: j. Reproducibility - This definition is taken from Scientific Apparatus Manufactures Association (SAMA) Standard PMC-20.1-1973, Process Measurement and Control Terminology:          "The closeness of agreement among repeated measurements of the output for the same value of input, under normal operating conditions over a period of time, approaching from both directions." It includes drift, due to environmental effects, hysteresis, long-term drift, and repeatability.
Long-term drift (aging of components, etc.) is not an important factor in accuracy requirements since, in general, the drift is not significant with respect to the time elapsed between testing. Therefore, long-term drift may be eliminated from this definition. Reproducibility, in most cases, is a part of the definition of accuracy (see below).
: k. Accuracy - This definition is derived from Scientific Apparatus Manufactures Association (SAMA) Standard PMC-20.1-1973, Process Measurement and Control Terminology. An accuracy statement for a device falls under Note 2 of the SAMA definition of accuracy, which means reference accuracy or the accuracy of that device at reference operating conditions: "Reference accuracy includes conformity, hysteresis and repeatability." To adequately define the accuracy of a system, the term reproducibilty is useful as it covers normal operating conditions. The following terms, "trip accuracy" and "indicated accuracy" etc., will then include conformity and reproducibility under normal operating conditions. Where the final result does not have to conform to an actual process variable but is related to another value established by testing, conformity may be eliminated, and the term reproducibility may be substituted for accuracy.
: l. Normal Operating Conditions - These conditions cover all normal process temperature and pressure changes. Also included are ambient temperature changes around the transmitter and racks. Not included are accuracies under "post-accident" conditions.
: m. Readout Devices - For consistency, the final device of a complete channel is considered a readout device. This includes indicators, recorders, isolators (nonadjustable), and controllers.
: n. Channel Accuracy - This definition includes accuracy of primary element, transmitter and rack modules. It does not include readout devices or rack environmental effects, but does include process and environmental effects on field-mounted hardware. Rack environmental effects are included in the next two definitions to avoid duplication due to dual inputs.
: o. Indicated and/or Recorded Accuracy - This definition includes channel accuracy, accuracy of readout devices and rack environmental effects.
 
SEABROOK                    INSTRUMENTATION AND CONTROLS                      Revision 19 STATION                                Introduction                          Section 7.1 UFSAR                                                                        Page 4
: p. Trip Accuracy - This definition includes comparator accuracy, channel accuracy, for each input, and rack environmental effects. This is the tolerance expressed in process terms (or percent of span) within which the complete channel must perform its intended trip function. The term "actuation accuracy" may be used where the word "trip" might cause confusion (for example, when starting pumps and other equipment).
: q. Control Accuracy - This definition includes channel accuracy, accuracy of readout devices (isolator, controller), and rack environmental effects. Where an isolator separates control and protection signals, the isolator accuracy is added to the channel accuracy to determine control accuracy, but credit is taken for tuning beyond this point; i.e., the accuracy of these modules (excluding controllers) is included in the original channel accuracy. It is simply defined as the accuracy of the control signal in percent of the span of that signal. This will then include gain changes where the control span is different from the span of the measured variable. Where controllers are involved, the control span is the input span of the controller. No error is included for the time in which the system is in a nonsteady-state condition.
7.1.1          Identification of Safety-Related Systems 7.1.1.1        Safety-Related Systems The Nuclear Steam Supply System (NSSS) and the Balance-of-Plant (BOP) instrumentation discussed in Chapter 7 are those required to function to achieve the system responses assumed in the safety evaluations, and those needed to shutdown the plant safely, and are identified in this section.
: a. Reactor Trip System The Reactor Trip System is a functionally defined system provided by the NSSS, and is described in Section 7.2. The equipment which provides the trip functions is identified and discussed in Section 7.2. Design bases for the Reactor Trip System are given in Subsection 7.1.2.1. Figure 7.1-1 includes a single line diagram of this system.
: b. Engineered Safety Features Actuation System The Engineered Safety Features Actuation System (ESFAS) is a functionally defined system provided by the NSSS and is described in Section 7.3. The equipment which provides the actuation functions is identified and discussed in Section 7.3. Design bases for the Engineered Safety Features Actuation System are given in Subsection 7.1.2.1.
 
SEABROOK              INSTRUMENTATION AND CONTROLS                  Revision 19 STATION                          Introduction                        Section 7.1 UFSAR                                                                Page 5
: c. Engineered Safety Feature Systems The Engineered Safety Feature Systems that perform protective actions after activation by ESFAS or the operator are listed below. All systems except the ECCS are BOP provided.
: 1.      Containment Spray System (Subsection 6.2.2)
: 2.      Containment Isolation System (Subsection 6.2.4)
: 3.      Combustible Gas Control System (Subsection 6.2.5)
: 4.      Emergency Core Cooling System (Section 6.3)
: 5.      Habitability Systems (Section 6.4)
: 6.      Fission Product Removal and Control Systems (Section 6.5)
: 7.      Emergency Feedwater System (Section 6.8).
: d. Instrumentation and Control Power Supply System Design bases for the Instrumentation and Control Power Supply System which is BOP provided are given in Subsection 7.1.2.1. Further description of this system is provided in Section 8.3.
: e. Other Auxiliary Supporting Systems Auxiliary Supporting Systems are those systems that, upon receipt of actuation signals, must function to support and enable the operation of protection systems.
Actuation signals for these systems are provided from the Engineered Safety Features Actuation System. All systems except the Chemical and Volume Control System are BOP provided. The auxiliary systems are:
: 1.      Fuel Storage and Handling Systems (Section 9.1)
: 2.      Station Service Water System (Subsection 9.2.1)
: 3.      Cooling System for Reactor Auxiliaries (Subsection 9.2.2)
: 4.      Ultimate Heat Sink (Subsection 9.2.5)
: 5.      Reactor Makeup Water System (Subsection 9.2.7)
: 6.      Chemical and Volume Control System (Subsection 9.3.4)
: 7.      Air Conditioning, Heating, Cooling and Ventilation Systems (Section 9.4).
: 8.      Normal and Emergency Electrical Power Systems (Section 8.3)
: 9.      Diesel Generator Mechanical Systems (Section 9.5)
 
SEABROOK                    INSTRUMENTATION AND CONTROLS                    Revision 19 STATION                                  Introduction                        Section 7.1 UFSAR                                                                        Page 6
: f.      Other Systems for Safety These are systems, safety-related and nonnuclear safety, which operate to reduce the probability of occurrence of specific accidents, maintain the plant within the envelope of operating conditions postulated in the accident analyses, or are required to assure full protection capability. These systems are:
Systems items 1, 5, 7, 8, 9, 10, 11 and 12 are BOP supplied, systems items 3 and 6 are NSSS supplied, and systems items 2, 4, and 13 are partially NSSS and BOP supplied.
: 1. Safety-related display instrumentation (Section 7.5)
: 2. Accumulator isolation valve controls (Section 7.6)
: 3. Reactor Coolant System pressure control during low temperature operation (Section 7.6)
: 4. Residual Heat Removal System interlocks (Section 7.6)
: 5. Protection against spurious valve actuation (Section 7.6)
: 6. Switchover from injection to recirculation (Section 7.6)
: 7. Isolation of nonessential components in PCCW system (Section 7.6)
: 8. Bypass and inoperable status indication system (Section 7.1)
: 9. Area radiation and airborne radioactivity monitoring instrumentation (Subsection 12.3.4)
: 10. High energy line break sensing system (Section 7.6)
: 11. ATWS Mitigation System (Section 7.6)
: 12. Turbine Trip System (Section 7.3)
: 13. Steam Blowdown System Isolation on emergency feed pump start (Section 10.4.8 and 6.8) 7.1.1.2        Safety-Related Display Instrumentation Display instrumentation (Section 7.5, Table 7.5-1) provides the operator with information to enable monitoring the results of Engineered Safety Features actions following a Condition III or IV event. Section 7.5, Table 7.5-1 and Table 7.5-2 list instrumentation and controls provided to maintain the plant in a hot shutdown condition, or to proceed to cold shutdown under normal operating conditions following condition III and IV events. The accident monitoring instrumentation for the safety-related systems includes position indication lights and indicators for the vital parameters in the systems listed in Subsection 7.1.1.1.
 
SEABROOK                    INSTRUMENTATION AND CONTROLS                    Revision 19 STATION                                Introduction                        Section 7.1 UFSAR                                                                        Page 7 7.1.1.3        Instrumentation and Control System Designs All systems discussed in Chapter 7 have definitive functional requirements developed on the basis of the Westinghouse NSSS design. Figure 7.2-1, Figure 7.2-2, Figure 7.2-3, Figure 7.2-4, Figure 7.2-5, Figure 7.2-6, Figure 7.2-7, Figure 7.2-8, Figure 7.2-9, Figure 7.2-10, Figure 7.2-11, Figure 7.2-12, Figure 7.2-13, Figure 7.2-14, and Figure 7.2-15 define scope interface.
Regardless of the supplier, the functional requirements necessary to assure plant safety and proper control are clearly delineated.
7.1.1.4        Plant Comparison System functions for all systems discussed in Chapter 7 are similar to those discussed in the comparisons provided in Section 1.3.
7.1.2          Identification of Safety Criteria Subsection 7.1.2.1 presents design bases for the systems given in Subsection 7.1.1.1. Design bases for nonsafety-related systems are provided in the sections which describe the systems.
Conservative considerations for instrument errors are included in the accident analyses presented in Chapter 15. Functional requirements, developed on the basis of the results of the accident analyses, which have utilized conservative assumptions and parameters, are used in designing these systems, and a preoperational testing program verifies the adequacy of the design.
Accuracies are discussed in Sections 7.2, 7.3 and 7.5.
The documents listed in Table 7.1-1 were considered in the design of the systems given in Subsection 7.1.1. In general, the scope of these documents is given in the document itself. This determines the systems or parts of systems to which the document is applicable. A discussion of compliance with each document for systems in its scope is provided in the referenced sections given in Table 7.1-1 for each criterion. Because some documents were issued after design and testing had been completed, the equipment documentation may not meet the format requirements of some standards. Justification for any exceptions taken to each document for systems in its scope is provided in the referenced sections.
7.1.2.1        Design Bases
: a. Reactor Trip System The Reactor Trip System acts to limit the consequences of Condition II events (faults of moderate frequency), such as loss of feedwater flow, by at most, a shutdown of the reactor and turbine, with the plant capable of returning to operation after corrective action. The Reactor Trip System features impose a limiting boundary region to plant operation which ensures that the reactor safety limits are not exceeded during Condition II, III and IV events, and that these events can be accommodated without developing into more severe conditions.
Reactor trip setpoints are given in the Technical Specifications.
 
SEABROOK                INSTRUMENTATION AND CONTROLS                      Revision 19 STATION                            Introduction                          Section 7.1 UFSAR                                                                    Page 8 The design requirements for the Reactor Trip System are derived by analyses of plant operating and fault conditions where automatic rapid control rod insertion is necessary to prevent or limit core or reactor coolant boundary damage. The design bases addressed in IEEE Standard 279-1971 are discussed in Subsection 7.2.1. The design limits for the Reactor Trip System are:
: 1.      Minimum DNBR shall not be less than the safety analysis limit value as a result of any anticipated transient or malfunction (Condition II faults).
: 2.      Power density shall not exceed the rated linear power density for Condition II faults. See Chapter 4 for fuel design limits.
: 3.      The stress limit of the Reactor Coolant System for the various conditions shall be as specified in Chapter 5.
: 4.      Release of radioactive material shall not be sufficient to interrupt or restrict public use of those areas beyond the exclusion radius as a result of any Condition III fault (10 CFR 20, Standard for Protection Against Radiation).
: 5.      For any Condition IV fault, release of radioactive material shall not result in an undue risk to public health and safety (10 CFR 100, Reactor Site Criteria).
: b. Engineered Safety Features Actuation System The Engineered Safety Features Actuation System acts to limit the consequences of Condition II and III events (infrequent faults such as primary coolant spillage from a small rupture which exceeds normal charging system makeup and requires actuation of the Safety Injection System). The Engineered Safety Features Actuation System acts to mitigate Condition IV events (limiting faults, which include the potential for significant release of radioactive material).
The design bases for the Engineered Safety Features Actuation System are derived from the design bases given in Chapter 6 for the Engineered Safety Features. Design bases requirements of IEEE Standard 279-1971 are addressed in Subsection 7.3.1.2. General design requirements implemented are given below.
 
SEABROOK              INSTRUMENTATION AND CONTROLS                    Revision 19 STATION                          Introduction                          Section 7.1 UFSAR                                                                  Page 9
: 1.      Automatic Actuation Requirements The primary functional requirement of the Engineered Safety Features Actuation System is to receive input signals (information) from the various on-going processes within the reactor plant and Containment and to automatically provide, as output, timely and effective signals to actuate the various components and subsystems comprising the Engineered Safety Features System. The performance objectives of these systems are outlined in Chapter 6. The functional diagrams presented in Figure 7.2-5, Figure 7.2-6, Figure 7.2-7 and Figure 7.2-8, depict the functions (or parameters) associated with the Engineered Safety Features Actuation Systems.
: 2.      Manual Actuation Requirements The Engineered Safety Features Actuation System has provisions in the main control room for manually initiating the functions of the Engineered Safety Features System, at the system level.
: c. Instrumentation and Control Power Supply System The Instrumentation and Control Power Supply System provides continuous, reliable, regulated single-phase AC power to all instrumentation and control equipment required for plant safety. Details of this system and the design bases are provided in Section 8.3.
: d. Emergency Power Design bases and system description for the emergency power supply are provided in Chapter 8.
 
SEABROOK                INSTRUMENTATION AND CONTROLS                    Revision 19 STATION                            Introduction                        Section 7.1 UFSAR                                                                  Page 10
: e. Interlocks Interlocks are discussed in Section 7.2, Section 7.3, Section 7.6 and Section 7.7.
The protection (P) interlocks are given on Table 7.2-2 and Table 7.3-2. The safety analyses demonstrate that even under conservative critical conditions for either postulated or hypothetical accidents, the protective systems ensure that the NSSS will be put into and maintained in a safe state following an ANS Condition II, III or IV accident, commensurate with applicable Technical Specifications and pertinent ANS criteria. Therefore, the protective systems have been designed to meet IEEE Standard 279-1971 and are entirely redundant and separate, including all permissives and blocks. All blocks of a protective function would be required to function in accordance with General Design Criteria 20, 21 and 22 and paragraphs 4.11, 4.12, and 4.13 of IEEE Standard 279-1971. Control interlocks (C) are identified on Table 7.7-1.        Because control interlocks are not safety-related, they have not been specifically designed to meet the requirements of IEEE Protection System Standards.
: f. Bypasses Bypasses are designed to meet the requirements of IEEE Standard 279-1971, paragraphs 4.11, 4.12, 4.13 and 4.14. A discussion of bypasses provided is given in Sections 7.2 and 7.3.
: g. Equipment Protection The criteria for equipment protection are given in Chapter 3. Equipment related to safe operation of the plant is designed, constructed and installed to protect it from damage. This is accomplished by designing to accepted standards and using criteria aimed at providing reliable instrumentation which is available under varying conditions. As an example, certain equipment is seismically qualified in accordance with IEEE Standard 344-1975. During construction, independence and separation are achieved, as required by IEEE Standard 279-1971, IEEE Standard 384-1974 and Regulatory Guide 1.75, consistent with Attachment C to AEC letter dated Dec. 14, 1973 (Appendix 8A), either by barriers, physical separation, or demonstration test and analysis. This serves to protect against complete destruction of a system by fires, missiles or other natural hazards.
: h. Diversity Functional diversity has been designed into the system. Functional diversity is discussed in Reference 1. The extent of diverse system variables has been evaluated for a wide variety of postulated accidents. Generally, two or more diverse protection functions would automatically terminate an accident before unacceptable consequences could occur.
 
SEABROOK                INSTRUMENTATION AND CONTROLS                    Revision 19 STATION                            Introduction                        Section 7.1 UFSAR                                                                    Page 11 For example, there are automatic reactor trips based upon neutron flux measurements, reactor coolant loop temperature measurements, pressurizer pressure and level measurements, and reactor coolant pump underfrequency and undervoltage measurements, as well as trips which are initiated manually, and by initiation of a safety injection signal.
Regarding the Engineered Safety Features Actuation System for a loss-of-coolant accident, a safety injection signal can be obtained manually or by automatic initiation from two diverse parameter measurements.
: 1.      Low pressurizer pressure
: 2.      High containment pressure (Hi-1)
For a steam line break accident, a safety injection signal can be obtained manually or by automatic initiation from three diverse parameter measurements.
: 1.      Low compensated steamline pressure
: 2.      For a steamline break inside Containment, high containment pressure (Hi-2) provides an additional parameter for generation of the signal.
: 3.      Low pressurizer pressure All of the above sets of signals are redundant and physically separated and meet the requirements of IEEE Standard 279-1971.
The seismic and environmental qualification for protection system sensors and channels is discussed in Sections 3.10 and 3.11, respectively.
: i. Bistable Trip Setpoints Three values applicable to reactor trip and engineered safety features actuation are specified:
: 1.      Safety limit
: 2.      Allowable value
: 3.      Nominal value.
The safety limit is the value assumed in the accident analysis and is the least conservative value.
The reactor trip setpoint limits specified in the Technical Specifications are the nominal values at which the reactor trips are set for each parameter. The setpoints have been selected to ensure that the reactor core and Reactor Coolant System are prevented from exceeding their safety limits during normal operation and design basis anticipated operational occurrences, and to assist the Engineered Safety Features Actuation System in mitigating the consequences of accidents.
 
SEABROOK              INSTRUMENTATION AND CONTROLS                      Revision 19 STATION                            Introduction                          Section 7.1 UFSAR                                                                    Page 12 The methodology to derive the nominal trip setpoints is based upon statistically combining all of the uncertainties in the channels and applying this total uncertainty with margin in the conservative direction.              Inherent to the determination of the trip setpoints is the determination of the magnitudes of the channel uncertainties. Sensors and other instrumentation used in these channels are expected to be capable of operating within the allowances of these uncertainty magnitudes.
To accommodate the instrument drift assumed to occur between operational tests and the accuracy to which setpoints can be measured and calibrated, allowable values for the reactor trip setpoints have also been specified in the Technical Specifications. Operation with setpoints less conservative than the nominal trip setpoint, but within the allowable value, is acceptable since an allowance has been made in the selection of that setpoint to accommodate this error without exceeding the value used in the safety analysis. A further discussion on setpoints is found in Subsection 7.2.2.2a.
Range selection for the instrumentation covers the expected range of the process variable being monitored consistent with its application. The design of the Reactor Protection and Engineered Safety Features Systems is such that the bistable trip setpoints do not require process transmitters to operate within 3 percent of the high and low end of their calibrated span or range. Functional requirements established for every channel in the Reactor Protection and Engineered Safety Features Systems stipulate the maximum allowable errors on accuracy, linearity, and reproducibility. The protection channels have the capability for, and are tested to ascertain that the characteristics throughout the entire span in all aspects are acceptable and meet functional requirement specifications. As a result, no protection channel operates normally within 3 percent of the limits of its specified span. The specific functional requirements for response time, setpoint, and operating span are based on the results and evaluation of safety studies carried out using data pertinent to the plant. Emphasis is placed on establishing adequate performance requirements under both normal and faulted conditions. This includes consideration of process transmitters margins such that even under a highly improbable situation of full power operation at the limits of the operating map (as defined by the high and low pressure reactor trip, T overpower and overtemperature trip lines (DNB protection) and the steam generator safety valve pressure setpoint), adequate instrument response is available to ensure plant safety.
 
SEABROOK              INSTRUMENTATION AND CONTROLS                    Revision 19 STATION                            Introduction                        Section 7.1 UFSAR                                                                  Page 13 Setpoints for safety-related BOP bistable instruments are determined using the same methodology which Westinghouse used for the protection system setpoints.
This methodology complies with the methodology outlined in Regulatory Guide 1.105 (Rev 1), as supplemented by the information presented in ISA Standard S67.04 (Draft F).
This methodology is applied to the determination of setpoints for all safety-related (Class 1E) bistable instruments, as distinct from the wording of Regulatory Guide 1.105, "instruments in systems important to safety." This distinction is beneficial to the safety of Seabrook Station because it provides a tangible and controllable distinction between those setpoints which require special attention and those which do not, while still insuring adequate safety consistent with the definition of "Class 1E" as stated in IEEE Std. 308.
Error allowances used in setpoint determination are supported by qualification testing, consistent with the postulated service conditions for the required protective function.      Time limits for the environmental qualification of safety-related instruments are one year post-accident, or as specified in the equipment qualification files.
: j. Safety-Related System Motor Selections Refer to Subsection 8.3.1.1i.
: k. Design Bases for Other Systems The design bases for the instrumentation and control of the safety-related systems designed and/or built by other than Westinghouse, as identified in Subsection 7.1.1, are:
: 1.      Adequate control and monitoring instrumentation are provided for these systems as described in the applicable Updated FSAR sections, during all modes of operation including post-accident conditions.
: 2.      The sensors, impulse lines, actuating devices, wiring, interlocks and bypasses in actuation and monitoring circuits performing the safety functions satisfy the functional requirements of IEEE Standard 279-1971, and separation requirements as discussed in Subsections 7.1.2.2 and 8.3.1.4.
: 3.      The instrumentation and controls for both the safety-related and nonsafety-related portions of the systems are compatible with their environment as defined in Section 3.11.                The safety-related instrumentation and control equipment has been qualified seismically and environmentally as described in Sections 3.10 and 3.11, respectively.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                    Revision 19 STATION                                  Introduction                        Section 7.1 UFSAR                                                                          Page 14 7.1.2.2          Independence of Redundant Safety-related Systems The safety-related systems in Subsection 7.1.1.1 are designed to meet the independence and separation requirements of Criterion 22 of the 1971 General Design Criteria and paragraph 4.6 of IEEE Standard 279-1971. The administrative responsibility and control provided during the design and construction is discussed in Chapter 17, Quality Assurance.
The electrical power supply, instrumentation, and control cables for redundant circuits of a nuclear plant have physical separation to preserve the redundancy and to ensure that no single credible event will prevent accomplishment of the associated function due to electrical cable damage. Detailed information pertaining to electrical cable system separation requirements for safety-related systems is give in Subsection 8.3.1.4. Critical circuits and functions include power, control and analog instrumentation associated with the operation of the Reactor Trip System or Engineered Safety Features Actuation System.
Credible events shall include, but not be limited to, the effects of short circuits, pipe rupture, missiles, fire, etc., and are considered in the basic plant design. Control board details are given in Subsection 7.1.2.2b. In the control board, separation of redundant circuits is maintained as described in Subsection 7.1.2.2a.
: a.      General
: 1.      Independence of Redundant Instrument Sensing Lines The independence of instruments and their sensing lines required for a system safety function is maintained through redundancy, physical separation and/or diversity in accordance with IEEE Standard 279-1971.
Sensing lines penetrating the primary Containment satisfy the requirements of Regulatory Guide 1.141 and the intent of Regulatory Guide 1.11.
: 2.      Design Criteria and Bases for the Installation of Electrical Cable for Safety-Related Systems The design criteria and bases for the installation of cables for preserving the independence of redundant reactor protection systems and engineered safety features systems with respect to cable derating, cable raceway fill, cable routing, sharing of raceways by safety-related cables with nonsafety-related cables, and cable tray markings are the same as that presented in Subsection 8.3.1.4.
: 3.      Spacing of Wiring and Components in Control Boards, Panels and Relay Racks Criteria for spacing of wiring and components in control boards, panels and relay racks are described in Subsection 7.1.2.2b.
 
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: 4. Physical Separation Criteria (a)    The physical separation criteria for redundant safety-related system sensors, sensing lines, wireways, cables and components on racks within Westinghouse NSSS and BOP scope meet recommendations contained in Regulatory Guide 1.75 with the following comments:
(1)    The Westinghouse design of the protection system relies on the provisions of IEEE Standard 384-1974 relative to overcurrent devices to prevent malfunctions in one circuit from causing unacceptable influences on the functioning of the protection system.        The protection system uses redundant instrumentation channels and actuation trains and incorporates physical and electrical separation to prevent faults in one channel from degrading any other protection channel.
(2)    Separation recommendations for redundant instrumentation racks are not the same as those given in Regulatory Guide 1.75, Revision 2, for the control boards because of different functional requirements. Main control boards contain redundant circuits that are required to be physically separated from each other. However, since there are no redundant circuits which share a single compartment of an NSSS protection instrumentation rack and since these redundant protection instrumentation racks are physically separated from each other, the physical separation specified for the main control board does not apply.
However, redundant, isolated control signal cables leaving the protection racks are brought into close proximity elsewhere in the plant, such as the control board. It could be postulated that electrical faults, or interference, at these locations might be propagated into all redundant racks and degrade protection circuits because of the close proximity of protection and control wiring within each rack.
Regulatory Guide 1.75 (Regulatory Position C.4) and IEEE Standard 384-1974 (Section 4.5(3)) provide the option to demonstrate by tests that the absence of physical separation could not significantly reduce the availability of Class 1E circuits.
 
SEABROOK    INSTRUMENTATION AND CONTROLS                      Revision 19 STATION                  Introduction                          Section 7.1 UFSAR                                                          Page 16 Westinghouse test programs have demonstrated that Class 1E protection systems (nuclear instrumentation system, solid-state protection system and 7300 process control system) are not degraded by non-Class 1E circuits sharing the same enclosure. Conformance to the requirements of IEEE Standard 279-1971 and Regulatory Guide 1.75 has been established and accepted by the NRC based on the following which is applicable to these systems at the Seabrook site.
Tests conducted on the as-built designs of the nuclear instrumentation system and solid-state protection system were reported and accepted by the NRC in support of the Diablo Canyon application (Docket Nos. 50-275 and 50-323) [See Reference 5]. Westinghouse considers these programs as applicable to all plants, including Seabrook.
Westinghouse tests on the 7300 Process Control System were covered in a report entitled, "Westinghouse 7300 Series Process Control System Noise Tests," subsequently reissued as Reference 2. In a {{letter dated|date=April 20, 1977|text=letter dated April 20, 1977}} (Reference 3) the NRC accepted the report in which the applicability of the Seabrook plant is established.
(3)    The physical separation criteria for instrument cabinets within    Westinghouse      NSSS      scope    meet  the recommendations contained in Section 5.7 of IEEE Standard 384-1974.
(b)  The physical separation criteria for redundant safety-related sensing lines meet the recommendations contained in Regulatory Guide 1.151, with the following comments.
Redundant safety-related instrument sensing lines are not routed in the same area where they would be subject to external forces such as those due to jet impingement or pipe whip caused by an accident.
All components located in seismic areas are reviewed to ensure that they will not produce seismically-generated missiles that could damage safety-related components.          The maximum feasible physical separation is maintained in areas where the redundant safety-related sensing lines are not subject to external forces caused by an accident.
 
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: b. Specific Systems Independence is maintained throughout the system, extending from the sensor through to the devices actuated by the protective function. Physical separation or barriers are used to achieve separation of redundant transmitters. Separation of wiring is achieved using separate wireways, cable trays, conduit runs and containment penetrations for each redundant protection channel set. Redundant analog equipment is separated by locating modules in different protection rack sets. Each redundant channel set is energized from a separate AC power feed.
There are four separate process analog sets. Separation of redundant analog channels begins at the process sensors and is maintained in the field wiring, containment penetrations and analog protection cabinets to the redundant trains in the logic racks. Redundant analog channels are separated by locating modules in different cabinets. Nonprotection system outputs are through qualified isolators and are appropriately separated.
The Solid-State Protection System input cabinets are divided into four isolated compartments, each serving one of the four redundant input channels. Horizontal 1/8-inch thick solid steel barriers coated with fire-retardant paint separate the compartments.      Four, 1/8-inch thick solid steel wireways coated with fire-retardant paint enter the input cabinets vertically, each in its own quadrant.
The wireway for a particular compartment is open only into that compartment so that flame could not propagate to affect other channels. Test (Reference 5) and analysis are used to address separation in the common area at the bottom of the input cabinets where the cables enter from the field raceways.
In the Nuclear Instrumentation System, Process Systems, and where redundant channel instrumentation is physically adjacent, there are no wireways, or cable penetrations which would permit, for example, a fire resulting from electrical failure in one channel to propagate into redundant channels in the logic racks.
Redundant analog channels are separated by locating modules in different cabinets. Since all equipment within any cabinet is associated with a single protection set and the cabinets are protected from external faults by isolators, there is no requirement for separation of wiring and components within the cabinet.
Independence of the logic trains is discussed in Sections 7.2 and 7.3.
Two reactor trip breakers are actuated by two separate logic matrices to interrupt power to the control rod drive mechanisms. The breaker main contacts are connected in series with the power supply so that opening either breaker interrupts power to all control rod drive mechanisms, permitting the rods to free fall into the core.
 
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: 1. Reactor Trip System (a)    Separate routing is maintained for the four basic Reactor Trip System channel sets analog sensing signals, bistable output signals and power supplies for such systems. The separation of these four channel sets is maintained from sensors to instrument cabinets to logic system input cabinets.
(b)    Separate routing of the redundant reactor trip signals from the redundant logic system cabinets is maintained, and, in addition, they are separated (by spatial separation or by provision of barriers or by separate cable trays or wireways) from the four analog channel sets.
: 2. Engineered Safety Features Actuation System (a)    Separate routing is maintained for the four basic sets of Engineered Safety Features Actuation System analog sensing signals, bistable output signals and power supplies for such systems. The separation of these four channel sets is maintained from sensors to instrument cabinets to logic system input cabinets.
(b)    Separate routing of the Engineered Safety Features actuation signals from the redundant logic system cabinets is maintained. In addition, they are separated by spatial separation or by provisions of barriers or by separate cable trays or wireways from the four analog channel sets.
(c)    Separate routing of control and power circuits associated with the operation of Engineered Safety Features equipment is required to retain redundancies provided in the system design and power supplies.
: 3. Instrumentation and Control Power Supply System The separation criteria presented above also apply to the power supplies for the load centers and buses distributing power to redundant components and to the control of these power supplies.
Reactor Trip System and Engineered Safety Features Actuation System analog circuits may be routed in the same wireways provided circuits have the same power supply and channel set identified (I, II, III or IV).
 
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: 4. Main Control Board (MCB)
The MCB is a hard-wired walk-in U-shaped duplex control board designed in accordance with IEEE 420. It contains a combination of Class 1E and non-Class 1E control and information devices necessary for remote operation of the unit. Arrangement of the controls within the MCB is system oriented. Within systems, it is train and/or loop oriented. Overall arrangements, besides providing for the separation requirements, are coordinated to assure safe and efficient operation. The front panels of the MCB contain the controls and information displays for the engineered safeguards, reactivity, turbine, heat cycle equipment, cooling water, ultimate heat sink and the electrical power distribution systems. The rear panels of the MCB contain the controls and instrumentation displays for the secondary support systems.
The separation criteria are discussed in Subsection 7.1.2.2a.
The covered wireways, formed from solid or punched sheet steel, and the conduits above or below each board-mounted device, comply with the separation criteria required by IEEE Standards. The MCB wiring is color-coded NEC-type SIS copper conductor with flame-retardant insulation, rated and qualified per IPCEA, UL, or IEEE standards.
Nonmetallic components, such as terminal blocks, wire cleats, cable ties, receptacles, indicating light lenses, nameplates, etc., are furnished of materials meeting the nonflammability requirements of UL standards.
The separation criteria within the MCB are given in Table 8.3-10 and were based on analysis and testing as permitted by Subsection 4.3.3 of IEEE 420. This analysis and testing are documented in References 1 and 2 of Subsection 8.3.4. Each component is clearly identified with a distinctively colored permanent tag. Colored nameplates are employed on the exterior surfaces of the MCB to identify the component's function (see Subsection 7.1.2.3).
 
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: c. Fire Protection For electrical equipment within the NSSS scope of supply, Westinghouse specifies noncombustible or fire retardant material and conducts vendor-supplied specification reviews of this equipment, which includes assurance that materials will not be used which may ignite or explode from an electrical spark, flame, or from heating, or will independently support combustion. These reviews also include assurance of conservative current-carrying capacities of all instrument cabinet wiring, which precludes electrical fires resulting from excessive overcurrent (I2R) losses. For example, wiring used for instrument cabinet construction has teflon or tefzel insulation and is adequately sized, based on current carrying capacities set forth by the National Electric Code. In addition, fire retardant paint is used on protection rack or cabinet construction to retard fire or heat propagation from rack to rack.              Braided sheathed material is noncombustible.
Subsections 8.3.1 and 8.3.2 describe design aspects used for BOP electrical equipment in the prevention of fires in cable system, including separation between redundant trains and voltage levels, cable material selection and cable sizing.
Details of the Plant Fire Protection System are provided in Subsection 9.5.1.
7.1.2.3        Physical Identification of Safety-Related Equipment There are four separate protection sets identifiable with process equipment associated with the Reactor Trip and Engineered Safeguards Actuation Systems. A protection set may be comprised of more than a single process equipment cabinet. The color coding of each process equipment rack instrument nameplate coincides with the color code established for the protection set of which it is a part. At the logic racks, the protection set color coding for redundant channels is clearly maintained until the channel loses its identity in the redundant logic trains. The color-coded nameplates described below provide identification of equipment associated with protective functions and their channel set association:
Protection Set          Color Coding I                  RED II                  WHITE III                BLUE IV                  YELLOW
 
SEABROOK                    INSTRUMENTATION AND CONTROLS                        Revision 19 STATION                                  Introduction                            Section 7.1 UFSAR                                                                            Page 21 The safety-related instrumentation and control system equipment throughout the plant is identified with colored tags or nameplates. The colored tags are consistent with the color coding of cables as defined in Subsection 8.3.1.3, and with the protection set nameplates as identified above.
Equipment Nameplate Color Train A or Channel 1            Red Train B or Channel 2            White Channel 3                      Blue Channel 4                      Yellow Accident Monitoring            Orange Instrumentation                (see Section 7.5 for additional clarification)
Nonsafety-Related              Black Remote Safe Shutdown            Purple The equipment nameplate colors described above represent the color assigned to identify each separation group. In the original nameplate design, the nameplate background color was used to identify the separation group. As a result of labeling improvements, including the addition of bar codes, redesign of the background color was required. Newer nameplates may use different methods, such as black letters on a white background with a border color that identifies the separation group. In this way, the same basic separation group color is maintained for different nameplate styles.
All noncabinet-mounted protective equipment and components are provided with an identification tag or nameplate. Small electrical components such as relays have nameplates on the enclosure which houses them. All cables are numbered with identification tags. All cable trays and conduits are identified using permanent markings (see Subsection 8.3.1.4). The purpose of such markings is to facilitate cable routing identification. Positive permanent identification of cables is made at all terminations. There are also identification nameplates on the input panels of the Solid-State Logic Protection System.
Instrument sensing lines comply with the identification and color coding requirements of Regulatory Guide 1.151, with the following exceptions and as described in Section 1.8:
: a.      Instrument sensing lines for a nuclear safety-related instrument are not color coded to identify its channel.
 
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: b.      Instrument sensing lines are tagged with unique line numbers at the instrument side of the root valve, on the process side of the instrument shut-off valve, and on each side of an obstacle when the tubing runs through the obstacle, such as a wall or floor. Redundant safety-related lines are installed using engineered design packages to ensure that the separation criteria are met.
7.1.2.4        Conformance to Criteria A listing of applicable criteria and the Updated FSAR sections where conformance is discussed is given in Table 7.1-1.
7.1.2.5        Conformance to Regulatory Guide 1.22 Periodic testing of the Reactor Trip and Engineered Safety Features Actuation Systems, as described in Subsections 7.2.2 and 7.2.3, complies with Regulatory Guide 1.22, "Periodic Testing of Protection System Actuation Functions," as described in this chapter and in Section 1.8.
Where the ability of a system to respond to a bona fide accident signal is intentionally bypassed to perform a test during reactor operation, each bypass condition is automatically indicated to the reactor operator in the main control room for the train in test. Test circuitry does not allow two trains to be tested at the same time so that extension of the bypass condition to the redundant system is prevented.
The actuation logic for the Reactor Trip and Engineered Safety Features Actuation System is tested as described in Sections 7.2 and 7.3. As recommended by Regulatory Guide 1.22, where actuated equipment is not tested during reactor operation it has been determined that:
: a.      There is no practicable system that would permit operation of the equipment without adversely affecting the safety or operability of the plant;
: b.      The probability that the protection system will fail to initiate the operation of the equipment is, and can be maintained, acceptably low without testing the equipment during reactor operation; and
: c.      The equipment can routinely be tested when the reactor is shutdown.
The list of equipment that cannot be tested at full power so as not to damage equipment or upset plant operation is as follows:
: a.      Manual actuation switches (reactor trip containment isolation phase A, containment spray actuation, and safety injection actuation)
: b.      Turbine trips (initiation and detection)
: c.      Main steam line isolation valves (close)
: d.      Main feedwater isolation valves (close)
 
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: e.      Feedwater control valves (close)
: f.      Main feedwater pump trip solenoids
: g.      Reactor coolant pump component cooling water isolation valves (close)
: h.      Reactor coolant pump seal water return valves (close)
: i.      Charging header to cold leg isolation valves
: j.      Accumulator isolation valves (open).
: k.      Charging and letdown isolation valves (close)
: l.      Letdown heat exchanger component cooling water outlet isolation valve (close)
: m.      Reactor coolant pump trip (underfrequency)
: n.      Chemical and Volume Control System TK-1 outlet isolation valves (close)
: o.      Refueling Water Storage Tank TK-8 to charging isolation valves (open)
The justifications for not testing the above 15 items at full power are discussed below.
: a.      Manual Actuation Switches These would cause initiation of their protection system function at power causing equipment damage or plant upset. It should be noted that the reactor trip function that is derived from the automatic safety injection signal is tested at power as follows:
The analog signals, from which the automatic safety injection signal is derived, are tested at power in the same manner as the other analog signals as described in Subsection 7.2.2.2c. The processing of these signals in the Solid-State Protection System (SSPS) wherein their channel orientation converts to a logic train orientation is tested at power by the built-in semi-automatic test provisions of the SSPS. The reactor trip breakers are tested at power as discussed in Subsection 7.2.2.2c.
: b.      Turbine There is no practicable system design that would permit actual tripping of the turbine without adversely affecting the operability of the plant. The reactor trip functions that receive input from the turbine trip signal are tested prior to startup:
 
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: c. Closing the Main Steam Line Isolation Valves Main steam isolation valves are routinely tested by full closure during refueling outages. Testing of the main steam isolation valves by full closure at power is not practical. As the plant power is increased, the coolant average temperature is programmed to increase. If the valves are closed under these elevated temperature conditions, the steam pressure transient would unnecessarily operate the steam generator relief valves and possibly the steam generator safety valves.
The steam pressure transient produced would cause shrinkage in the steam generator level, which would cause the reactor to trip on low-low steam generator water level. Testing during operation will decrease the operating life of the valve.
Based on the above identified problems incurred with periodic testing by full closure of the main steam isolation valves at power and since (1) no practical system design will permit full closure of these valves without adversely affecting the safety or operability of the plant, (2) the probability that the protection system will fail to initiate the activated equipment is acceptably low due to testing up to final actuation, and (3) these valves will be routinely tested during refueling outages, the proposed resolution meets the guidelines of Section D.4 of Regulatory Guide 1.22.
: d. Closing the Feedwater Isolation Valve The feedwater isolation valves are routinely tested during refueling outages.
Periodic testing of these feedwater isolation valves by closing them completely at power would induce steam generator water level transients and oscillations which would trip the reactor. These transients conditions would be caused by perturbing the feedwater flow and pressure conditions necessary for proper operation of the variable-speed feedwater pump control system and the steam generator water level control system. Any operation which induces perturbations in the main feedwater flow, whether deliberate or otherwise, generally leads to a reactor trip and should be avoided.
Based on these identified problems incurred with periodic testing of the feedwater isolation valves at power and since (1) no practical system design will permit operation of these valves without adversely affecting the safety or operability of the plant, (2) the probability that the protection system will fail to initiate the activated equipment is acceptably low due to testing up to final actuation, and (3) these valves will be routinely tested during refueling outages, the proposed resolution meets the guidelines of Section D.4 of Regulatory Guide 1.22.
 
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: e. Closing the Feedwater Control Valves These valves are routinely tested during refueling outages. To close them at power would adversely affect the operability of the plant. The verification of operability of feedwater control valves at power is assured by confirmation of proper operation of the steam generator water level system. The actual actuation function of the solenoids, which provides the closing function, is periodically tested at power as discussed in Subsection 7.3.2.2e. The operability of the slave relay which actuates the solenoid, which is the actuating device, is verified during this test. Although the actual closing of these control valves is blocked when the slave relay is tested, all functions are tested to assure that no electrical malfunctions have occurred which could defeat the protective function. It is noted that the solenoids work on the de-energize-to-actuate principle, so that the feedwater control valves will fail closed upon either the loss of electrical power to the solenoids or loss of air pressure.
Based on the above, the testing of the isolating function of feedwater control valves meets the guidelines of Section D.4 of Regulatory Guide 1.22.
: f. Main Feedwater Pump Trip Solenoids No practical system design will permit full trip function testing the feedwater pumps without adversely affecting the safety and operability of the plant. At power, tripping of these pumps would introduce a steam generator level transient, resulting in unnecessary trip of the plant from low-low steam generator level.
Hence, the complete trip functions will be routinely tested during refueling outages and/or as required by Technical Specifications. However, any one of three electrical trip devices can be separately tested during power operation without a pump trip. The individual electrical trip devices are confirmed, one at a time, to trip and subsequently reset if the equipment operating conditions permit.
The high pressure and low pressure stop valves of the feedwater turbines can be tested during power operation. A 2-way solenoid valve is included on each stop valve assembly. When energized, this allows each stop valve to be test stroked with the turbine in service to ensure that the stop valve stem is not stuck. The LP stop valves are only partially closed. A limit switch provides control input to de-energize the solenoid valve at test position. Hence, the stop valve will move up and down through the limit switch deadband, to complete the test cycle. The HP stop valves are tested for fully closed operation if the equipment operating condition permits.
 
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: g. RCP Motor Component Cooling Water Isolation Valves (Close)
Component cooling water supply and return containment isolation valves are routinely tested during refueling outages. Testing of these valves while the reactor coolant pumps are operating introduces an unnecessary risk of costly damage to all the reactor coolant pumps. Loss of component cooling water to these pumps is of economic consideration only, as the reactor coolant pumps are not required to perform any safety-related function.
The reactor coolant pumps will not seize due to complete loss of component cooling. Information from the pump manufacturer indicates that the bearing babbitt would eventually break down but not rapidly enough to overcome the inertia of the flywheel. If the pumps are not stopped within 3 to 10 minutes after component cooling water is isolated, pump damage could be incurred.
Additional containment penetrations and containment isolation valves introduce additional unnecessary potential pathways for radioactive leakage following a postulated accident. Also, since the component cooling water flow rates and temperatures are about equal during both plant power operation and plant refueling, periodic tests of these valves during a refueling outage would duplicate accident conditions. Additionally, the possibility of failure of containment isolation is remote because an additional failure of the low-pressure fluid system in addition to failure of both isolation valves would have to occur to open a path through the Containment.
Based on the above described potential reactor coolant pump damage incurred with periodic testing of the component cooling water containment isolation valves at power, the duplication of at-power operating condition during refueling outages, and since (1) no practical system design will permit operation of these valves without adversely affecting the safety or operability of the plant, (2) the probability that the protection system will fail to initiate the activated equipment is acceptably low due to testing up to final actuation, and (3) these valves will be routinely tested during refueling outages when the reactor coolant pumps are not operating, the proposed resolution meets the guidelines of Section D.4 of Regulatory Guide 1.22.
 
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: h. Seal Water Return Valves (Close)
Seal return line isolation valves are routinely tested during refueling outages.
Closure of these valves during operation would cause the safety valve to lift, with the possibility of valve chatter. Valve chatter would damage this relief valve.
Testing of these valves at power would cause equipment damage. Therefore, these valves will be tested during scheduled refueling outages. As above, additional containment penetrations and containment isolation valves introduce additional unnecessary potential pathways for radioactive release following a postulated accident. Thus, the guidelines of Section D.4 of Regulatory Guide 1.22 are met.
: i. Charging Header to Cold Leg Isolation Valves The opening of these valves during the test of the actuating protection channel would adversely affect the operability of the plant. The probability that the protection system will fail to open these valves is acceptably low due to testing up to final actuation and the valves are routinely tested during refueling outages.
: j. Accumulator Isolation Valves (Open)
The position of the accumulator isolation valves is controlled by the Technical Specifications. The specifications require these valves to be open and power removed. Since the valves are maintained in actuated position, online testing of valve actuation is not required.
Based on the above, testing of the accumulator isolation valves meets the guidelines of Regulatory Guide 1.22 since (1) no practical system design will permit operation of these valves without adversely affecting the Technical Specifications, (2) the probability that the protection system will fail to initiate the activated equipment is acceptably low due to the valve being maintained open when RCS pressure is above 1000 psig and testing will be performed up to final actuation device, and (3) these valves will be routinely operated during the plant heatup and cooldown cycles.
: k. Charging and Letdown Isolation Valves (Close)
Charging and letdown isolation valves are routinely tested during refueling outages. Closure of these valves during power operation may damage plant equipment due to thermal cycling of mechanical joints and charging nozzles. The probability that the protection system will fail to close these valves is acceptably low due to testing up to final actuation.
 
SEABROOK                    INSTRUMENTATION AND CONTROLS                      Revision 19 STATION                                Introduction                          Section 7.1 UFSAR                                                                        Page 28
: l. Letdown Heat Exchanger Component Cooling Water Outlet Isolation Valve (Close)
The letdown heat exchanger component cooling water outlet isolation valve is routinely tested during refueling outages. Closure of this valve causes thermal cycling which may cause damage to plant equipment. The probability that the protection system will fail to close this valve is acceptably low due to testing up to final actuation.
: m. Reactor Coolant Pump Trip (Underfrequency)
There is no practical system design that would permit reactor coolant pump trip on underfrequency without adversely affecting the safety and operability of the plant. This function is provided to assure that in the event of decaying grid frequency and subsequent loss of power, the pumps have enough inertia to supply coolant flow on coastdown to cool the core. Refer to Subsection 7.2.1.1(4),
Reactor Coolant Low Flow Trips, for additional discussion of this function.
: n. Chemical and Volume Control System TK-1 Outlet Isolation Valves (Close)
Chemical and Volume Control System TK-1 outlet isolation valves are routinely tested during refueling outages. Closure of these valves during power operation may damage plant equipment due to pressure or temperature swings on the seal flow to the reactor coolant pumps or momentary loss of seal cooling flow. The probability that the protection system will fail to close these valves is acceptably low due to testing up to the final actuation device.
: o. Refueling Water Storage Tank TK-8 to Charging Pump Isolation Valves (Open)
Refueling Water Storage Tank TK-8 to charging pump isolation valves are routinely tested during refueling outages. Opening of these valves during power operation may damage plant equipment due to pressure or temperature swings on the seal flow to the reactor coolant pumps or momentary loss of seal cooling flow.
The probability that the protection system will fail to open these valves is acceptably low due to testing up to the final actuation device.
7.1.2.6        Conformance to Regulatory Guide 1.47 The bypass indication system which does not perform functions essential to public health and safety during an accident is designed to meet paragraph 4.13 of IEEE Standard 279-1971 and the intent of Regulatory Guide 1.47.
 
SEABROOK                    INSTRUMENTATION AND CONTROLS                    Revision 19 STATION                                  Introduction                        Section 7.1 UFSAR                                                                        Page 29 Automatic indication of the bypassed and inoperable status of safety systems is provided on the Video Alarm System (VAS). The VAS continuously monitors the status of selected components. When a bypass or inoperable condition is detected which results in either redundant train being inoperable, an audible alarm is sounded and an incoming alarm at the system (train) level is displayed on the VAS. The VAS also provides an overall system level alarm if both of the redundant trains are bypassed or made inoperable. When the bypass or inoperable condition affects only one channel of the protection system then only a channel level (not a system level) VAS alarm will be provided. The VAS alarm will be provided for the first condition if multiple, administratively controlled, conditions exist concurrently as part of a procedure which results in the bypass of a safety function. Once activated, the automatically initiated system level indication will remain on until the actuating condition is cleared and the VAS reset.
In addition to the automatic VAS display, manual bypassed and inoperable status indication is provided on the main control board for those systems whose complexity increases the possibility of having frequent inoperable conditions that are not monitored by the automatic system.
Indication is provided at the system level on a per train basis. Activation of an indicator on the bypassed and inoperable status panel is performed through manual actuation of its corresponding pushbutton. An exception to this is the system level indication associated with the diesel generator. These indicators are initiated automatically. The bypassed and inoperable status pushbuttons are also monitored by the VAS.
The VAS and the manual bypass and inoperable status indicators will automatically indicate the dependent auxiliary and safety systems that are made inoperable by a bypassed or inoperable safety system.
The design of the bypass indication system allows testing during normal operation.
The following rules are used to develop the system design, which satisfies Regulatory Guide 1.47:
: a.      System and component testing that can render a system inoperable must be scheduled more frequently than once/year to be input to the bypass and inoperable status alarm.
: b.      If a component is redundant within a redundant train, it will not be alarmed when bypassed or made inoperable.
: c.      If a component is positioned by procedure after an accident, and given that the accident analysis does not reflect the consequences of that component out of position prior to the accident, it will alarm when out of normal position.
 
SEABROOK                    INSTRUMENTATION AND CONTROLS                  Revision 19 STATION                                Introduction                        Section 7.1 UFSAR                                                                      Page 30
: d.      If a component is required to change state upon receipt of the safeguard signal, testing of that component would involve placing it in a position required for the accident. If an accident should occur while returning the component to its normal position, the safeguards signal will reposition it automatically. Input to the system bypassed and inoperable status alarm is not provided in this case.
The following lists the various systems provided with system level bypassed and inoperable status indication.
System Containment Building Spray (CBS)
Primary Component Cooling Water (CC)
Chemical and Volume Control (CS)
Feedwater (FW)
Residual Heat Removal (RH)
Safety Injection (SI)
Service Water (SW)
Main Steam (MS) (Auto Only)
Diesel Generators (DG) 7.1.2.7        Conformance to Regulatory Guide 1.53 and IEEE Standard 379-1972 The principles described in IEEE Standard 379-1972 were used in the design of the Westinghouse Protection System. The system complies with the intent of this standard and the additional guidance of Regulatory Guide 1.53 although the formal analyses have not been documented exactly as outlined.
See Subsection 7.2.2.2c(11) for a discussion of exceptions to the single failure criterion while a channel is bypassed for maintenance or testing.
Westinghouse has gone beyond the required analyses and has performed a fault tree analysis, Reference 1.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                      Revision 19 STATION                                    Introduction                          Section 7.1 UFSAR                                                                            Page 31 The referenced topical report provides details of the analyses of the protection systems previously made to show conformance with single failure criterion set forth in paragraph 4.2 of IEEE Standard 279-1971. The interpretation of single failure criterion provided by IEEE Standard 379-1972 does not indicate substantial differences with the Westinghouse interpretation of the criterion except in the methods used to confirm design reliability. Established design criteria in conjunction with sound engineering practices form the bases for the Westinghouse protection systems. The Reactor Trip and Engineered Safety Features Actuation Systems are each redundant safety systems. The required periodic testing of these systems will disclose any failures or loss of redundancy which could have occurred in the interval between tests, thus ensuring the availability of these systems.
The design of the BOP 1E systems complies with IEEE 379-1972 and the additional guidance of Regulatory Guide 1.53.
7.1.2.8          Conformance to Regulatory Guide 1.63 Conformance to Regulatory Guide 1.63 is discussed in Section 8.1 and Subsection 8.3.1.2.
7.1.2.9          Conformance to IEEE Standard 317-1972 Conformance to this IEEE standard is discussed in Section 8.1.
7.1.2.10        Conformance to IEEE Standard 336-1971 The installation and preoperational testing of Class 1E systems and related Class 1E electrical power, instrumentation and control equipment conforms or will conform to the requirements of IEEE Standard 336-1971. The quality assurance program for design, procurement and installation is described in Chapter 17 and the preoperational test procedures for each system are described in Chapter 14.
7.1.2.11        Conformance to IEEE Standard 338-1975 The periodic testing of the Reactor Trip System and the Engineered Safety Features Actuation System conforms to the requirements of IEEE Standard 338-1975, with the following comments:
: a.      The surveillance requirements of the Technical Specifications for the protection system ensure that the system functional operability is maintained comparable to the original design standards. Periodic tests at frequent intervals, or as determined by probabilistic risk/reliability evaluations, demonstrate this capability.
Overall protection systems response time shall be verified. Sensors will be verified adequate for this design by; (1) historical records based on acceptable response time tests (power interrupt tests), (2) in-place, onsite, or offsite (e.g. vendor) test measurements, or (3) utilizing vendor engineering specifications. The Nuclear Instrumentation System detectors are excluded since they exhibit response time characteristics such that delays attributable to them are negligible in the overall channel response time required for safety.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                    Revision 19 STATION                                  Introduction                        Section 7.1 UFSAR                                                                        Page 32 The measurement of response time at the time intervals in the Technical Specification provides assurance that the protective and engineered safety features action function associated with each channel is completed within the time limit assumed in the accident analyses.
: b.      The periodic time interval discussed in IEEE Standard 338-1975, and specified in the plant Technical Specifications, is conservatively selected to ensure that equipment associated with protection functions has not drifted beyond its minimum performance requirements. If any protection channel appears to be marginal, or requires more frequent adjustments due to plant condition changes, the time interval will be decreased to accommodate the situation until the marginal performance is resolved.
: c.      The test interval discussed in IEEE Standard 338-1975 is developed primarily on past operating experience and modified, if necessary, to assure that system and subsystem protection is reliably provided. Analytic methods for determining reliability are not used to determine test interval.
: d.      Nonroutine tests, such as operational tests performed when one of the redundant channels is inoperable, may require the use of temporary jumpers, lifted leads, or other circuit modifications.
: e.      See Subsection 7.2.2.2c(11) for a discussion of exceptions to the single failure criterion while a channel is bypassed for maintenance or testing.
Based on the scope definition give in IEEE Standard 338-1975, no other systems described in Chapter 7 are required to comply with this standard.
For detailed discussions regarding the testing of the non-NSSS ESF and 1E power systems, refer to Sections 7.3 and 8.3, respectively.
7.1.2.12        Conformance to Regulatory Guide 1.151 The recommendations of ISA Standard S67.02, 1980, as endorsed by Regulatory Guide 1.151, have been followed for the design and installation of safety-related instrument sensing lines, with the exceptions and clarifications listed below. See Subsections 1.8, 7.1.2.2, 7.1.2.1, 7.1.2.3 and 7.7.2 for discussions of specific sections.
: 1.      The instrumentation defined as Category 1 in UFSAR Section 7.5 is the only instrumentation considered to be required to monitor safety-related systems.
: 2.      In clarification of paragraph 5.2.2 (2) of ISA S67.02, where instrument tubing penetrates a shield wall, measures have been taken to reduce potential personnel exposure for radiation "streaming" from radioactive sources unless the radiation from piping nearby would be the larger source of exposure. These measures have included:
 
SEABROOK              INSTRUMENTATION AND CONTROLS                    Revision 19 STATION                            Introduction                        Section 7.1 UFSAR                                                                  Page 33
: a.      Locating penetration high enough to eliminate a concern from a radiation protection standpoint
: b.      Locating some penetrations to avoid a direct streaming path from the source of radiation
: c.      When the above two methods were not used, apply radiation absorbing penetration sealant.
: 3. The sensing lines from safety-related HVAC ductwork are designed to the same safety class as the ductwork, and are installed to the requirements of ANSI B31.1 Seismic Category I.
: 4. The sealed sensing lines for containment pressure, wide range reactor coolant pressure and the Reactor Vessel Level Indication System (RVLIS) are Safety Class 2 and installed to requirements of ANSI B31.1, Seismic Category I, rather than ASME Class 2 Seismic Category I, as recommended by Regulatory Position C.2.b or ISA S67.02, Section 4.1. The sealed, fluid-filled, instrumentation systems are in accordance with the standard Westinghouse design.
The containment penetration sleeve is part of the BOP scope and is ASME Class 2.
: 5. Common instrument taps are used for redundant sensors for pressurizer pressure and RCS flow (high pressure tap only). This is in conformance with the standard Westinghouse design.
: 6. An evaluation has been performed of those instrument lines which were downgraded in accordance with the provisions of this regulatory guide from ASME Class 2 or 3 to ANSI B31.1. This evaluation was done to determine if the failure of any of these lines would affect the safety function of the associated system. Where a passive failure of the instrument line would adversely affect the safety function of the system, an inspection of the line has been done to equivalent quality assurance requirements of ANS Safety Class 2 lines. Also, the lines have been installed to Seismic Category I criteria. Hence, a passive failure of one of these lines is not postulated to occur.
: 7. Commercial grade dedication may be used, where applicable, instead of the requirements of ISA-S67.02 Sections 4.2.2 and 8.2 for components installed in accordance with ANSI B31.1 Seismic Category I.
: 8. See Subsection 7.2.2.2c(11) for a discussion of exceptions to the single failure criterion while a channel is bypassed, i.e., removed from service, for maintenance or testing.
 
SEABROOK              INSTRUMENTATION AND CONTROLS                  Revision 19 STATION                          Introduction                      Section 7.1 UFSAR                                                              Page 34 7.1.3    References
: 1. Gangloff, W. C. and Loftus, W. D., "An Evaluation of Solid State Logic Reactor Protection in Anticipated Transients," WCAP-7706-L, July 1971 (Proprietary) and WCAP-7706, July 1971. (Nonproprietary).
: 2. Marasco, F. W. and Siroky, R. M., "Westinghouse 7300 Series Process Control System Noise Tests," WCAP-8892-A, June 1977.
: 3. Letter dated April 20, 1977 from R. L. Tedesco (NRC) to C. Eicheldinger (Westinghouse).
: 4. Katz, D.N., "Solid State Logic Protection System Description" WCAP-7488-L, January 1971 (Proprietary)
: 5. "Westinghouse Protection Systems Noise Tests," WCAP-12358, October 1975.
 
SEABROOK                    INSTRUMENTATION AND CONTROLS                    Revision 21 STATION                              Reactor Trip System                      Section 7.2 UFSAR                                                                        Page 1 7.2            REACTOR TRIP SYSTEM 7.2.1          Description 7.2.1.1        System Description The Reactor Trip System automatically keeps the reactor operating within a safe region by shutting down the reactor whenever the limits of the region are approached. The safe operating region is defined by several considerations such as mechanical/hydraulic limitations on equipment, and heat transfer phenomena. Therefore, the Reactor Trip System keeps surveillance on process variables which are directly related to equipment mechanical limitations, such as pressure, pressurizer water level (to prevent water discharge through safety valves, and uncovering heaters), and also on variables which directly affect the heat transfer capability of the reactor (e.g., flow and reactor coolant temperatures). Still other parameters utilized in the Reactor Trip Systems are calculated from various process variables. In any event, whenever a direct process or calculated variable exceeds a setpoint, the reactor will be shutdown to protect against either gross damage to fuel cladding or loss of system integrity which could lead to release of radioactive fission products into the Containment.
The following systems and equipment make up the Reactor Trip System (see References 1, 2 and 3 for additional background information).
: a.      Process Instrumentation System
: b.      Nuclear Instrumentation System
: c.      Solid-State Protection System
: d.      Reactor Trip Switchgear
: e.      Manual Actuation Circuit The Reactor Trip System consists of sensors, connected to signal processing circuitry consisting of two to four redundant channels, that monitor various plant parameters, and digital circuitry, consisting of two redundant logic trains which receive inputs from the signal processing channels to complete the logic necessary to automatically open the reactor trip breakers.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                        Revision 21 STATION                              Reactor Trip System                        Section 7.2 UFSAR                                                                            Page 2 Each logic train is capable of opening a separate and independent reactor trip breaker, RTA and RTB, respectively. The two trip breakers in series connect three-phase AC power from the rod drive motor generator sets to the rod drive power cabinets, as shown on Figure 7.2-2. During plant power operation, a DC undervoltage coil on each reactor trip breaker holds a trip plunger out against its spring, allowing the power to be available at the rod control power supply cabinets. For reactor trip, removal of DC voltage to the undervoltage trip attachment releases the trip plunger and trips open the breaker. In addition, removal of DC voltage de-energizes the shunt trip auxiliary relay which causes the shunt trip coil to be energized to provide diverse tripping of the breaker. When either of the trip breakers opens, power is interrupted to the rod drive power supply, and the control rods fall, by gravity, into the core. The rods cannot be withdrawn until the trip breakers are manually reset. The trip breakers cannot be reset until the abnormal conditions which initiated the trip are corrected. Bypass breakers BYA and BYB are provided to permit testing of the trip breakers, as discussed in Subsection 7.2.2.2c.
: a. Functional Performance Requirements The Reactor Trip System automatically initiates reactor trips:
: 1.      Whenever necessary to prevent fuel damage for an anticipated operational transient (Condition II)
: 2.      To limit core damage for infrequent faults (Condition III)
: 3.      So that the energy generated in the core is compatible with the design provisions to protect the reactor coolant pressure boundary for limiting fault conditions (Condition IV).
The Reactor Trip System initiates a turbine trip signal whenever reactor trip is initiated to prevent excessive reactor system cooldown which could result in reactivity insertion, reduced DNB ratio margin, and unnecessary safety injection actuation. This function is assumed in the accident analyses but it is not classified as a protective function.
The Reactor Trip System provides for manual initiation of reactor trip by operator action.
: b. Reactor Trips The various reactor trip circuits automatically open the reactor trip breakers whenever a condition monitored by the Reactor Trip System reaches a preset level. To ensure a reliable system, high quality design, components, manufacturing, quality control and testing are used. In addition to redundant channels and trains, the design approach provides a Reactor Trip System which monitors numerous system variables, therefore providing a large amount of protection system functional diversity. The extent of this diversity has been evaluated for a wide variety of postulated accidents (see Chapter 15).
 
SEABROOK              INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                        Reactor Trip System                        Section 7.2 UFSAR                                                                    Page 3 Table 7.2-1 provides a list of reactor trips which are described below.
: 1. Nuclear Overpower Trips The specific trip functions generated are as follows:
(a)    Power Range High Neutron Flux Trip The power range high neutron flux trip circuit trips the reactor when two of the four power range channels exceed the trip setpoint.
There are two bistables, each with its own trip setting used for a high and a low range trip setting. The high trip setting provides protection during normal power operation and is always active.
The low trip setting, that provides protection during startup, can be manually bypassed when two out of the four power range channels read above approximately 10 percent power (P-10). Three out of the four channels below 10 percent automatically reinstates the trip function. Refer to Table 7.2-2 for a listing of all protection system interlocks.
(b)    Intermediate Range High Neutron Flux Trip The intermediate range high neutron flux trip circuit trips the reactor when one out of the two intermediate range channels exceeds the trip setpoint. This trip, which provides protection during reactor startup, can be manually blocked if two out of four power range channels are above approximately 10 percent power (P-10). Three out of the four power range channels below this value automatically reinstate the intermediate range high neutron flux trip. The intermediate range channels (including detectors) are separate from the power range channels. The intermediate range channels can be individually bypassed at the nuclear instrumentation racks to permit channel testing during plant shutdown or prior to startup. This bypass action is annunciated on the control board.
 
SEABROOK          INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                    Reactor Trip System                        Section 7.2 UFSAR                                                                Page 4 (c)    Source Range High Neutron Flux Trip The source range high neutron flux trip circuit trips the reactor when one of the two source range channels exceeds the trip setpoint. This trip, which provides protection during reactor startup and plant shutdown, can by manually bypassed when one of the two intermediate range channels reads above the P-6 setpoint value and is automatically reinstated when both intermediate range channels decrease below the P-6 setpoint value.
This trip function can also be reinstated below P-10 by an administrative action requiring manual actuation of two control board-mounted switches. Each switch will reinstate the trip function in one of the two protection logic trains. The source range trip point is set between the P-6 setpoint (source range cutoff power level) and the maximum source range power level. The channels can be individually bypassed at the nuclear instrumentation racks to permit channel testing during plant shutdown or prior to startup. This bypass action is annunciated on the control board.
(d)    Power Range High Positive Neutron Flux Rate Trip This circuit trips the reactor when a sudden abnormal increase in nuclear power occurs in two out of four power range channels. This trip provides protection against rapid changes in neutron flux (e.g.
rod ejection accidents of low worth from mid-power or rapid RCCA withdrawal) and is always active.
Figure 7.2-3 shows the logic for all of the nuclear overpower and rate trips. (See Reference 2 for additional information.)
: 2. Core Thermal Overpower Trips The specific trip functions generated are as follows:
(a)    Overtemperature T Trip This trip protects the core against low DNBR and trips the reactor on coincidence as listed in Table 7.2-1 with one set of temperature measurements per loop. The setpoint for this trip is continuously calculated by analog circuitry for each loop by solving the following equation:
 
SEABROOK                INSTRUMENTATION AND CONTROLS                                Revision 21 STATION                          Reactor Trip System                              Section 7.2 UFSAR                                                                              Page 5 1 + 1 S  1 T
1 + 2 S  1 +3 S 1 + 4 S    1 T K 1 K 2                T        T' + K 3 (P  P') f 1 (I )
o 1 +5 S    1 +6 S Where:
T        = Measured T by RTD instrumentation 1, 2    = Time constants utilized in lead/lag controller for T 3        = Time constant utilized in the lag compensator for T Tc      = Indicated T at rated thermal power K1        = Preset bias K2        = Preset gain which compensates for piping and instrument time delay 1+4 S 1+5 S    = The function generated by the lead/lag controller for Tavg dynamic compensation 4, 5 =        Preset time constant which compensates for instrument time delay T      =        Average temperature, °F 6    =        Time constant utilized in the measured Tavg lag compensator T'    =        Indicated Tavg at rated thermal power K3    =        Preset gain which compensates for the effect of pressure on the DNB limits P      =        Pressurizer pressure, psig P'    =        Nominal RCS operating pressure S      =        Laplace transform operator, sec-1 f1(I) =        A function of the indicated difference between top and bottom detectors of the power-range nuclear ion chambers, with gains to be selected based on incore to excore calibrations.
A separate long ion chamber unit supplies the flux signal for each Overtemperature T trip channel.
 
SEABROOK              INSTRUMENTATION AND CONTROLS                                    Revision 21 STATION                            Reactor Trip System                                  Section 7.2 UFSAR                                                                                  Page 6 Increases in I beyond a pre-defined deadband result in decrease in trip setpoint. Refer to Figure 7.2-16. The required one pressurizer pressure parameter per loop is obtained from four pressure instruments on the pressurizer.
Figure 7.2-5 shows the logic for Overtemperature T trip function.
b)        Overpower T Trip This trip protects against excessive power (fuel rod rating protection) and trips the reactor on coincidence as listed in Table 7.2-1, with one set of temperature measurements per loop.
The setpoint for each channel is continuously calculated using the following equation:
1 + 1 S  1 T
1 +    S 2      1 +  S 3
S  1                        1 T o K 4 K 5  7                      T K 6 T          T" f 2 (I )
1 + 7 S  1 +6 S            1 +6 S Where:
T        = Measured T by RTD instrumentation 1, 2    = Time constants utilized in lead/lag controller for T 3        = Time constant utilized in the lag compensator for T To      = Indicated T at rated thermal power K4        = Preset bias K5        = A constant which compensates for instrument time delay 7        = Time constant utilized in rate-lag controller for Tavg 6        = Time constant utilized in the measured Tavg lag compensator K6        = A constant which compensates for the change in density flow and heat capacity of the water with temperature T        = Average temperature °F T"        = Indicated Tavg at rated thermal power S        = Laplace transform operator, sec-1
 
SEABROOK              INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                      Reactor Trip System                        Section 7.2 UFSAR                                                                    Page 7 f2(I)    = A function of the indicated difference between top and bottom detectors of the power-range nuclear ion chambers, with gains to be selected based on measured instrument response during plant startup tests.
A separate long ion chamber unit supplies the flux signal for each Over power T trip channel.
Increases in I beyond a pre-defined deadband result in a decrease in the trip setpoint. Refer to Figure 7.2-16.
The source of temperature and flux information is identical to that of the Overtemperature T trip and the resultant T setpoint is compared to the same T. Figure 7.2-5 shows the logic for this trip function.
: 3. Reactor Coolant System Pressurizer Pressure and Water Level Trips The specific trip functions generated are as follows:
(a)    Pressurizer Low Pressure Trip The purpose of this trip is to protect against low pressure which could lead to DNB. The parameter being sensed is reactor coolant pressure as measured in the pressurizer. Above P-7, the reactor is tripped when the pressurizer pressure measurements (compensated for rate of change) fall below preset limits. This trip is blocked below P-7. The trip logic and interlocks are given in Table 7.2-1.
The trip logic is shown on Figure 7.2-6.
(b)    Pressurizer High Pressure Trip The purpose of this trip is to protect the Reactor Coolant System against system overpressure.
The same sensors and transmitters used for the pressurizer low pressure trip are used for the high pressure trip except that separate bistables are used for the trip. These bistables trip when uncompensated pressurizer pressure signals exceed preset limits on coincidence as listed in Table 7.2-1. There are no interlocks or permissives associated with this trip function.
The logic for this trip is shown on Figure 7.2-6.
 
SEABROOK          INSTRUMENTATION AND CONTROLS                        Revision 21 STATION                  Reactor Trip System                          Section 7.2 UFSAR                                                                  Page 8 (c)    Pressurizer High Water Level Trip This trip is provided as a backup to the high pressurizer pressure trip and serves to prevent water relief through the pressurizer safety valves. This trip is blocked below P-7. The coincidence logic and interlocks of pressurizer high water level signals are given in Table 7.2-1.
The trip logic for this function is shown on Figure 7.2-6.
: 4. Reactor Coolant System Low Flow Trips These trips protect the core from DNB in the event of a loss-of-coolant flow situation. Figure 7.2-5 shows the logic for these trips. The means of sensing the loss-of-coolant flow are as follows:
(a)    Low Reactor Coolant Flow The parameter sensed is reactor coolant flow. Three differential pressure measurements at a piping elbow tap in each reactor coolant loop are used for the flow measurement. The basic function of this device is to provide information as to whether or not a reduction in flow has occurred. An output signal from two out of three bistables in a loop would indicate a low flow in that loop. The coincidence logic and interlocks are given in Table 7.2-1.
(b)    Reactor Coolant Pump Undervoltage Trip This trip is required in order to protect against low flow which can result from loss of voltage to at least one reactor coolant pump motor on each bus (e.g., from plant blackout or reactor coolant pump breakers opening).
There is one undervoltage sensing relay connected for each pump at the motor side of each reactor coolant pump breaker. These relays provide an output signal when the motor voltage goes below a preset level. Signals from these relays are time-delayed to prevent spurious trips caused by short-term voltage perturbations.
Channel response time includes consideration of the bus voltage decay time due to generated Electro-Motive Force (EMF) from motors connected to the bus as the motors coast down. The coincidence logic and interlocks are given in Table 7.2-1.
 
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The function of this trip is to trip the reactor in event of a decaying bus frequency condition. Subsection 8.2.3 provides additional details for the maximum credible frequency decay rate.
There is one underfrequency sensing relay for each reactor coolant pump motor. Underfrequency signals from two motors (one from each bus), time delayed to prevent spurious trips caused by short-term frequency perturbations, will trip the reactor if the power level is above P-7. (For an evaluation of under frequency transients, see Chapter 15.)
: 5. Steam Generator Trip The specific trip function generated is the low-low steam generator water level trip.
This trip protects the reactor from loss of heat sink. This trip is actuated on two out of four low-low water level signals occurring in any steam generator.
The level channels, which have condensate pots common to both steam flow transmitters and level transmitters, are lag compensated to prevent spurious trips caused by short-term pressure waves which are generated during rapid closure of the turbine control valves.
The logic is shown on Figure 7.2-7 (see Reference 1 for additional information).
 
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: 6. Reactor Trip on a Turbine Trip (anticipatory)
The reactor trip on a turbine trip is actuated by two out of three logic from emergency trip fluid pressure signals or by all closed signals from the turbine steam stop valves. A turbine trip causes a direct reactor trip above P-9. The reactor on turbine trip provides additional protection and conservatism beyond that required for the health and safety of the public.
This trip is included as part of good engineering practice and prudent design. No credit is taken in any of the safety analyses (Chapter 15) for this trip. The turbine provides anticipatory trips to the Reactor Protection System from contacts which change position when the turbine stop valves close or when the turbine emergency trip fluid pressure goes below its setpoint. One of the design bases considered in the protection system is the possibility of an earthquake. With respect to these contacts, their functioning is unrelated to a seismic event in that they are anticipatory to other diverse parameters which cause reactor trip. The contacts are closed during plant operation and open to cause reactor trip when the turbine is tripped. No power is provided to the protection system from the contacts; they merely serve to interrupt power to cause reactor trip. This design functions in a de-energize-to-trip fashion to cause a plant trip if power is interrupted in the trip circuitry. This ensures that the protection system will in no way be degraded by this anticipatory trip because seismic design considerations do not form part of the design bases for anticipatory trip sensors. (The reactor protection system cabinets which receive the inputs from the anticipatory trip sensors are, of course, seismically qualified as discussed in Section 3.10.) The SSPS input circuits in nonseismic structures are routed in conduit to maintain train separation and to prevent the application of fault voltages greater than the maximum credible fault voltages. The electrical and physical independence of the connecting cabling conforms to Regulatory Guide 1.75. The anticipatory trips thus meet IEEE 279-1971, including redundancy, separation, single failure, etc.
Seismic qualification of the contacts sensors is not required.
The logic for this trip is shown on Figure 7.2-15.
: 7. Safety Injection Signal Actuation Trip A reactor trip occurs when the Safety Injection System is actuated. The means of actuation the Safety Injection System are described in Section 7.3. This trip protects the core against a loss of reactor coolant or a steam line rupture.
Figure 7.2-8 shows the logic for this trip.
 
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: 8. Manual Trip The manual trip consists of two switches with two outputs on each switch.
One output is used to actuate the Train A reactor trip breaker, the other output actuates the Train B reactor trip breaker. Operating a manual trip switch removes the voltage from the undervoltage trip coil and energizes the shunt trip coil on each breaker.
There are no interlocks which can block this trip. Figure 7.2-3 shows the manual trip logic. The design conforms to Regulatory Guide 1.62, as shown on Figure 7.1-2.
: 9. General Warning Alarm Reactor Trip Each of the two trains of the Solid-State Protection System is continuously monitored by the general warning alarm reactor trip subsystem. The warning circuits are actuated if undesirable train conditions are set up by improper alignment of testing systems, circuit malfunction or failure, etc.,
as listed below. A trouble condition in a logic train is annunciated in the control room. However, if any one of the conditions exists in Train A at the same time any one of the conditions exists in Train B, the general warning alarm circuits will automatically trip the reactor.
(a)    Loss of either of two 48-volt DC or either of two 15-volt DC power supplies (b)    Printed circuit card improperly inserted (c)    Input error inhibit switch in the INHIBIT position (d)    Slave relay tester mode selector in TEST position (e)    Multiplexing selector switch in INHIBIT position (f)    Train bypass breaker racked in and closed (g)    Permissive or memory test switch not in OFF position (h)    Logic function test switch not in OFF position (i)    Loss of power to slave relay output cabinet.
 
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: c. Reactor Trip Interlocks
: 1. Power Escalation Permissives The overpower protection provided by the out-of-core nuclear instrumentation consists of three discrete, but overlapping, ranges.
Continuation of startup operation or power increase requires a permissive signal from the higher range instrumentation channels before the lower range level trips can be manually blocked by the operator.
A one of two intermediate range permissive signal (P-6) is required prior to source range level trip blocking and detector high voltage cutoff.
Source range level trips are automatically reactivated and high voltage restored when both intermediate range channels are below the permissive (P-6) setpoint. There are two manual reset switches for administratively reactivating the source range level trip and detector high voltage when between the permissive P-6 and P-10 setpoints, if required. Source range level trip block and high voltage cutoff are always maintained when above the permissive P-10 setpoint.
The intermediate range level trip and power range (low setpoint) trip can only be blocked after satisfactory operation and permissive information are obtained from two of four power range channels. Four individual blocking switches are provided so that the low range power range trip and intermediate range trip can be independently blocked (one switch for each train). These trips are automatically reactivated when any three of the four power range channels are below the permissive (P-10) setpoint, thus ensuring automatic activation to more restrictive trip protection.
The development of permissive P-6 and P-10 is shown on Figure 7.2-4.
All of the permissives are digital; they are derived from analog signals in the nuclear power range and intermediate range channels.
See Table 7.2-2 for the list of protection system interlocks.
: 2. Blocks of Reactor Trips at Low Power Interlock P-7 blocks a reactor trip at low power (below approximately 10 percent of full power) on a low reactor coolant flow in more than one loop, reactor coolant pump undervoltage, reactor coolant pump underfrequency, pressurizer low pressure, or pressurizer high water level.
See Figure 7.2-5 and Figure 7.2-6 for permissive applications. The low power signal is derived from three out of four power range neutron flux signals below the setpoint in coincidence with two out of two turbine impulse chamber pressure signals below the setpoint (low plant load). See Figure 7.2-4 and Figure 7.2-15 for the derivation of P-7.
 
SEABROOK                INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                        Reactor Trip System                        Section 7.2 UFSAR                                                                      Page 13 The P-8 interlock blocks a reactor trip when the plant is below approximately 50 percent of full power, on a low reactor coolant flow in any one loop. The block action (absence of the P-8 interlock signal) occurs when three out of four neutron flux power range signals are below the setpoint. Thus, below the P-8 setpoint, the reactor will be allowed to operate with one inactive loop and trip will not occur until two loops are indicating low flow. See Figure 7.2-4 for derivation of P-8, and Figure 7.2-5 for applicable logic.
The P-9 interlock blocks a reactor trip on a turbine trip when the plant is below approximately 45 percent of full power during normal power operation or below approximately 20 percent of full power during Tavg or Tavg/power coastdown operation. The turbine trip is sensed by either: (1) all turbine main stop valves closed or (2) two out of three low trip fluid pressure. The block action (absence of P-9 interlock signal) occurs when three of four neutron flux power range signals are below the setpoint.
Thus, below the P-9 setpoint, the reactor will be allowed to operate with the turbine tripped. See Figure 7.2-4 for the derivation of P-9 and Figure 7.2-15 for applicable logic.
See Table 7.2-2 for the list of protection system blocks.
: d. Coolant Temperature Sensor Arrangement The hot and cold leg temperature signals required for input to the protection and control functions are obtained using thermowell-mounted RTDs installed in each reactor coolant loop.
The hot leg temperature measurement in each loop is accomplished using three fast-response dual-element narrow-range RTDs mounted in thermowells. Two of the three thermowells of each loop are located within the existing hot leg scoops.
A third thermowell is mounted in the RCS process stream. On loops A, B, and D, this thermowell is mounted in an independent boss offset approximately 30° from the unused scoop location. On loop C the boss has been positioned approximately 12 inches upstream of the scoop location at approximately 105°. The two reused flow scoops have been modified by machining a flow hole in the end of the scoop to facilitate the flow of water through the leading edge of the scoop, past the thermowell and back into the pipe flow stream.
 
SEABROOK                INSTRUMENTATION AND CONTROLS                    Revision 21 STATION                        Reactor Trip System                      Section 7.2 UFSAR                                                                    Page 14 The temperature measured by each of the three thermowell-mounted RTDs, of each loop, is different due to hot leg temperature streaming. This temperature varies as a function of thermal power, core configuration and core age. Therefore, these signals are electronically averaged to generate a hot leg average temperature. If the active element of the dual-element RTD should fail, the second spare element will be wired into the processing cabinets. If the entire RTD has failed (i.e., the spare element is also inoperable), operation with two RTDs is acceptable. Provisions have been incorporated into the process electronics to allow for operation with only two RTDs in service. The two operable RTD measurements can be biased to compensate for the loss of the third.
The cold leg temperature measurement in each loop is accomplished by one fast-response dual-element narrow-range RTD. The original cold leg RTD bypass penetration nozzle has been modified to accept a thermowell. Temperature streaming in the cold leg is minimal due to the mixing action of the reactor coolant pump. Therefore, only a single temperature measurement is required in each cold leg.
: e. Pressurizer Water Level Reference Leg Arrangement The design of the pressurizer water level instrumentation employs the usual tank level arrangement using differential pressure between an upper and a lower tap on a column of water. A reference leg connected to the upper tap is kept full of water by condensation of steam at the top of the leg.
: f. Process Monitoring Process monitoring is performed by two instrumentation systems: the Process Instrumentation System and the Nuclear Instrumentation System.
Process Instrumentation System includes those analog and trip actuating devices (and their interconnection into systems) which measure voltage, frequency, valve position, temperature, pressure, fluid flow, and fluid level as in tanks or vessels.
        "Process" instrumentation specifically excludes nuclear and radiation measurements. The process instrumentation includes the field transmitters or process sensors, power supplies, indicators, recorders, alarm actuating devices, controllers, signal conditioning devices, etc., which are necessary for day-to-day operation of the Nuclear Steam Supply System as well as bistables for monitoring the plant and providing initiation of protective functions upon approach to unsafe plant conditions.
 
SEABROOK              INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                        Reactor Trip System                      Section 7.2 UFSAR                                                                    Page 15 The primary function of nuclear instrumentation is to protect the reactor by monitoring the neutron flux and generating appropriate trips and alarms for various phases of reactor operating and shutdown conditions. It also provides a secondary control function and indicates reactor status during startup and power operation. The Nuclear Instrumentation System uses information from three separate types of instrumentation channels to provide three discrete protection levels. Each range of instrumentation (source, intermediate, and power) provides the necessary overpower reactor trip protection required during operation in that range. The overlap of instrument ranges provides reliable continuous protection beginning with source level through the intermediate and low power level. As the reactor power increases, the overpower protection level is increased by administrative procedures after satisfactory higher range instrumentation operation is obtained. Automatic reset to more restrictive trip protection is provided when reducing power.
Various types of neutron detectors, with appropriate solid-state electronic circuitry, are used to monitor the leakage neutron flux from a completely shutdown condition to 120 percent of full power. The power range channels are capable of recording overpower excursions up to 200 percent of full power. The neutron flux covers a wide range between these extremes. Therefore, monitoring with several ranges of instrumentation is necessary.
The lowest range ("source" range) covers six decades of leakage neutron flux.
The lowest observed count rate depends on the strength of the neutron sources in the core and the core multiplication associated with the shutdown reactivity. This is generally greater than two counts per second. The next range ("intermediate" range) covers eight decades. Detectors and instrumentation are chosen to provide overlap between the higher portion of the source range and the lower portion of the power range. The highest range of instrumentation ("power" range) covers approximately two decades of the total instrumentation range. This is a linear range that overlaps with the higher portion of the intermediate range.
The system described above provides control room indication and recording of signals proportional to reactor neutron flux during core loading, shutdown, startup and power operation, as well as during subsequent refueling. Startup-rate indication for the source and intermediate range channels is provided at the control board. Reactor trip, rod stop, control and alarm signals are transmitted to the Reactor Control and Protection System for automatic plant control.
Equipment failures and test status information are annunciated in the control room.
 
SEABROOK                INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                        Reactor Trip System                        Section 7.2 UFSAR                                                                      Page 16 Trip actuating devices combine the process measuring, conditioning, and output functions into one device such as a pressure switch, limit switch, control switch, electrical relay, etc. Analog channel refers to signal processing equipment that provides interface with process measuring sensors; signal processing; limit checking; and output functions in one piece of equipment such as the Process Protection and Nuclear Instrumentation System cabinets.
See References 1 and 2 for additional background information on the process and nuclear instrumentation.
: g. Solid-State Protection System The logic portion consists of the Solid-State Protection System (SSPS). The SSPS takes binary inputs (voltage/no voltage) from the process and nuclear instrument channels corresponding to conditions (normal/abnormal) of plant parameters. The SSPS combines these signals in the required logic combination and generates a trip signal (no voltage) to the under voltage-trip attachment and shunt trip auxiliary relay coils (shunt trip coils are actually energized to trip, see Subsection 7.2.1.1) of the reactor trip circuit breakers when the necessary combination of signals occur. The system also provides annunciator, status light and computer input signals which indicate the condition of bistable input signals, partial trip and full trip functions and the status of the various blocking, permissive and actuation functions. In addition, the system includes means for semi-automatic testing of the logic circuits. See Reference 3 and 10 for additional background information.
: h. Isolation Amplifiers In certain applications, Westinghouse considers it advantageous to employ control signals derived from individual protection channels through isolation amplifiers contained in the protection channel, as permitted by IEEE Standard 279-1971.
In all of these cases, analog signals derived from protection channels for nonprotective functions are obtained through isolation amplifiers located in the analog racks. By definition, nonprotective functions include those signals used for control, remote process indication, and computer monitoring. Refer to Subsection 7.1.2.2a for discussion of electrical separation of control and protection functions. (See Reference 5 for isolation amplifier qualification-type tests.)
: i. Energy Supply and Environmental Variations The energy supply for the Reactor Trip System including the voltage and frequency variations, is described in Section 7.6 and Chapter 8.                  The environmental variations, throughout which the system will perform, are given in Section 3.11 and Chapter 8.
 
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: j. Setpoints The setpoints that require trip action are given in the Technical Specifications. A detailed discussion on setpoints is found in Subsection 7.1.2.1i.
: k. Seismic Design The seismic design considerations for the Reactor Trip System are given in Section 3.10. This design meets the requirements of Criterion 2 of the 1971 General Design Criteria (GDC).
7.2.1.2        Design Bases Information The information given below presents the design bases information requested by Section 3 of IEEE Standard 279-1971. Functional diagrams are presented in Figure 7.2-1, Figure 7.2-2, Figure 7.2-3, Figure 7.2-4, Figure 7.2-5, Figure 7.2-6, Figure 7.2-7, Figure 7.2-8, Figure 7.2-9, Figure 7.2-10, Figure 7.2-11, Figure 7.2-12, Figure 7.2-13, Figure 7.2-14 and Figure 7.2-15.
: a. Generating Station Conditions The following are the generating station conditions requiring reactor trip:
: 1.      DNBR approaching the safety analysis limit value.
: 2.      Power density (kilowatts per foot) approaching rated value for Condition II faults (see Chapter 4 for fuel design limits)
: 3.      Reactor Coolant System overpressure creating stresses approaching the limits specified in Chapter 5.
: b. Generating Station Variables The following are variables required to be monitored in order to provide reactor trips. (See Table 7.2-1).
: 1.      Neutron flux
: 2.      Reactor coolant temperature
: 3.      Reactor coolant system pressure (pressurizer pressure)
: 4.      Pressurizer water level
: 5.      Reactor coolant flow
: 6.      Reactor coolant pump operational status (voltage and frequency)
: 7.      Steam generator water level
: 8.      Turbine-generator operational status (trip fluid pressure and stop valve position).
 
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: c. Spatially Dependent Variables The following variables are spatially dependent:
: 1.      Reactor coolant temperature: See Subsection 7.3.1.2 for a discussion of this variable spatial dependence.
: 2.      Neutron flux: See Subsection 4.3.2.2 for a discussion of this variable spatial dependence.
: d. Limits, Margins and Set Points The parameter values that will require reactor trip are given in the Technical Specifications and in Chapter 15, Accident Analyses. Chapter 15 proves that the setpoints in the Technical Specifications and Core Operating Limits Report are conservative.
The setpoints for the various functions in the Reactor Trip System have been analytically determined so that the prescribed operational limits will prevent fuel rod clad damage and loss of integrity of the Reactor Coolant System as a result of any ANS Condition II incident (anticipated malfunction). As such, during any ANS Condition II incident, the Reactor Trip System limits the following parameters to:
: 1.      Minimum DNBR = the safety analysis limit value.
: 2.      Maximum system pressure = 2750 psia
: 3.      Fuel rod maximum linear power to the fuel design linear power limit for protection against fuel centerline melting.
The accident analyses described in Chapter 15 demonstrate that the function requirements as specified for the Reactor Trip System are adequate to meet the above considerations, even assuming, for conservatism, adverse combination of instrument errors (refer to Table 15.0-4). A discussion of the safety limits associated with the reactor core and Reactor Coolant System, plus the limiting safety system setpoints, are presented in the Technical Specifications and Core Operating Limits Report.
: e. Abnormal Events The malfunctions, accidents or other unusual events which could physically damage reactor trip system components or could cause environmental changes are as follows:
: 1.      Earthquakes (see Sections 2.5 and 3.7)
: 2.      Fire (see Section 9.5)
 
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: 3.      Explosion (hydrogen buildup inside Containment) (see Section 6.2)
: 4.      Missiles (see Section 3.5)
: 5.      Flood (see Sections 2.4 and 3.4)
: 6.      Wind and tornadoes (see Section 3.3)
: 7.      Lightning (see Section 2.3).
The Reactor Trip System fulfills the requirements of IEEE Standard 279-1971 to provide automatic protection and to provide initiating signals to mitigate the consequences of faulted conditions. The Reactor Trip System relies upon provisions made by the owner and operator of the plant to provide protection against destruction of the system from fires, explosions, missiles, floods, wind, lightning and tornadoes (see each item above).
: f.      Minimum Performance Requirements
: 1.      Reactor Trip System Response Times Reactor Trip System response time is defined in Section 7.1. Typical maximum allowable time delays in generating the reactor trip signal are tabulated in Table 7.2-3. See Subsection 7.1.2.11 for a discussion of periodic response time verification capabilities.
: 2.      Reactor Trip Accuracies Accuracy is defined in Section 7.1. Reactor trip accuracies are tabulated in Table 7.2-3. An additional discussion on accuracy is found in Subsection 7.1.2.1i.
: 3.      Protection System Ranges Typical Protection System ranges are tabulated in Table 7.2-3. Range selection for the instrumentation covers the expected range of the process variable being monitored during power operation. Limiting setpoints are at least 3 percent from the end of the instrument span.
7.2.2          Analyses 7.2.2.1        Failure Mode and Effects Analyses An analysis of the Reactor Trip System has been performed. Results of this study and a fault tree analysis are presented in Reference 4.
 
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The capability of the Reactor Trip System to prevent loss of integrity of the fuel cladding and/or reactor coolant system pressure boundary during Condition II, III, and IV transients is demonstrated in Chapter 15. These accident analyses are carried out using those setpoints determined from results of the engineering design studies. Setpoint limits are presented in the Technical Specifications. A discussion of the intent for each of the various reactor trips and the accident analyses (where appropriate) which use this trip is presented below. It should be noted that the selection of trip setpoints provide for margin before protection action is actually required to allow for uncertainties and instrument errors. The design meets the requirements of Criteria 10 and 20 of the 1971 GDC.
: a.      Trip Setpoint Discussion It has been pointed out previously that below a DNBR equal to the safety analysis limit value there is likely to be significant local fuel cladding failure. The DNBR existing at any point in the core for a given core design can be determined as a function of the core inlet temperature, power output, operating pressure and flow.
Consequently, core safety limits in terms of a DNBR equal to the safety analysis limit value for the hot channel can be developed as a function of core T, Tavg and pressure for a specified flow as illustrated by the solid lines in Figure 15.0-1.
Also shown as solid lines in Figure 15.0-1 are the loci of conditions equivalent to 118 percent of power as a function of T and Tavg representing the overpower (kW/ft) limit on the fuel. The dashed lines indicate the maximum permissible setpoint (T) as a function of Tavg and pressure for the overtemperature and overpower reactor trip. Actual setpoint constants in the equation representing the dashed lines are as given in the Technical Specifications.
These values are conservative to allow for instrument errors. The design meets the requirements of Criteria 10, 15, 20 and 29 of the 1971 GDC.
DNBR is not a directly measurable quantity; however, the process variables that determine DNBR are sensed and evaluated. Small isolated changes in various process variables may not individually result in violation of a core safety limit; whereas the combined variation, over sufficient time, may cause the overpower or overtemperature safety limit to be exceeded. The design concept of the Reactor Trip System recognizes this situation by providing reactor trips associated with individual process variables in addition to the overpower/overtemperature safety limit trips.
 
SEABROOK                INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                        Reactor Trip System                        Section 7.2 UFSAR                                                                    Page 21 Process variable trips prevent reactor operation whenever a change in the monitored value is such that a core or system safety limit is in danger of being exceeded should operation continue. Basically, the high pressure, low pressure and Overpower/Overtemperature T trips provide sufficient protection for slow transients as opposed to such trips as low flow or high flux which will trip the reactor for rapid changes in flow or flux, respectively, that would result in fuel damage before actuation of the slower responding T trips could be affected.
Therefore, the Reactor Trip System has been designed to provide protection for fuel cladding and reactor coolant system pressure boundary integrity where: (1) a rapid change in a single variable or factor will quickly result in exceeding a core or a system safety limit, and (2) a slow change in one or more variables will have an integrated effect which will cause safety limits to be exceeded. Overall, the Reactor Trip System offers diverse and comprehensive protection against fuel cladding failure and/or loss of reactor coolant system integrity for Condition II,III, and IV accidents. This is demonstrated by Table 7.2-4 which lists the various trips of the Reactor Trip System, the appropriate accident in the safety analyses in which the trip could be utilized and the corresponding limiting safety system setting Technical Specification.
It should be noted that the Reactor Trip System automatically provides core protection during nonstandard operating configuration, i.e., operation with a loop out of service. Although operating with a loop out of service over an extended time is considered to be an unlikely event and is not allowed by the plant operating license, no protection system setpoints would need to be reset. This is because the nominal value of the power (P-8) interlock setpoint restricts the power so that DNB ratios less than the safety analysis limit value will not be realized during any Condition II transients occurring during this mode of operation. This restricted power is considerably below the boundary of permissible values as defined by the core safety limits for operation with a loop out of service. Thus, the P-8 interlock acts essentially as a high nuclear power reactor trip when operating with one loop not in service.
The design meets the requirements of Criterion 21 of the 1971 GDC.
Preoperational testing is performed on reactor trip system components and systems to determine equipment readiness for startup. This testing serves as a further evaluation of the system design.
Analyses of the results of Conditions I, II, III and IV events, including considerations of instrumentation installed to mitigate their consequences, are presented in Chapter 15. The instrumentation installed to mitigate the consequences of load rejection and turbine trip is given in Section 7.7.
 
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: b. Reactor Coolant Flow Measurement The elbow taps used on each loop in the primary coolant system are instrument devices that indicate the status of the reactor coolant flow. The basic function of this device is to provide information as to whether or not a reduction in flow has occurred. The correlation between flow and elbow tap signal is given by the following equation:
P  w  2
              =
P o  w o where Po is the pressure differential at the reference flow wo, and P is the pressure differential at the corresponding flow, w. The full flow reference point is established during initial plant startup. The low flow trip is then established by extrapolating along the correlation curve. The expected absolute accuracy of the channel is within +/-10 percent of full flow and field results have shown the repeatability of the trip point to be within +/-1 percent.
: c. Evaluation of Compliance to Applicable Codes and Standards The Reactor Trip System meets the criteria of the General Design Criteria as indicated. The Reactor Trip System meets the requirements of Section 4 of IEEE Standard 279-1971, as indicated below.
: 1.      General Functional Requirement The protection system automatically initiates appropriate protective action whenever a condition monitored by the system reaches a preset level.
Functional performance requirements are given in Subsection 7.2.1.1a.
Subsection 7.2.1.2d presents a discussion of limits, margins and levels; Subsection 7.2.1.2e discusses unusual (abnormal) events; and Subsection 7.2.1.2f presents minimum performance requirements.
: 2.      Single Failure Criterion The protection system is designed to provide two, three, or four instrumentation channels for each protective function and two logic train circuits. These redundant channels and trains are electrically isolated and physically separated. Thus, any single failure within a channel or train will not prevent protective action at the system level when required. Loss of input power, the most likely mode of failure, to a channel or logic train will result in a signal calling for a trip. This design meets the requirements of Criterion 23 of the 1971 GDC.
 
SEABROOK          INSTRUMENTATION AND CONTROLS                    Revision 21 STATION                  Reactor Trip System                      Section 7.2 UFSAR                                                              Page 23 To prevent the occurrences of common mode failures, such additional measures as functional diversity, physical separation, and testing as well as administrative control during design, production, installation and operation are employed, as discussed in Reference 4. The design meets the requirements of Criteria 21 and 22 of the 1971 GDC.
: 3. Quality of Components and Modules For a discussion on the quality of the components and modules used in the Reactor Trip System, refer to Chapter 17. The quality assurance applied conforms to Criterion 1 of the 1971 GDC.
: 4. Equipment Qualification For a discussion of the type tests and/or analyses made to verify the performance requirements, refer to Section 3.11. The tests results demonstrate that the design meets the requirements of Criterion 4 of the 1971 GDC.
: 5. Channel Integrity Protection system channels required to operate in accident conditions maintain necessary functional capability under extremes of condition relating to environment, energy supply, malfunction, and accidents. The energy supply for the Reactor Trip System is described in Chapter 8. The environmental variations throughout which the system will perform are given in Section 3.11.
: 6. Independence Channel independence is carried throughout the system, extending from the sensor through to the devices actuating the protective function.
Physical separation is used to achieve separation of redundant transmitters.
Separation of wiring is achieved using separate wireways, cable trays, conduit runs and containment penetrations for each redundant channel.
Redundant analog equipment is separated by locating modules in different protection cabinets. Each redundant protection channel set is energized from a separate AC power feed. This design meets the requirements of Criterion 21 of the 1971 GDC.
Two reactor trip breakers, which are actuated by two separate logic matrices, interrupt power to the control rod mechanisms. The breaker main contacts are connected in series with the power supply so that opening either breaker interrupts power to all control rod drive mechanisms, permitting the rods to free fall into the core. See Figure 7.1-1.
 
SEABROOK          INSTRUMENTATION AND CONTROLS                        Revision 21 STATION                    Reactor Trip System                        Section 7.2 UFSAR                                                                  Page 24 The design philosophy is to make maximum use of a wide variety of measurements. The protection system continuously monitors numerous diverse protection variable. Generally, two or more diverse protection functions would terminate reactor operation before intolerable consequences could occur. This design meets the requirements of Criterion 22 of the 1971 GDC.
: 7. Control and Protection System Interaction The protection system is designed to be independent of the control system.
In certain applications the control signals and other nonprotective functions are derived from individual protective channels through isolation amplifiers. The isolation amplifiers are classified as part of the protection system and are located in the analog protective racks. Nonprotective functions include those signals used for control, remote process indication, and computer monitoring. The isolation amplifiers are designed so that a short circuit, open circuit, or the application of credible fault voltages from within the cabinets on the isolated output portion of the circuit (i.e., the nonprotective side of the circuit) will not affect the input (protective) side of the circuit. The signals obtained through the isolation amplifiers are never returned to the protective racks. This design meets the requirement of Criterion 24 of the 1971 GDC and paragraph 4.7 of IEEE Standard 279-1971.
The results of applying various malfunction conditions on the output portion of the isolation amplifiers show that no significant disturbance to the isolation amplifier input signal occurred.
See Subsection 7.2.2.2c(11) for a discussion of exceptions to the single failure criterion while a channel is bypassed for maintenance or testing and Subsection 7.2.2.3 for a discussion of specific control and protection interactions.
: 8. Derivation of System Inputs To the extent feasible and practical, protection system inputs are derived from signals which are direct measures of the desired variables. Variables monitored for the various reactor trips are listed in Subsection 7.2.1.2b.
 
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: 9. Capability for Sensor Checks The operational availability of each system input sensor and that portion of the channel related to indication during reactor operation is accomplished by channel checks. Channel checks provide qualitative cross checking between channels that bear a known relationship to each other and that have read-outs available. Channel checks are discussed in Technical Specification 3/4.3 and Table 4.3-1 of the Technical Specifications.
: 10. Capability For Testing The Reactor Trip System is capable of being tested during power operation. Where only parts of the system are tested at any one time, the design is capable of providing the necessary overlap between the parts to assure complete system operation. The testing capabilities are in conformance with Regulatory Guide 1.22 as discussed in Subsection 7.1.2.5.
The protection system is designed to permit periodic testing of the process monitoring portion of the Reactor Trip System during reactor power operation without initiating a protective action unless a trip condition actually exists. This is because of the coincidence logic required for reactor trip. These tests may be performed at any plant power from cold shutdown to full power. Before starting any of these tests with the plant at power, all redundant reactor trip channels associated with the function to be tested must be in the normal (untripped) mode in order to avoid spurious trips. Setpoints are referenced in the Standard Instrument Schedule and Technical Specifications. Bypass Test Instrumentation (BTI) features have been added to selected Process and Nuclear Instrumentation System channels to permit periodic testing with the monitoring portion of the channel in bypass rather than in trip. This eliminates the potential for a reactor trip caused by spurious actuation of a redundant channel when a channel is in trip for testing.
(a)    Analog Channel Operational Tests Analog Channel Operational Tests (ACOTs) are performed on the Process and Nuclear Instrumentation Systems between channel calibrations to detect process monitoring failures which are not detectable by channel checks.
 
SEABROOK INSTRUMENTATION AND CONTROLS                      Revision 21 STATION          Reactor Trip System                        Section 7.2 UFSAR                                                      Page 26 Process Instrumentation Channel Operational Tests The analog channels of the Process Instrumentation System are tested by individually introducing simulated input signals into the analog channels and observing the tripping of the appropriate output bistables. When a channel with a normally energized SSPS input relay is tested in trip, the output to the logic circuitry is interrupted by a test switch which, when thrown, de-energizes the associated logic input and inserts a proving lamp in the bistable output. BTI is connected downstream of the channel test card, thus enabling the bypass of the entire analog channel for surveillance testing or maintenance.
If BTI is not used, interruption of the bistable output to the logic circuitry for any cause (test, maintenance, or removal from service) will cause that portion of the logic circuitry to be actuated (partial trip) accompanied by a partial trip alarm and channel status light actuation in the control room. If BTI is used, the logic circuitry will not be actuated. Each channel contains those switches, test points, etc., necessary to test the channel. See References 1 and 2 additional non-BTI background information.
The following Process Instrumentation System analog channel periodic tests are performed:
(1)    Tavg and T protection channel testing (2)    Pressurizer pressure protection channel testing (3)    Pressurizer water level protection channel testing (4)    Steam generator water level protection channel testing (5)    Reactor coolant low flow protection channels testing.
Nuclear Instrumentation Analog Channels Operational Tests
 
SEABROOK INSTRUMENTATION AND CONTROLS                      Revision 21 STATION          Reactor Trip System                        Section 7.2 UFSAR                                                      Page 27 The power range analog channels of the Nuclear Instrumentation System are tested either by superimposing a test signal on the actual detector signal being received by the channel at the time of testing or by injecting a test signal in place of the actual detector signal. The output of the bistable is not placed in a tripped condition prior to testing. Also, since the power range channel logic is two out of four, bypass of this reactor trip function is not required but has been provided to minimize the potential for spurious trips. BTI is connected to the power, intermediate, and source range channel output, thus enabling the bypass of the entire analog channel for surveillance testing or maintenance.
To test a power range channel, a "TEST-OPERATE" switch is provided to require deliberate operator action, operation of which will initiate an alarm in the control room. If BTI is not used, bistable operation is tested by increasing the test signal to its trip setpoint and verifying bistable relay operation by control board annunciator and trip status lights.
It should be noted that if the test signal is superimposed on the detector signal a valid trip signal would cause the channel under test to trip at a lower actual reactor power level. A reactor trip would occur when a second bistable trips.
If BTI is used, the logic circuitry will not be actuated and bistable operation will be indicated at the nuclear instrumentation cabinet.
The trip of a second channel will not result in a reactor trip.
A nuclear instrumentation system channel which can cause a reactor trip through one of two protection logic (source or intermediate range) is provided with a bypass function which prevents the initiation of a reactor trip from that particular channel during the short period that it is undergoing test. These bypasses are indicated by status lights or a VAS alarm in the control room.
The following Nuclear Instrumentation System periodic tests are performed:
(1)    Testing at plant shutdown Source range testing Intermediate range testing Power range testing
 
SEABROOK    INSTRUMENTATION AND CONTROLS                        Revision 21 STATION              Reactor Trip System                        Section 7.2 UFSAR                                                            Page 28 (2)    Testing between P-6 and P-10 permissive power levels Intermediate range testing Power range testing (3)    Testing above P-10 permissive power level Power range testing (with exception of the low power setpoint)
Any deviations noted during the performance of these tests are investigated and corrected in accordance with the established calibration and trouble-shooting procedures provided in the plant technical manual for the Nuclear Instrumentation System.        Control and protection trip settings are indicated in the standard instrument schedule.
For additional background information on the Nuclear Instrumentation System, see Reference 2.
(b)  Trip Actuating Device Operational Testing A trip actuating device operational test is performed in trip by exercising the monitored component/system or introducing simulated input signals into the instrumentation channel and observing actuation of the appropriate SSPS logic circuitry (partial trip) accompanied by a partial trip alarm and channel status light actuation in the control room. The reactor coolant pump (RCP) undervoltage (UV) and underfrequency (UF) channels have Bypass Test Instrumentation (BTI) features which provide for testing the field contact without de-energizing the UV or UF time delay relays or actuating the SSPS.
The following trip actuating device periodic tests are performed:
(1)    Reactor coolant pump underfrequency and undervoltage protection channel testing.
(2)    Turbine-generator trip fluid pressure and stop valve position testing.
 
SEABROOK    INSTRUMENTATION AND CONTROLS                      Revision 21 STATION              Reactor Trip System                      Section 7.2 UFSAR                                                          Page 29 (c)  Channel Calibration Channel calibrations are performed at the refueling frequency. The channel calibration is a complete check of the instrument channel, including the required sensor, alarm, interlock, display, and trip functions. Overlap of the monitoring and logic portions of the Reactor Trip System is verified for the channels which were tested in bypass. Calibration of instrument channels with resistance temperature detector (RTD) or thermocouple sensors may consist of an in-place assessment of sensor behavior and normal calibration of the remaining adjustable devices in the channel. The channel calibration may be performed by means of any series of sequential, overlapping calibrations or total channel steps so that the entire channel is calibrated.
(d)  Solid-State Protection System Logic Testing The Reactor Trip System logic trains are part of the Solid-State Protection System (SSPS) and are designed to be capable of complete testing at power. After the individual process monitoring channel testing is complete, the logic matrices are tested from the Train A and Train B logic rack test panels. During this test, all of the logic inputs are actuated automatically in all combinations of trip and nontrip logic. Trip logic is not maintained sufficiently long enough to permit opening of the reactor trip breakers. The reactor trip undervoltage coils are "pulsed" in order to check continuity. During logic testing of one train, the other train can initiate any required protective functions.        Annunciation is provided in the control room to indicate when a train is in test (train output bypassed) and when a reactor trip breaker is bypassed. Logic testing can be performed in less than 30 minutes.
This design complies with the testing requirements of IEEE Standard 279-1971 and IEEE Standard 338-1975 discussed in Subsection 7.1.2.11.
The permissive and block interlocks associated with the Reactor Trip System and Engineered Safety Features Actuation System are given on Table 7.2-2 and Table 7.3-2 and designated protection or "P" interlocks. As a part of the protection system, these interlocks are designed to meet the testing requirements of IEEE Standard 279-1971 and 338-1975.
 
SEABROOK INSTRUMENTATION AND CONTROLS                        Revision 21 STATION          Reactor Trip System                        Section 7.2 UFSAR                                                        Page 30 Testing of all protection system interlocks is provided by the logic testing and semi-automatic testing capabilities of the Solid-State Protection System. In the Solid-State Protection System, the undervoltage trip attachment and shunt trip auxiliary relay coils (Reactor Trip) and master relays (Engineered Safeguards Features Actuation) are pulsed for all combinations of trip or actuation logic with and without the interlock signals. For example, reactor trip on low flow (2 out of 4 loops showing 2 out of 3 low flow) is tested to verify operability of the trip above P-7 and nontrip below P-7 (see Figure 7.2-5). Interlock testing may be performed at power.
Testing of the logic trains of the Reactor Trip System includes a logic matrix check and may include a check of the input relays.
The following sequence is used to test the system:
(1)    Check of Input Relays When the process instrumentation system and nuclear instrumentation system channels are tested in trip, each channel bistable is placed in a trip mode causing one input relay in Train A and one in Train B to de-energize. A refueling frequency has been justified for the testing of normally energized input relays (Reference 7). All input relays are tested at refueling intervals. A contact of each relay is connected to a universal logic printed circuit card.
This card performs both the reactor trip and monitoring functions. Each reactor trip input relay contact causes a status lamp on the control board to operate and provides an input to the Video Alarm System (VAS). Either the Train A or Train B input relay operation will light the status lamp and provide the VAS alarm.
Each train contains a multiplexing test switch. During a process or nuclear instrumentation system test, this switch (in either train) is in the A + B position. The A + B position alternately allows information to be transmitted from the two trains to the control board. A steady status lamp and annunciator indicates that input relays in both trains have been de-energized. A flashing lamp means that the input relays into the two trains did not both de-energize.
 
SEABROOK INSTRUMENTATION AND CONTROLS                    Revision 21 STATION        Reactor Trip System                        Section 7.2 UFSAR                                                    Page 31 Trip actuating device or associated auxiliary relay contact inputs to the SSPS, such as reactor coolant pump bus underfrequency relays, operate input relays which are tested by operating the remote contacts as described above and using the same type of indications as those provided for bistable input relays.
Actuation of the input relays provides the overlap between the testing of the SSPS and the testing of those systems supplying the inputs to the SSPS. Test indications are status lamps and VAS alarms on the control board. Inputs to the SSPS are checked one channel at a time, leaving the other channels in service. For example, a function that trips the reactor when two out of four channels trip becomes a one-out-of-three trip when one channel is placed in the trip mode or reverts to two-out-of-three when the channel is tested in bypass. Both trains of the SSPS remain in service during this portion of the test.
(2)  Check of Logic Matrices Logic matrices are checked one train at a time. Input relays are not operated during this portion of the test. Reactor trips from the train being tested are inhibited with the use of the input error inhibit switch on the semi-automatic test panel in the train. At the completion of the logic matrix tests, the input error is verified removed and returned to normal by the performance of continuity checks of the input inhibit error circuit.
The logic test scheme uses pulse techniques to check the coincidence logic.        All possible trip and nontrip combinations are checked. Pulses from the tester are applied to the inputs of the universal logic card at the same terminals that connect to the input relay contacts. Thus there is an overlap between the input relay check and the logic matrix check. Pulses are fed back from the reactor trip breaker undervoltage trip attachment and shunt trip auxiliary relay coils to the tester. The pulses are of such short duration that the reactor trip breaker undervoltage coil armature cannot respond mechanically.
 
SEABROOK    INSTRUMENTATION AND CONTROLS                      Revision 21 STATION            Reactor Trip System                        Section 7.2 UFSAR                                                          Page 32 Test indications that are provided are an annunciator in the control room indicating that reactor trips from the train have been blocked and that the train is being tested, and green and red lamps on the semi-automatic tester to indicate a good or bad logic matrix test. Protection capability provided during this portion of the test is from the train not being tested.
The testing capability meets          the  requirements  of Criterion 21 of the 1971 GDC.
(e)  Testing of Reactor Trip Breakers Normally, reactor trip breakers 52/RTA and 52/RTB are in service, and bypass breakers 52/BYA and 52/BYB are withdrawn (out of service). In testing the protection logic, pulse techniques are used to avoid tripping the reactor trip breakers thereby eliminating the need to bypass them during this testing. The following procedure describes the method used for testing the trip breakers:
(1)    With bypass breaker 52/BYA racked out, manually close and trip it to verify its operation.
(2)    Rack in and close 52/BYA. Manually trip 52/RTA through a protection system logic matrix while at the same time operating the "Auto Shunt Trip Block" push button on the automatic shunt trip panel. This verifies operation of the Undervoltage Trip Attachment (UVTA) when the breaker trips. After reclosing RTA, trip it again by operation of the "Auto Shunt Trip Test" push- button on the automatic shunt trip panel. This is to verify tripping of the breaker through the shunt trip device.
(3)    Reset 52/RTA.
(4)    Trip and rack out 52/BYA.
(5)    Repeat above steps to test trip breaker 52/RTB using bypass breaker 52/BYB.
 
SEABROOK INSTRUMENTATION AND CONTROLS                        Revision 21 STATION        Reactor Trip System                          Section 7.2 UFSAR                                                        Page 33 If an event requiring a reactor trips occurs during the testing of the reactor trip breaker, the bypass breaker 52/BYA would receive an undervoltage trip signal from the B train SSPS. 52/BYA also receives a shunt trip signal from the A train manual trip switch output. Similarly the bypass breaker 52/BYB would receive an undervoltage trip signal from the A train SSPS and a shunt trip signal from the B train manual trip switch output.
Auxiliary contacts of the bypass breakers are connected into the general warning alarm logic of their respective trains so that if either train is placed in test or if an attempt is made to close the bypass breaker while the bypass breaker of the other train is closed, both reactor trip breakers and both bypass breakers will automatically trip.
The Train A and Train B general warning alarm logics operate separate VAS alarms in the control room. The two bypass breakers also operate separate VAS alarms.
Bypassing of a protection train with either the bypass breaker or with the test switches will result in audible and visual indications.
The complete Reactor Trip System is normally required to be in service. However, to permit online testing of the various protection channels or to permit continued operation in the event of a subsystem instrumentation channel failure, Technical Specification 3/4.3 defining the minimum number of operable channels, has been formulated. This Technical Specification also defines the required restriction to operation in the event that the channel operability requirements cannot be met.
 
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: 11. Channel Bypass or Removal from Operation The protection system is designed to permit periodic testing of the Reactor Trip System during reactor power operation without initiating a protective action unless a trip condition actually exists. Protective action is prevented by the coincidence logic required for reactor trip and the Bypass Test Instrumentation provided for most channels. IEEE Standard 279-1971, Paragraph 4.11, provides an exception to the single failure criterion for one-out-of-two systems during channel bypass where acceptable reliability of operation can be demonstrated. WCAP-10271 and its supplements and revisions, Reference 7, demonstrate acceptable protection system reliability for one-out-of-two systems when channels are bypassed for maintenance and testing.
WCAP-10271 also demonstrates acceptable protection system reliability for certain two-out-of-three and two-out-of-four systems during channel bypass for maintenance and testing. WCAP-10271, Supplement 2, Revision 1, concludes that the rationale for the single failure exception for one-out-of-two systems is equally applicable to two-out-of-three and two-out-of-four systems where acceptable reliability of operation can be demonstrated.
This exception is applicable to the following protection system functions:
Functions with two-out-of-three logic RCS Flow Lo Reactor Trip Pressurizer Pressure Lo P-11 Pressurizer Level Hi Reactor Trip Steam Generator Pressure Lo/Rate Hi Safety Injection/Main Steam Isolation Containment Pressure Hi-1/Hi-2 Safety Injection/Main Steam Isolation Functions with two-out-of-four logic which have a control/protection interaction Pressurizer Pressure Lo/Hi Reactor Trip Pressurizer Pressure Lo-Lo Safety Injection Steam Generator Level Lo Reactor Trip/Emergency Feedwater Actuation Steam Generator Level Hi Turbine Trip/Feedwater Isolation
 
SEABROOK            INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                    Reactor Trip System                        Section 7.2 UFSAR                                                                  Page 35 The NRC has accepted the generic approach of bypassing channels for the performance of maintenance and testing in the safety evaluations which are attached to WCAP-10271. In the NRC Safety Evaluation related to Amendment No. 36 to the Seabrook Station Operating License, Reference 9, the NRC stated that the generic analyses used in WCAP-10271 and its supplements are applicable to Seabrook Station. Channel bypass for testing and maintenance, using permanent test equipment which avoids the lifting of leads and/or the installation of jumpers, was accepted in the safety evaluation for Amendment No. 36.
: 12. Operating Bypasses Where operating requirements necessitate automatic or manual bypass of a protective function, the design is such that the bypass is removed automatically whenever permissive conditions are not met. Devices used to achieve automatic removal of the bypass of a protective function are considered part of the protective system and are designed in accordance with the criteria of this section. Indication is provided in the control room if some part of the system has been administratively bypassed or taken out of service.
: 13. Indication of Bypasses Indication of bypass for the reactor protection system is provided by status lights or by VAS alarms. Bypass of a reactor trip breaker, the protection system output, or a monitoring channel is alarmed for each train or protection set on the VAS.
: 14. Access to Means for Bypassing The design provides for administrative control of access to the means for manually bypassing channels or protective functions.
: 15. Multiple Setpoints For monitoring neutron flux, multiple setpoints are used. When a more restrictive trip setting becomes necessary to provide adequate protection for a particular mode of operation or set of operating conditions, the protective system circuits are designed to provide positive means or administrative control to assure that the more restrictive trip setpoint is used. The devices used to prevent improper use of less restrictive trip settings are considered part of the protective system and are designed in accordance with the criteria of this section.
 
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: 16. Completion of Protective Action The protection system is so designed that, once initiated, a protective action goes to completion. Return to normal operation requires action by the operator.
: 17. Manual Initiation Switches are provided on the control board for manual initiation of protective action. Failure in the automatic system does not prevent the manual actuation of the protective functions. Manual actuation relies on the operation of a minimum of equipment.
: 18. Access The design provides for administrative control of access to all setpoint adjustments, module calibration adjustments, and test points.
: 19. Identification of Protective Actions Protective channel identification is discussed in Subsection 7.1.2.3.
Indication is discussed in Item 20 below.
: 20. Information Read-Out The protective system provides the operator with complete information pertinent to system status and safety. All transmitted signals (flow, pressure, temperature, etc.) which can cause a reactor trip will be either indicated or recorded for every channel, including all neutron flux power range currents (top detector, bottom detector, algebraic difference and average of bottom and top detector currents).
Any reactor trip will actuate an alarm and an annunciator. Such protective actions are indicated and identified down to the channel level.
Alarms and annunciators are also used to alert the operator of deviations from normal operating conditions so that he may take appropriate corrective action to avoid a reactor trip. Actuation of any rod stop or trip of any reactor trip channel will actuate an alarm.
: 21. System Repair The system is designed to facilitate the recognition, location, replacement, and repair of malfunctioning components or module. Refer to the discussion in Item 10 above.
 
SEABROOK                  INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                          Reactor Trip System                        Section 7.2 UFSAR                                                                      Page 37 7.2.2.3    Specific Control and Protection Interactions
: a. Neutron Flux Four power range neutron flux channels are provided for overpower protection.
An isolated auctioneered high signal is derived by auctioneering of the four channels for automatic rod control. If any channel fails in such a way to produce a low output, that channel is incapable of proper overpower protection but will not cause control rod movement because of the auctioneer. Two out of four overpower trip logic will ensure an overpower trip if needed even with an independent failure in another channel.
In addition, channel deviation signals in the control system will give an alarm if any neutron flux channel deviates significantly from the average of the flux signals. Also, the control system will respond only to rapid changes in indicated neutron flux; slow changes or drifts are compensated by the temperature control signals. Finally, an overpower signal from any nuclear power range channel will block manual and automatic rod withdrawal. The set point for this rod stop is below the reactor trip setpoint.
: b. Coolant Temperature The accuracy of the resistance temperature detector (RTD) loop temperature measurements is demonstrated during plant startup tests by comparing temperature measurement from all loop RTDs with one another as well as with the temperature measurements obtained from the wide-range RTDs located in the hot leg and cold leg piping of each loop. The linearity of the T measurements obtained from the hot leg and cold leg loop RTDs as a function of plant power is also checked during plant startup tests. The absolute value of T versus plant power is not important, per se, as far as reactor protection is concerned. Reactor trip system setpoints are based upon percentages of the indicated T at nominal full power rather than on absolute values of T. This is done to account for loop differences which are inherent. The percent T scheme is relative, not absolute, and therefore provides better protective action without the expense of accuracy.
For this reason, the linearity of the T signals as a function of power is of importance rather than the absolute values of the T.
Reactor control is based upon signals derived from protection system channels after isolation by isolation amplifiers so that no feedback effect can perturb the protection channels.
 
SEABROOK                INSTRUMENTATION AND CONTROLS                    Revision 21 STATION                        Reactor Trip System                      Section 7.2 UFSAR                                                                    Page 38 The Tavg (rod) control system is based on average Tavg. Margins to DNB have been analyzed based on the uncertainties for average Tavg. These uncertainties have been appropriately determined such that the deviation from the highest loop Tavg to the average Tavg has been explicitly addressed and will not result in a loss of analyzed DNB margin.
A spurious low average temperature measurement from any loop temperature control channel will cause the Average Tavg input signal to the control system to decrease. This will result in a demand for rod withdrawal (due to Average Tavg /
Tref mismatch) and a demand for reduction in charging flow (due to pressurizer level program signal mismatch). The effect of the charging flow change is bounded by analysis in Section 15.6, Decrease in Reactor Coolant Inventory. If this failure were to occur when the control rods are fully withdrawn there would be no rod withdrawal. If this failure were to occur when the rods were not fully withdrawn a rod withdrawal and subsequent power increase would occur. This event is bounded by the analysis in Section 15.4.2, Uncontrolled Rod Cluster Control Assembly Bank Withdrawal at Power.
A spurious high average temperature measurement from any loop temperature control channel will cause the Average Tavg input signal to the control system to increase. This will result in a demand for rod insertion (safe direction) due to Average Tavg / Tref mismatch.
Channel deviation signals in the control system will give an alarm if any temperature channel deviates significantly from the average value. Alarms for an approach to Overpower or Overtemperature T reactor trip are also provided if any two of the four Overtemperature or Overpower T channels indicate an adverse condition.
: c. Pressurizer Pressure The pressurizer pressure protection channel signals are used for high and low pressure protection and as inputs to the Overtemperature T trip protection function. Isolated output signals from these channels are used for pressure control. These are used to control pressurizer spray and heaters and power-operated relief valves. Pressurizer pressure is sensed by fast response pressure transmitters.
A spurious high pressure signal from one channel can cause decreasing pressure by actuation of either spray or relief valves. Additional redundancy is provided in the low pressurizer pressure reactor trip and in the logic for safety injection to ensure low pressure protection.
 
SEABROOK                INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                        Reactor Trip System                        Section 7.2 UFSAR                                                                      Page 39 Overpressure protection is based upon the positive surge of the reactor coolant produced as a result of turbine trip under full load, assuming the core continues to produce full power. The self-actuated safety valves are sized on the basis of steam flow from the pressurizer to accommodate this surge at a setpoint of 2500 psia and an accumulation of 3 percent. Note that no credit is taken for the relief capability provided by the power-operated relief valves during this surge.
: d. Pressurizer Water Level Three pressurizer water level channels are used for reactor trip. Isolated signals from these channels are used for pressurizer water level control. A failure in the level control system could fill or empty the pressurizer at a slow rate (on the order of half an hour or more).
The high water level trip setpoint provides sufficient margin so that the undesirable condition of discharging liquid coolant through the safety valves is avoided. Even at full power conditions, which would produce the worst thermal expansion rates, a failure of the water level control would not lead to any liquid discharge through the safety valves. This is due to the automatic high pressurizer pressure reactor trip actuating at a pressure sufficiently below the safety valve setpoint.
For control failures which tend to empty the pressurizer, two out of four logic for safety injection actuation on low pressure ensures that the protection system can withstand an independent failure in another channel. In addition, ample time and alarms exist to alert the operator of the need for appropriate action.
: e. Steam Generator Water Level The basic function of the reactor protection circuits associated with low-low steam generator water level is to preserve the steam generator heat sink for removal of long-term residual heat. Should a complete loss of feedwater occur, the reactor would be tripped on low-low steam generator water level. In addition, redundant emergency feedwater pumps are provided to supply feedwater in order to maintain residual heat removal after trip. This reactor trip acts before the steam generators are dry. This reduces the required capacity, increases the time interval before emergency feedwater pumps are required, and minimizes the thermal transient on the Reactor Coolant System and steam generators. Therefore, a low-low steam generator water level reactor trip circuit is provided for each steam generator to ensure that sufficient initial thermal capacity is available in the steam generator at the start of the transient. Two-out-of-four low-low steam generator water level trip logic ensures a reactor trip if needed even with an independent failure in another channel used for control and when degraded by an additional second postulated random failure.
 
SEABROOK                INSTRUMENTATION AND CONTROLS                    Revision 21 STATION                        Reactor Trip System                      Section 7.2 UFSAR                                                                    Page 40 A spurious low signal from the feedwater flow channel being used for control would cause an increase in feedwater flow. The mismatch between steam flow and feedwater flow produced by the spurious signal would actuate alarms to alert the operator of the situation in time for manual correction. If the condition continues, a two-out-of-four high-high steam generator water level signal in any loop, independent of the indicated feedwater flow, will cause feedwater isolation and trip the turbine. The turbine trip will result in a subsequent reactor trip if power is above the P-9 setpoint. The high-high steam generator water level trip is an equipment protective trip preventing excessive moisture carryover which could damage the turbine blading.
In addition, the three element feedwater controller incorporates reset action on the level error signal, so that with expected controller settings a rapid increase or decrease in the flow signal would cause only a small change in level before the controller would compensate for the level error. A slow change in the feedwater signal would have no effect at all. A spurious low or high steam flow signal would have the same effect as high or low feedwater signal, discussed above.
A spurious high steam generator water level signal from the protection channel used for control will tend to close the feedwater valve. A spurious low steam generator water level signal will tend to open the feedwater valve. Before a reactor trip would occur, two-out-of-four channels in a loop would have to indicate a low-low water level. Any slow drift in the water level signal will permit the operator to respond to the level alarms and take corrective action.
Automatic protection is provided in case the spurious high level reduces feedwater flow sufficiently to cause low-low level in the steam generator.
Automatic protection is also provided in case the spurious low level signal increases feedwater flow sufficiently to cause high level in the steam generator.
A turbine trip and feedwater isolation would occur on two-out-of-four high-high steam generator water level in any loop.
 
SEABROOK                    INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                              Reactor Trip System                        Section 7.2 UFSAR                                                                          Page 41 7.2.2.4        Additional Postulated Accidents Loss of plant instrument air or loss of component cooling water is discussed in Subsection 7.3.2.3. Load rejection and turbine trip are discussed in further detail in Section 7.7.
The control interlocks, called rod stops, that are provided to prevent abnormal power conditions which could result from excessive control rod withdrawal are discussed in Subsection 7.7.1.4a and listed on Table 7.7-1. Excessively high power operation (which is prevented by blocking of automatic rod withdrawal), if allowed to continue, might lead to a safety limit (as given in the Technical Specification) being reached. Before such a limit is reached, protection will be available from the Reactor Trip System. At the power levels of the rod block setpoints, safety limits have not been reached; therefore, these rod withdrawal stops do not come under the scope of safety-related systems, and are considered as control systems.
7.2.3          Tests and Inspections The Reactor Trip System meets the testing requirements of IEEE Standard 338-1975, as discussed in Subsection 7.1.2.11. The testability of the system is discussed in Subsection 7.2.2.2c. The test intervals are specified in the Technical Specifications. All active devices will be tested at the operational test frequency unless a lower frequency is justified. Passive devices will be checked at the same frequency where practicable (Reference 6). References 7 and 8 document the operational test frequency and justify channel calibration frequency for testing of the normally energized SSPS input and RCP UV/UF time delay relays for channels which are tested in bypass. All components will be tested at the channel calibration frequency. Written test procedures and documentation, conforming to the requirements of IEEE Standard 338-1975, will be available for audit by responsible personnel. Periodic testing complies with Regulatory Guide 1.22, as discussed in Subsections 7.1.2.5 and 7.2.2.2c.
All active components can be tested at the operational test frequency. A lower testing frequency may be justified if adequate reliability is assured. Passive components will be tested at the operational test frequency where practicable.
7.2.4          References
: 1.      Reid, J. B., "Process Instrumentation for Westinghouse Nuclear Steam Supply Systems," WCAP-7913, January 1973. (Addition background information only)
: 2.      Lipchak, J. B., "Nuclear Instrumentation System," WCAP-8255, January 1974.
(Additional background information only)
: 3.      Katz, D. N., "Solid State Logic Protection System Description," WCAP-7488-L, January 1971 (Proprietary) and WCAP-7672, June 1971 (Nonproprietary).
(Additional background information only)
: 4.      Gangloff, W. C. and Loftus, W. D., "An Evaluation of Solid State Logic Reactor Protection in Anticipated Transients," WCAP-7706-L, February 1971 (Proprietary) and WCAP-7706, July 1971 (Nonproprietary).
 
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: 5. Marasco, F. W. and Siroky, R. M., "Westinghouse 7300 Series Process Control Noise Tests," WCAP-8892-A, June 1977.
: 6.  "Overlap Testing Requirements," NAESCo Engineering Evaluation 95-22, September 1995.
: 7.  "Evaluation of Surveillance Frequencies and Out of Service Times for the Reactor Protection Instrumentation System," WCAP-10271-P-A, May 1986; Supplement 1, May 1986; and Supplement 2, Revision 1, June 1990.
: 8.  "Risk/Reliability Evaluation of SSPS Input Relays and Timers in the Bypass Test Scheme," NAESCo Engineering Evaluation 95-20, August 1995.
: 9.  "Safety Evaluation by the Office of Nuclear Reactor Regulation Related to Amendment No. 36 to Facility Operating License No. NPF-86," April 10, 1995.
: 10. Gruber, T.J. and Ryan, M.L., "Westinghouse SSPS Board Replacement Licensing Summary Report", WCAP-17867-P-A, Revision 1, October 2014 (Proprietary).
: 11. Surveillance Frequency Control Program as defined in Technical Specification 6.7.6.n approved by License Amendment No. 141 to the Facility License.
 
SEABROOK                  INSTRUMENTATION AND CONTROLS                      Revision 21 STATION              Engineered Safety Features Actuation System            Section 7.3 UFSAR                                                                        Page 1 7.3            ENGINEERED SAFETY FEATURES ACTUATION SYSTEM In addition to the requirements for a reactor trip for anticipated abnormal transients, the facility is provided with adequate instrumentation and controls to sense accident situations and initiate the operation of necessary Engineered Safety Features (ESF). The occurrence of a limiting fault, such as a loss-of-coolant accident or a steam line break, requires a reactor trip plus actuation of one or more of the Engineered Safety Features to prevent or mitigate damage to the core and reactor coolant system components, and ensure containment integrity.
To accomplish these design objectives, the Engineered Safety Features System has proper and timely initiating signals which are to be supplied by the sensors, transmitters and logic components making up the various instrumentation channels of the Engineered Safety Features Actuation System.
7.3.1          Description The Engineered Safety Features Actuation System uses selected plant parameters, determines whether or not predetermined safety limits are being exceeded and, if they are, combines the signals into logic matrices sensitive to combinations indicative of primary or secondary system boundary ruptures (Class III or IV faults). Once the required logic combination is completed, the system sends actuation signals to the appropriate engineered safety features components. The Engineered Safety Features Actuation System meets the requirements of Criteria 13, 20, and 38 of the 1971 General Design Criteria (GDC).
7.3.1.1        System Description The Engineered Safety Features Actuation System is a functionally defined system described in this section.      The equipment which provides the actuation functions identified in Subsection 7.3.1.1a is listed below and discussed in this section. For additional background information refer to References 1, 2 and 3 and Sections 11.5 and 12.3.4.
* Process Instrumentation System (Reference 1)
* Radiation Monitoring System (Sections 11.5 and 12.3.4)
* Solid-State Protection System (Reference 2)
* Engineered Safety Features Test Cabinet (Reference 3)
* Manual Actuation Circuits The Engineered Safety Features Actuation System consists of sensors, connected to signal processing circuitry consisting of two to four redundant channels that monitor various plant parameters, and digital circuitry consisting of two redundant logic trains which receive inputs from the signal processing channels to complete the logic needed to actuate the Engineered Safety Features.
 
SEABROOK                    INSTRUMENTATION AND CONTROLS                    Revision 21 STATION              Engineered Safety Features Actuation System          Section 7.3 UFSAR                                                                      Page 2 Each of the two logic trains is capable of actuating the Engineered Safety Features equipment required. The intent is that any single failure within the Engineered Safety Features Actuation System shall not prevent system action when required.
The redundant concept is applied to both the monitoring and logic portions of the system.
Separation of redundant monitoring channels begins at the process sensors and is maintained in the field wiring, containment vessel penetrations and electronics terminating at the redundant safeguards logic racks. The design meets the requirements of Criteria 20, 21, 22, 23 and 24 of the 1971 GDC.
The variables are sensed by the monitoring portion as discussed in Reference 1 and in Sections 7.2, 11.5 and 12.3.4. The outputs from the monitoring portion are combined into actuation logic as shown on Figure 7.2-5, Figure 7.2-6, Figure 7.2-7 and Figure 7.2-8.
Table 7.3-1 gives additional information pertaining to logic and function.
The interlocks associated with the Engineered Safety Features Actuation System are outlined in Table 7.3-2. These interlocks satisfy the functional requirements discussed in Subsection 7.1.2.
Manual actuation from the control board of containment isolation Phase A is provided by operation of either one of the redundant momentary containment isolation Phase A controls.
Each manual actuation switch actuates the equipment in its respective train. In a similar manner, manual actuation of containment spray and containment isolation Phase B is initiated from the control board, except that two switches must be operated for each train. Also on the control board, are manual actuation switches for safety injection. Each of these controls are dual train switches, which will actuate both Train A and Train B equipment.
Manual controls are also provided to switch from the injection to the recirculation phase after a loss-of-coolant accident.
The transfer from the injection to the recirculation phase is initiated automatically and completed manually by operator action from the main control board. Protection logic is provided to automatically open the two recirculation sump isolation valves on a 2/4 RWST Lo-Lo level in conjunction with initiation of an "S" signal (see Figure 7.6-4, sh.1, and Figure 7.6-4, sh.2). This aligns the two RHR pumps to take suction from the containment sump and to deliver directly to the RCS without stopping the RHR pumps. The charging/safety injection pumps will continue to take suction from the RWST, during the above automatic action, until manual operator action is initiated to align these pumps in series with the RHR pumps. The Safety Injection System will be aligned for cold leg recirculation after the completion of the required manual actions.
 
SEABROOK                  INSTRUMENTATION AND CONTROLS                      Revision 21 STATION              Engineered Safety Features Actuation System            Section 7.3 UFSAR                                                                        Page 3 Refer to Subsections 6.3.2.8 and 7.6.5 for additional discussions of recirculation initiation.
: a. Function Initiation The specific functions which rely on the Engineered Safety Features Actuation System for initiation are:
: 1.      A reactor trip, provided one has not already been generated the by Reactor Trip System (see Figure 7.2-2).
: 2.      Opening of cold leg injection isolation valves for injection of borated water by charging and safety injection pumps into the cold legs of the Reactor Coolant System.
: 3.      Start of charging pumps, safety injection pumps, residual heat removal pumps and actuation of associated valving to provide emergency makeup water to the cold legs of the Reactor Coolant System following a loss-of-coolant accident.
: 4.      The start of the containment enclosure emergency exhaust filter fans and the filtration system designed to function following a LOCA to maintain a negative pressure within the enclosure by exhausting air and in-leakage to the plant unit vent (see Drawing NHY-503515).
: 5.      Start of motor-driven and turbine-driven emergency feedwater pumps, and actuation of associated valves to provide secondary heat removal (see Figure 7.2-14).
: 6.      Phase A containment isolation, whose function is to prevent fission product release (isolation of all lines not essential to reactor protection).
See Figure 7.2-8.
: 7.      Steam line isolation to prevent the continuous, uncontrolled blowdown of more than one steam generator and thereby uncontrolled reactor coolant system cooldown (see Figure 7.2-8).
: 8.      Isolation of the nonnuclear parts of the Component Cooling Water and Service Water Systems (see Drawings NHY-503273 and NHY-503965).
: 9.      Automatic opening of the isolation valves in the cooling water discharge lines of the residual heat removal heat exchangers (see Drawing NHY-503271).
: 10. Main feedwater line isolation as required to prevent or mitigate the effect of excessive cooldown (see Figure 7.2-13, sh.1).
: 11. Start of the emergency diesels to assure backup supply of power to emergency and supporting systems components (see Figure 7.2-8).
 
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: 12. The start of emergency cleanup filter system, designed to clean up a portion of recirculated air and meet control room occupancy requirements following a loss-of-coolant accident (see Drawing NHY-503242).
: 13. Containment spray actuation which performs the following functions:
(a)    Initiates containment spray to reduce containment pressure and temperature following a loss-of-coolant or steam line break accident inside of Containment (see Figure 7.2-8).
(b)    Initiation of Phase B containment isolation which isolates the Containment following a loss of reactor coolant accident, or a steam or feedwater line break within containment to limit radioactive releases. (Phase B isolation together with Phase A isolation results in isolation of all but Engineered Safety Features lines penetrating the Containment.) See Figure 7.2-8.
(c)    Opens the isolation valves in the cooling water discharge lines for the containment spray heat exchangers (see Drawing NHY-503271).
: 14. Switchover of the RHR and containment spray system pump suction from the RWST to the containment sump (see Figure 7.6-4, sh.1 and sh.2).
: 15. Start of containment structure recirculating filter fans (see Drawing NHY-503204).
: 16. Containment Ventilation Isolation (see Figure 7.2-8).
: b. Process Monitoring Process monitoring is performed by the Process Instrumentation and Radiation Data Management Systems. The monitoring sensors and signal processing circuits for the Engineered Safety Features Actuation System are covered in Reference 1 and Sections 11.5 and 12.3.4. The parameters to be measured including pressures, flows, tank and vessel water levels, radiation levels, and temperatures, as well as the measurement and signal transmission considerations, are discussed. These latter considerations include the sensors, transmitters, orifices and flow elements, resistance temperature detectors, as well as automatic calculations, signal conditioning and location and mounting of the devices.
The sensors monitoring the primary system are located as shown on the piping flow diagrams in Chapter 5, Reactor Coolant System. The secondary system sensor locations are shown on the steam system flow diagrams given in Chapter 10.
 
SEABROOK              INSTRUMENTATION AND CONTROLS                    Revision 21 STATION          Engineered Safety Features Actuation System          Section 7.3 UFSAR                                                                  Page 5 Containment pressure is sensed by four physically separated differential pressure transmitters connected to containment atmosphere by a filled and sealed hydraulic transmission system. These transmitters are mounted on seismically qualified supports outside of Containment. The distance from penetration to transmitter is kept to a minimum, and separation is maintained. This arrangement, together with the pressure sensors external to the Containment, forms a double barrier and conforms to GDC 56 and Regulatory Guide 1.141, as well as the intent of Regulatory Guide 1.11.
Radiation sensors are located as shown in Sections 11.5 and 12.3.4.
: c. Logic Circuitry The Engineered Safety Features Actuation System logic and actuation functions are performed by the Solid-State Protection System (SSPS) which is discussed in detail in Reference 2 and 8. The description includes the considerations and provisions for physical and electrical separation as well as details of the circuitry.
Reference 2 also covers certain aspects of online test provisions, provisions for test points, considerations for the instrument power source and considerations for accomplishing physical separation. The outputs from the analog channels are combined into actuation logic as shown on Figure 7.2-5 (Tavg), Figure 7.2-6 (Pressurizer Pressure), Figure 7.2-7 (Steam Line Pressure and Steam Line Pressure Rate), Figure 7.2-8 (Engineered Safety Features Actuation), and Figure 7.2-14 (Emergency Feedwater Pumps Startup).
To facilitate Engineered Safety Features Actuation testing, four cabinets (two per train) are provided which enable operation, to the maximum practical extent, of safety features loads on a group by group basis until actuation of all devices has been checked. Final actuation testing is discussed in detail in Subsection 7.3.2.
: d. Final Actuation Circuitry The outputs of the Solid-State Protection System (the slave relays) are energized to actuate, as are most final actuators and actuated devices. These devices are listed as follows:
: 1.      Safety injection system pump and valve actuators. See Chapter 6 for flow diagrams and additional information.
: 2.      Containment isolation (Phase A - "T" signal isolates all nonessential process lines on receipt of safety injection signal; Phase B - "P" signal isolates remaining process lines (which do not include Engineered Safety Features lines) on receipt of 2/4 Hi-3 containment pressure signal). For further information, see Subsection 6.2.4.
 
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: 3. Component cooling water system and service water system valve actuators (see Subsection 9.2.2)
: 4. Emergency feed pumps start (see Subsection 6.8.5)
: 5. Diesel start (see Section 8.3)
: 6. Feedwater isolation (see Section 10.4)
: 7. Containment air purge isolation valves (see Section 6.2)
: 8. Steam line isolation valve actuators (see Section 10.3)
: 9. Containment spray pump and valve actuators (see Section 6.2)
: 10. Control room emergency cleanup filter system fans and dampers (see Subsection 9.4.1)
: 11. Containment recirculation fans and dampers (see Subsection 9.4.5)
: 12. Containment enclosure emergency cleanup filter system fans and dampers (see Subsection 9.4.6).
If an accident is assumed to occur coincident with a loss of offsite power, the Engineered Safety Features loads must be sequenced onto the diesel generators to prevent overloading the diesel generator. This sequence is discussed in Section 8.3. The design meets the requirements of Criterion 35 of the 1971 GDC.
: e. Support Systems The following systems are required for support of the Engineered Safety Features:
: 1. Service Water - Heat Removal (see Subsection 9.2.1)
: 2. Primary Component Cooling Water System - Heat Removal (see Subsection 9.2.2)
: 3. Electrical Power Distribution Systems (see Chapter 8)
: 4. Heating, ventilation and air conditioning system for the ESF equipment locations (see Section 9.4)
: 5. Diesel generator and associated diesel fuel storage and transfer systems (see Section 9.5).
 
SEABROOK                  INSTRUMENTATION AND CONTROLS                      Revision 21 STATION              Engineered Safety Features Actuation System            Section 7.3 UFSAR                                                                        Page 7 7.3.1.2      Design Bases Information The functional diagrams presented in Figure 7.2-5, Figure 7.2-6, Figure 7.2-7 and Figure 7.2-8 provide a graphic outline of the functional logic associated with requirements for the Engineered Safety Features Actuation System. Requirements for the Engineered Safety Features System are given in Chapter 6. Given below is the design bases information required in IEEE Standard 279-1971, Reference 4.
: a. Generating Station Conditions The following is a summary of those generating station conditions requiring protective action:
: 1.      Primary System (a)    Rupture in small pipes or cracks in large pipes (b)    Rupture of a reactor coolant pipe (loss-of-coolant accident)
(c)    Inadvertent opening of a pressurizer relief or safety valve (d)    Steam generator tube rupture (e)    Dropped fuel assembly.
: 2.      Secondary System (a)    Minor secondary system pipe breaks resulting in steam release rates equivalent to a single dump, relief or safety valve (b)    Rupture of a major steam pipe.
(c)    Loss of feedwater
: b. Generating Station Variables The following list summarizes the generating station variables required to be monitored for the automatic initiation of ESF during each accident identified in the preceding section. Post-accident monitoring requirements are given in Table 7.5-1.
: 1.      Primary System Accidents (a)    Pressurizer pressure (b)    Containment pressure and radiation (not required for steam generator tube rupture)
(c)    Reactor coolant temperature (monitored by the operator; its automatic protective action is to stop feed flow)
 
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: 2.      Secondary System Accidents (a)    Pressurizer pressure (b)    Steam line pressures and steam line pressure rates (c)    Containment pressure (d)    Refueling water storage tank level (e)    Steam generator level
: c. Spatially Dependent Variables The variables sensed by the Engineered Safety Features Actuation System which have spatial dependence are reactor coolant hot leg temperature and containment manipulator crane area radiation. The spatial dependence of the reactor coolant hot leg temperature is accounted for by taking three temperatures from the RCS hot leg and electronically averaging the signals to generate a hot leg average temperature. The spatial dependence of the radiation field associated with a fuel handling accident is considered in the placement of the radiation sensors on the containment manipulator crane. In this location, the sensors are close as possible to a dropped fuel assembly while remaining above water level in the refueling canal.
: d. Limits, Margins and Setpoints Prudent operation limits, available margins and setpoints before onset of unsafe conditions requiring protective action are discussed in Chapter 15 and the Technical Specifications.
: e. Abnormal Events The malfunctions, accidents, or other unusual events which could physically damage protection system components or could cause environmental changes are as follows:
: 1.      Loss-of-coolant accident (see Section 15.6)
: 2.      Steam line breaks (see Section 15.1)
: 3.      Earthquakes (see Sections 2.5 and 3.7)
: 4.      Fire (see Subsection 9.5.1)
: 5.      Explosion (hydrogen buildup inside Containment) (see Section 6.2)
: 6.      Missiles (see Section 3.5)
 
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: 7. Flood (see Sections 2.4 and 3.4)
: 8. Wind and Tornadoes (see Section 3.3)
: 9. Lightning (see Section 2.3)
: f. Minimum Performance Requirements Minimum performance requirements are as follows:
: 1. System Response Times The ESFAS response time is defined as the interval required for the ESF sequence to be initiated subsequent to the time that the appropriate variable(s) exceed this setpoint(s). The ESF sequence is initiated by the output of the ESFAS which is by the operation of the dry contacts of the slave relays (600 and 700 series relays) in the output cabinets of the Solid-State Protection System. The response times listed below include the interval of time which will elapse between the time the parameter as sensed by the sensor exceeds the safety setpoint and the time the solid-state protection system slave relay dry contacts are operated. These values (as listed below) are maximum allowable values consistent with the safety analyses and the Technical Specifications and are systematically verified during plant preoperational startup tests. For the overall ESF response time, refer to the Technical Requirements Manual. In a similar manner for the overall reactor trip system instrumentation response time, refer to the Technical Requirements Manual. These maximum delay times thus include all compensation and therefore require that any such network be aligned and operating during verification testing.
The Engineered Safeguards Actuation System is always capable of having response time tests performed using the same methods as those tests performed during the preoperational test program or following significant component changes.
Typical maximum allowable time delays in generating the actuation signal for loss-of-coolant protection are:
(a)    Pressurizer pressure                          2.0 seconds Typical maximum allowable time delays in generating the actuation signal for steamline break protection are:
(a)    Steam line pressure rate                      1.0 second (b)    Steam line pressure                          1.0 second
 
SEABROOK        INSTRUMENTATION AND CONTROLS                    Revision 21 STATION    Engineered Safety Features Actuation System          Section 7.3 UFSAR                                                            Page 10 (c)    Reactor Coolant System Tavg including 4 seconds for RTD sensor response time and 2 seconds for electronic delay          6.0 seconds (d)    High containment pressure for closing main steamline stop valves                  1.5 seconds (e)    Actuation signals for emergency feed pumps                                        2.0 seconds (f)    Refueling water storage tank levels for recirculation actuation                      1.0 second
: 2. System Accuracies Typical accuracies required in generating the required actuation signals for loss-of-coolant protection are:
(a)    Pressurizer pressure (uncompensated)        +/-12.63 percent of span Typical accuracies required in generating the required actuation signals for steam line break protection are:
(a)    Steam line pressure                          +/-12.5 percent of span (b)    Steam line pressure rate                    +/-1.8 percent of span (c)    Tavg                                        +/-5.0 percent of span (d)    Containment pressure signal                  +/-2.5 percent of span (e)    Refueling water storage tank level          +/-2.75 percent of span
 
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: 3.      Range of Sensed Variables Ranges of sensed variables to be accommodated until conclusion of protective action is assured.
Typical ranges required in generating the required actuation signals for loss-of-coolant protection are:
(a)    Pressurizer pressure                      1600 to 2500 psig (b)    Containment pressure                      0 to 60 psig (c)    Refueling water storage tank level        0 to 140 inches (suppressed range)
Typical ranges needed to generate the required actuation signals for steam line break protection are:
(a)    Tavg                                      530 to 630°F (b)    Steam line pressure                        0 to 1300 psig (c)    Containment pressure                      0 to 60 psig (d)    Refueling water storage tank level        0 to 140 inches (suppressed range) 7.3.2        Analysis 7.3.2.1      Failure Mode Effects Analysis Failure mode and effects analyses have been performed, Reference 5, on ESF systems equipment within the Westinghouse scope of supply. The Seabrook ESF systems, although not identical, have been designed to equivalent safety design criteria.
7.3.2.2      Compliance with Standards and Design Criteria Discussion of the General Design Criteria (GDC) is provided in various sections of Chapter 7 where a particular GDC is applicable. Applicable GDCs include Criteria 13, 20, 21, 22, 23, 24, 35, 37, 38, 40, 43 and 46 of the 1971 GDC. Compliance with certain IEEE Standards is presented in Subsections 7.1.2.6, 7.1.2.7, 7.1.2.10 and 7.1.2.11. Compliance with Regulatory Guide 1.22 is discussed in Subsection 7.1.2.5. The discussion given below shows the Engineered Safety Features Actuation System complies with IEEE Standard 279-1971, Reference 4.
 
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: a. Single Failure Criteria The discussion presented in Subsection 7.2.2.2c is applicable to the Engineered Safety Features Actuation System, with the following exception.
In the Engineered Safety Features Actuation System, a loss of instrument power will call for actuation of Engineered Safety Features equipment controlled by the specific bistable that lost power (containment pressure Hi-3 and RWST level low excepted). The actuated equipment that does not fail to the actuated condition must have power to comply. The power supply for the protection systems is discussed in Chapter 8. For containment pressure Hi-3 and RWST level low, the final bistables are energized to trip to avoid spurious actuation. In addition, manual containment spray requires simultaneous actuation of two manual controls. This is considered acceptable because spray actuation on High-3 containment pressure signal provides automatic initiation of the system via protection channels. Moreover, two sets (two switches per set) of containment spray manual initiation switches are provided to meet the requirements of IEEE Standard 279-1971. Also it is possible for all Engineered Safety Features equipment (valves, pumps, etc.) to be individually manually actuated from the control board. Hence, a third mode of containment spray initiation is available.
The design meets the requirements of Criteria 21 and 23 of the 1971 GDC.
: b. Equipment Qualification Equipment qualifications are discussed in Sections 3.10 and 3.11.
: c. Channel Independence The discussion presented in Subsection 7.2.2.2c is applicable. The Engineered Safety Features Actuation System slave relay outputs from the solid-state logic protection cabinets are redundant, and the actuations associated with each train are energized up to and including the final actuators by the separate AC power supplies which power the logic trains.
: d. Control and Protection System Interaction The discussions presented in Subsection 7.2.2.2c are applicable.
: e. Capability for Sensor Checks and Equipment Test and Calibration The discussions of system testability in Subsection 7.2.2.2c are applicable to the sensors, signal processing, and logic trains of the Engineered Safety Features Actuation System.
 
SEABROOK            INSTRUMENTATION AND CONTROLS                      Revision 21 STATION        Engineered Safety Features Actuation System            Section 7.3 UFSAR                                                                  Page 13 The following discussions cover those areas in which the testing provisions differ from those for the Reactor Trip System.
: 1. Testing of Engineered Safety Features Actuation Systems The Engineered Safety Features Actuation Systems are tested to provide assurance that the systems will operate as designed and will be available to function properly in the unlikely event of an accident. The testing program meets the requirements of Criteria 21, 37, 40 and 43 of the 1971 GDC and Regulatory Guide 1.22 as discussed in Subsection 3.1.4 and 7.1.2.5. The tests described in Subsection 7.2.2.2c and further discussed in Subsection 6.3.4 meet the requirements on testing of the Emergency Core Cooling System as stated in GDC 37 except for the operation of those components that will cause an actual safety injection or are not compatible with plant operation. The test, as described, demonstrates the performance of the full operational sequence that brings the system into operation, the transfer between normal and emergency power sources and the operation of associated cooling water systems. The safety injection and residual heat removal pumps are started and operated and their performance verified in a separate test discussed in Subsection 6.3.4.
When the pump tests are considered in conjunction with the emergency core cooling system test, the requirements of GDC 37 on testing of the Emergency Core Cooling System are met as closely as possible without causing an actual safety injection.
Testing as described in Subsections 6.3.4 and 7.2.2.2c provides complete periodic testability during reactor operation of all logic and components associated with the Emergency Core Cooling System. This design meets the requirements of Regulatory Guide 1.22 as discussed in the above sections. The program is as follows:
(a)    Prior to initial plant operations, Engineered Safety Features System tests will be conducted.
(b)    Subsequent to initial startup, Engineered Safety Features System tests will be conducted during each regularly scheduled refueling outage.
 
SEABROOK        INSTRUMENTATION AND CONTROLS                      Revision 21 STATION    Engineered Safety Features Actuation System            Section 7.3 UFSAR                                                              Page 14 (c)    During online operation of the reactor, all of the Engineered Safety Features Actuation System monitoring and logic circuitry will be fully tested. All active components will be tested at the operational test frequency. A lower testing frequency may be justified if adequate reliability is assured. Passive components will be tested at the operational test frequency where practicable.              All components will be tested at the channel calibration frequency. In addition, essentially all of the Engineered Safety Features actuated equipment, with the exceptions listed in Section 7.1.2.5, will be fully tested. The remaining actuated equipment whose operation is not compatible with continued online plant operation will be checked by means of continuity check of associated testable actuation devices or overlapping testing.
(d)    During normal operation, the operability of testable final actuation devices of the Engineered Safety Features Systems will be tested by manual initiation from the control room.
: 2. Performance Test Acceptability Standard for the "S" (Safety Injection Signal) and for the "P" (the Automatic Demand Signal for Containment Spray Actuation) Actuation Signals Generation The basis for Engineered Safety Features Actuation Systems acceptability will be the successful completion of overlapping tests (see Figure 7.3-1).
Channel checks of process indications verify operability of the sensors and the associated signal processing equipment. Channel operational tests performed with the channel in trip verify the operability of the channels from the signal processing equipment input through to and including the logic input relays.
Bypass Test Instrumentation (BTI) permits the testing of the Process Instrumentation System channels in bypass instead of in trip. Channel operational tests performed with the Process Instrumentation channel in bypass verify the operability of the channel from its input to the output of the signal processing equipment. Input relays for functions tested in bypass, except for the input relays associated with containment pressure Hi-3 and RWST level low, are tested at the refueling frequency.
The input relays associated with the containment pressure Hi-3 function are tested during the solid-state logic testing. The input relays associated with RWST level low are tested during the operational test.
 
SEABROOK        INSTRUMENTATION AND CONTROLS                      Revision 21 STATION    Engineered Safety Features Actuation System            Section 7.3 UFSAR                                                              Page 15 Solid-state logic testing also checks the digital signal path from the input to the logic matrices to the inputs to the slave relays. Logic testing includes continuity tests on the coils of the output slave relays. Final actuator testing operates the output slave relays and verifies operability of those devices which require Engineered Safety Features Actuation and which can be tested without causing plant upset. A continuity check is performed on the testable actuation devices of the untestable devices.
Operation of the final devices is confirmed by control board indication and visual observation that the appropriate pump breakers close and automatic valves have completed their travel.
The basis for acceptability for the Engineered Safety Features interlocks is control board indication of proper receipt of the signal upon introducing the required input at the appropriate setpoint.
: 3. Frequency of Performance of Engineered Safety Features Actuation Tests Test frequencies are specified in the Technical Specifications.
References 6 and 7 document the operational test frequency and justify channel calibration frequency testing of the SSPS input relays.
: 4. Engineered Safety Features Actuation Test Description The following sections describe the testing circuitry and procedures for the online portion of the testing program. The guidelines used in developing the circuitry and procedures are:
(a)    The test procedures must not involve the potential for damage to any plant equipment.
(b)    The test procedures must minimize the potential for accidental tripping.
(c)    The provisions for online testing must minimize complication of Engineered Safety Features Actuation circuits so that their reliability is not degraded.
(d)    The active components are tested at the operational test frequency unless the channel calibration frequency is justified. The passive components are tested at the operational test frequency where practicable.
(e)    All active and passive components required for each protective function will be tested at the channel calibration frequency.
 
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: 5. Description of Initiation Circuitry Several systems which provide the specific functions listed in Subsection 7.3.1.1a compose the Engineered Safety Features Actuation Systems, the majority of which may be initiated by different process conditions and be reset independently of each other.
The remaining functions are initiated by a common signal (safety injection) which in turn may be generated by different process conditions.
In addition, operation of all other vital auxiliary support systems, such as component cooling and service water, is initiated by the safety injection signal.
The output of each of the initiation circuits consists of a master relay which drives slave relays for contact multiplication as required. The logic, master, and slave relays are mounted in the Solid-State Protection System cabinets designated Train A, and Train B, respectively, for the redundant counterparts. The master and slave relay circuits operate various pump and fan circuit breakers or starters, motor-operated valve contactors, solenoid-operated valves, emergency generator starting, etc.
: 6. Process Monitoring Testing Process Monitoring testing is identical to that used for reactor trip circuitry and is described in Subsection 7.2.2.2c.
Exceptions to this are containment pressure Hi-3 and Refueling Water Storage Tank (RWST) level low, which are energized to actuate channels.
A test point for the containment pressure Hi-3 channels is provided to permit continuity testing of comparator trip switch BTI relay contacts, wiring between the comparator and the Solid-State Protection System (SSPS) input relay, and the input relay coil during operational testing. The RWST level low input relays are tested as part of the operational test.
: 7. Solid-State Logic Testing Except for containment pressure Hi-3 channels, logic testing is the same as that discussed in Subsection 7.2.2.2c and 7.2.3. The containment pressure Hi-3 channels have special test switches which are used to energize the input relays as part of the logic test. During logic testing of one train, the other train can initiate the required engineered safety features function.
For additional details, see Reference 2.
 
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: 8. Actuator Testing At this point, testing of the initiation circuits through operation of the master relay and its contacts to the coils of the slave relays, with the exception of the normally energized SSPS input relays for channels tested in bypass, has been accomplished. The Engineered Safety Features Actuation System (ESFAS) logic slave relays in the solid-state protection system output cabinets are subjected to coil continuity tests by the output relay tester in the SSPS cabinets. Slave relays (K601, K602, etc.) do not operate because of reduced voltage applied to their coils by the mode selector switch (TEST/OPERATE). A multiple position master relay selector switch selects the master relays and corresponding slave relays to which the coil continuity test voltage applied. The master relay selector switch is returned to "OFF" before the mode selector switch is placed back in the "OPERATE" mode. However, failure to do so will not result in defeat of the protective function. The ESFAS slave relays are activated during testing by the online test cabinet, so that overlap testing is maintained.
The engineered safety features actuation system final actuation device or actuated equipment testing is performed from the engineered safeguards test cabinets. These cabinets are located near the solid-state logic protection system equipment. There is one set of test cabinets provided for each of the two protection Trains A and B. Each set of cabinets contains individual test switches necessary to actuate the slave relays. To prevent accidental actuation, test switches are of the type that must be rotated and then depressed to operate the slave relays.
Assignments of contacts of the slave relays for actuation of various final devices or actuators have been made so that groups of devices or actuated equipment, can be operated individually during plant operation without causing plant upset or equipment damage. In the unlikely event that a safety injection signal is initiated during the test of the final device that is actuated by this test, the device will already be in its safeguards position.
During this last procedure, close communication between the main control room operator and the tester at the test cabinet is required. Prior to the energizing of a slave relay, the operator in the main control room assures that plant conditions will permit operation of the equipment that will be actuated by the relay. After the tester has energized the slave relay, the main control room operator observes that all equipment has operated as indicated by appropriate indicating lamps, monitor lamps and annunciators on the control board and records all operations. He then resets all devices and prepares for operation of the next slave-relay actuated equipment.
 
SEABROOK          INSTRUMENTATION AND CONTROLS                      Revision 21 STATION    Engineered Safety Features Actuation System            Section 7.3 UFSAR                                                              Page 18 By means of the procedure outlined above, all engineered safety features devices actuated by engineered safety features actuation systems initiation circuits, with the exceptions noted in Subsection 7.1.2.5 under a discussion of Regulatory Guide 1.22 are operated by the automatic circuitry.
: 9. Actuator Blocking and Continuity Test Circuits Those few final actuation devices that cannot be designed to be actuated during plant operation (discussed in Subsection 7.1.2.5) have been assigned to slave relays for which additional test circuitry has been provided to individually block actuation to a final device upon operation of the associated slave relay during testing. Except for the main steam isolation valve (MSIV) operation of these slave relays, including contact operations, and continuity of the electrical circuits associated with the final devices' control are checked in lieu of actual operation. The circuits provide for monitoring of the slave relay contacts, the devices' control circuit cabling, control voltage and the devices' actuation solenoids. The MSIVs are controlled by a solid-state logic that is not compatible with the standard SSPS test circuitry. The MSIVs are blocked from actuation during slave relay testing by a special SSPS test circuit that sends a signal to the MSIV logic cabinets to block the final MSIV logic gate. A light on the MSIV logic test panel on the MCB is illuminated to indicate that the MSIV closing logic is blocked. Operation of the slave relay will test all the MSIV logic up to the final gate and illuminate a light on the MSIV logic test panel to indicate a satisfactory test. After slave relay testing the SSPS block signal is removed, returning the MSIV logic cabinets to their normal condition. During refueling outages the final logic gate, MSIV logic cabinet output relay and MSIV actuating solenoid are tested by stroke exercising of the MSIVs. This overlapping test of the MSIV logic with MSIV exercising provides a complete test of the MSIVs.
Interlocking prevents blocking the output from more than one output relay in a protection train at a time. Interlocking between trains is also provided to prevent continuity testing in both trains simultaneously; therefore, the redundant device associated with the protection train not under test will be available in the event protection action is required. If an accident occurs during testing, the automatic actuation circuitry will override testing as noted above. One exception to this is that if the accident occurs while testing a slave relay whose output must be blocked, those few final actuation devices associated with this slave relay will not be actuated; however, the redundant devices in the other train would be operational and would perform the required safety function. Actuation devices to be blocked are identified in Subsections 7.1.2.5a through j.
 
SEABROOK      INSTRUMENTATION AND CONTROLS                    Revision 21 STATION  Engineered Safety Features Actuation System          Section 7.3 UFSAR                                                          Page 19 The continuity test circuits for these components that cannot be actuated on line are verified by proving lights on the safeguards test cabinet.
The charging and letdown isolation valves (described in Subsection 7.1.2.5k) are blocked by administrative controls. If an accident occurs while testing, the redundant equipment in the other train would be operational and would perform the required safety function.
The letdown heat exchanger component cooling water outlet isolation valve (described in Subsection 7.1.2.5l) is blocked by administrative controls. If an accident occurs while testing, the valve will be immediately closed by manual action, removing the nonessential heat load from the Component Cooling Water System.
The Chemical and Volume Control System TK-1 outlet isolation valves (described in Subsection 7.1.2.5n) are blocked by administrative controls.
If an accident occurs while testing, the redundant equipment in the other train would be operational and would perform the required safety function.
The Refueling Water Storage Tank TK-8 to charging pump isolation valves (described in Subsection 7.1.2.5o) are blocked by administrative controls. If an accident occurs while testing, the redundant equipment in the other train would be operational and would perform the required safety function. The typical schemes for blocking operation of selected protection function actuator circuits are shown in Figure 7.3-2 as details A and B. The schemes operate as explained below and are duplicated for each safeguards train.
 
SEABROOK      INSTRUMENTATION AND CONTROLS                      Revision 21 STATION  Engineered Safety Features Actuation System            Section 7.3 UFSAR                                                            Page 20 Detail A shows the circuit for contact closure for protection function actuation. Under normal plant operation, and equipment not under test, the test lamps "DS*" for the various circuits will be energized. Typical circuit path will be through the normally closed test relay contact "K8*"
and through test lamp connections 1 to 3. Coils "X1" and "X2" will be capable of being energized for protection function actuation upon closure of solid-state logic output relay contacts "K*." Coil "X1" is typical for a motor control center starter coil, "X2" coil is typical for a breaker closing auxiliary coil, motor starter master coil, coil of a solenoid valve, auxiliary relay, etc. When the contacts "K8*" are opened to block energizing of coil "X1" or "X2," the white lamp is de-energized and the slave relay "K*"
may be energized to perform continuity testing. To verify operability of the blocking relay in both blocking and restoring normal service, open the blocking relay contact in series with lamp terminal 1 - the test lamp should be de-energized; close the blocking relay contact in series with the lamp terminal 1 - the test lamp should now be energized, which verifies that the circuit is now in its normal, i.e., operable condition.
Detail B shows the circuit for contact opening for protection function actuation. Under normal plant operation, and equipment not under test, for 125V DC actuation devices the white test lamps "DS*" for the various circuits will be energized, and green test lamp "DS*" will be de-energized.
Typical circuit path for white lamp "DS*" will be through the normally closed solid-state logic output relay contact "K*" and through test lamp connections 3 to 1. Coil "Y2" will be capable of being de-energized for protection function actuation upon opening of solid-state logic output relay contact "K*." Coil "Y2" is typical for a solenoid valve coil, auxiliary relay, etc. When the contact "K8*" is closed to block de-energizing of coil "Y2," the green test lamp is energized and the slave relay "K*" may be energized to verify operation (opening of its contacts).
To verify operability of the blocking relay in both blocking and restoring normal service, close the blocking relay contact to the green lamp - the green test lamp should now be energized also; open this blocking relay contact - the green test lamp should now be de-energized, which verifies that the circuit is now in its normal, i.e., operable position.
 
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: 10. Time Required for Testing Analog testing can be performed at a rate of several channels per hour.
Logic testing of both Trains A and B can be performed in less than 30 minutes each. Testing of actuated components (including those which can only be partially tested) is a function of control room operator availability.
It requires several shifts to accomplish these tests. During this procedure automatic actuation circuitry overrides testing, except for those few devices associated with a single slave relay whose outputs must be blocked and tested only while blocked. Continuity testing associated with a blocked slave relay takes several minutes. During this time the redundant devices in the other trains are functional.
: 11. Summary of Online Testing Capabilities The design described above provides capability for checking completely from the process signal to the logic cabinets and from there to the individual pump and fan circuit breakers or starter, valve contactors, pilot solenoid valves, etc., including all field cabling actually used in the circuitry called upon to operate for an accident condition. All passive and active components are tested at the refueling frequency. All active components are tested at the operational test frequency except for the normally energized SSPS input relays where refueling frequency testing has been justified (Reference 7). For those few devices whose operation could adversely affect plant or equipment operation (see Subsection 7.1.2.5), the same procedure provides for checking from the process signal to the logic rack. To check the final actuation device a continuity or overlapping blocked logic/manual exercise test of the individual control circuits is performed.
The procedures require testing at various locations.
(a)    Monitoring circuit testing and verification of bistable setpoint are accomplished at the signal processing circuits. Verification of bistable relay operation is done at the main control room status lights or at the bistable output if the SSPS input relay is not tested during the operational test.
(b)    Logic testing through operation of the master relays and low voltage application to slave relays is done at the SSPS logic rack test panel.
(c)    Testing of pumps, fans and valves is done at the test panel located in the vicinity of the SSPS logic racks in combination with the control room operator.
 
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: 12. Testing During Shutdown Engineered Safety Features Actuation Systems tests will be performed periodically in accordance with the Technical Specifications with the Reactor Coolant System isolated from the Emergency Core Cooling System by closing the appropriate valves and other valve alignments as required to prevent unacceptable actions. A test safety injection signal will then be applied to initiate operation of active components (pumps and valves) of the Engineered Safety Features. This is in compliance with Criteria 37, 40 and 43 of the 1971 GDC.
: 13. Periodic Maintenance Inspections The maintenance inspections which follow will be accomplished per applicable plant programs and procedures. The frequency will depend on the operating conditions and requirements of the reactor power plant.
Typically maintenance inspections occur during preventive and corrective maintenance activities. If any degradation of equipment operation is noted, either mechanically or electrically, remedial action is taken to repair, replace, or readjust the equipment.
Typical maintenance inspections include the following:
(a)      Check cleanliness of exterior and interior surfaces (b)      Check fuses for corrosion (c)      Inspect for loose or broken control knobs and burned out indicator lamps (d)      Inspect for moisture and condition of cables and wiring (e)      Mechanically check connectors and terminal boards for looseness, poor connection, dirt or corrosion (f)      Inspect the components of an assembly for signs of overheating or component deterioration (g)      Perform complete system operating check.
The balance of the requirements listed in Reference 4 (Paragraphs 4.11 through 4.22) are discussed in Subsection 7.2.2.2a. Paragraph 4.20 receives special attention in Section 7.5.
 
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: f. Manual Resets and Blocking Features The manual reset and block control associated with safety injection actuation is provided to permit manual control of components actuated by the safety injection signal and to prevent automatic re-actuation of safety injection once it is blocked.
Manual reset and block cannot be performed until sufficient time has elapsed after safety injection actuation to permit the actuated equipment to perform the required functions. Subsequent automatic safety injection actuations will be blocked if the reactor trip interlock (P-4) is present. A status light is illuminated to indicate when automatic safety injection actuation is blocked. The automatic safety injection block circuit is returned to normal when the reactor is not tripped.
Subsequent manual safety injection actuations are not blocked if the automatic signal has been cleared by operation of the automatic block circuit or clearing of the condition that resulted in an automatic actuation.
The manual reset feature associated with ESF actuation is provided in the standard design of the Westinghouse Solid-State Protection System design for two basic purposes. First, the feature permits the operator to start an interruption procedure of automatic ESF in event of false initiation of an actuate signal.
Second, although ESF performance is automatic, the reset feature enables the operator to start a manual takeover of the system to handle unexpected events that can be better dealt with by operator appraisal of changing conditions following an accident.
It is most important to note that manual control of the ESF system does not occur, once actuation has begun, by just resetting the associated logic devices alone.
Components will seal in (latch) or complete the protective action before reset of the actuate signal is credible so that removal of the actuate signal, in itself, will neither cancel nor prevent completion of protective action or provide the operator with manual override of the automatic system by this single action. In order to take complete control of the system to interrupt its automatic performance, the operator must take deliberate action to individually operate or realign affected equipment.
The manual reset feature associated with ESF, therefore, does not perform a bypass function. It is merely the first of several manual operations required to take control from the automatic system or interrupt its completion should such an action be considered necessary.
 
SEABROOK              INSTRUMENTATION AND CONTROLS                      Revision 21 STATION          Engineered Safety Features Actuation System            Section 7.3 UFSAR                                                                    Page 24 In the event that the operator anticipates system actuation and erroneously concludes that it is undesirable or unnecessary and imposes a standing reset condition in one train (by operating and holding the corresponding reset switch at the time the initiate signal is transmitted) the other train will automatically carry the protective action to completion. In the event that the reset condition is imposed simultaneously in both trains at the time the initiate signals are generated, the automatic sequential completion of system action is interrupted and control has been taken by the operator. Manual takeover will be maintained, even though the reset switches are released, if the original initiate signal exists. Should the initiate signal then clear and return again, automatic system actuation will repeat.
Note also that any time delays imposed on the system action are to be applied after the initiating signals are latched. Delay of actuate signals for fluid systems lineup, load sequencing, valve stroke time etc., do not provide the operator time to interrupt automatic completion, with manual reset alone, as would be the case if time delay was imposed prior to sealing of the initial actuate signal.
The manual block features associated with pressurizer and steam line safety injection signals provide the operator with the means to block initiation of safety injection during plant startup. These block features meet the requirement of Paragraph 4.12 of IEEE Standard 279-1971 in that automatic removal of the block occurs when plant conditions require the protection system to be functional.
: g. Manual Initiation of Protective Actions (Regulatory Guide 1.62)
There are four individual main steam stop valve momentary control switches (one per loop) mounted on the control board. Each switch when actuated, will close one of the main steam line isolation valves. In addition, there are two system level switches. Operating either switch will actuate all four main steam line isolation valves on the system level. Manual initiation of switchover to recirculation is in compliance with Section 4.17 of IEEE Standard 279-1971, with the following comment:
 
SEABROOK              INSTRUMENTATION AND CONTROLS                    Revision 21 STATION          Engineered Safety Features Actuation System          Section 7.3 UFSAR                                                                Page 25 Manual initiation of either one of two redundant safety injection actuation main control board-mounted switches provides for actuation of the components required for reactor protection and mitigation of adverse consequences of the postulated accident, including delayed actuation of sequenced started emergency electrical loads as well as components providing switchover from the safety injection mode to the cold leg recirculation mode (see Subsection 7.6.5) following a loss of primary coolant accident. Therefore, once safety injection is initiated, those components of the Emergency Core Cooling System (see Section 6.3) that are realigned as part of the semi-automatic switchover, go to completion on low refueling storage tank water level without any manual action. Manual operation of other components or manual verification of proper position as part of emergency procedures is not precluded nor otherwise in conflict with the above described compliance to Paragraph 4.17 of IEEE Standard 279-1971 of the semi-automatic switchover circuits.
No exception to the requirements of IEEE Standard 279-1971 has been taken in the manual initiation circuit of safety injection. Although Paragraph 4.17 of IEEE Standard 279-1971 requires that a single failure within common portions of the protective system shall not defeat the protective action by manual or automatic means, the standard does not specifically preclude the sharing of initiated circuitry logic between automatic and manual functions. It is true that the manual safety injection initiation functions associated with one actuation train (e.g., Train A) shares portions of the automatic initiation circuitry logic of the same logic train; however, a single failure in shared functions does not defeat the protective action of the redundant actuation train (e.g., Train B). A single failure in shared functions does not defeat the protective action of the safety function. It is further noted that the sharing of the logic by manual and automatic initiation is consistent with the system level action requirements of the IEEE Standard 279-1971, Paragraph 4.17 and consistent with the minimization of complexity.
 
SEABROOK                INSTRUMENTATION AND CONTROLS                  Revision 21 STATION            Engineered Safety Features Actuation System        Section 7.3 UFSAR                                                                  Page 26 7.3.2.3    Further Considerations
: a. In addition to the considerations given above, a loss of instrument air or loss of component cooling water to vital equipment has been considered. Neither the loss of instrument air nor the loss of cooling water (assuming no other accident conditions) can cause safety limits as given in the Technical Specifications to be exceeded. Likewise, loss of either one of the two will not adversely affect the core or the Reactor Coolant System, nor will it prevent an orderly shutdown if this is necessary. Furthermore, all pneumatically operated valves and controls will assume a preferred operating position upon loss of instrument air. High pressure gas backup is provided for certain air-operated valves where functioning is required immediately after a loss of the compressed air system. Backup supply sizing is based on the assumption that within four hours, either the plant air system can be started manually on the diesel generator bus, or local manual control will be established. It is also noted, that for conservatism during the accident analysis (Chapter 15), credit is not taken for the nonsafety compressed air systems nor for any control system benefit.
: b. The design does not provide any circuitry which will directly trip the reactor coolant pumps on a loss of component cooling water. Indication and alarm in the control room are provided whenever component cooling water is lost. The reactor coolant pumps can run for a minimum of 10 minutes after a loss of component cooling water. This provides adequate time for the operator to correct the problem or trip the plant, if necessary.
: c. In regard to the Emergency Feedwater System, there is one motor-driven pump and one turbine-driven pump. The motor-driven pump is initiated from Train B logic, and the turbine-driven pump is initiated from Train A or B logic. The motor-driven and turbine-driven pumps are initiated automatically by the following signals:
: 1.      Safety injection (from Solid-State Protection System) or
: 2.      2/4 low-low level in any steam generator (from Solid-State Protection System) or
: 3.      Loss of offsite power
: 4.      ATWS Mitigation System (see Subsection 7.6.12)
These pumps can also be started manually.
 
SEABROOK              INSTRUMENTATION AND CONTROLS                  Revision 21 STATION          Engineered Safety Features Actuation System          Section 7.3 UFSAR                                                                Page 27 In addition, the startup feedwater pump (SUFP) which is a pump additional to the emergency feed pumps is started automatically on the trip of both main feedwater pumps if the SUFP is aligned to Bus 4. This automatic start signal is blocked by an SI or steam generator hi-hi level signal. When the SUFP is aligned to Bus E5, it will be manually started only. (See Subsections 6.8, 8.3.1.1.b.9.(a) and 10.4.12).
: d. Safety function instrumentation can be divided into two general classifications:
actuation instrumentation and control instrumentation.
Actuation instrumentation performs functions that are considered protective functions (i.e., reactor trip and Engineered Safety Features Actuation) or are necessary to provide essential auxiliary functions (cooling tower actuation, isolation of the nonsafety component cooling water piping). This instrumentation is designed to meet the requirements of IEEE 279 and, typically, has the following features:
: 1.      Dedicated indicator in the control room, except for Refueling Water Storage Tank (RWST) level.
: 2.      Alarm on actuation of a specific safety function.
: 3.      Indicator lights on the MCB, VAS alarm, channel indication at the instrument cabinets to alert the operator to a channel in the trip condition and to identify the specific channel; this indication is not applicable to functions that only have one sensing instrument.
: 4.      Indication to monitor the performance of the actuated equipment.
: 5.      Capability to perform the surveillance tests specified in the Technical Specifications (see Subsection 7.2.2.2c). These tests can be performed without interfering with normal plant operation or the use of jury-rigs or lifted leads. The design conforms with the guidance of Regulatory Guides 1.22 and 1.118.
Control instrumentation performs functions associated with the control of auxiliary supporting features in response to changes in a measured variable (start of cooling fans to maintain environmental conditions, operation of valves to meet minimum flow conditions for a pump). These control functions only affect the operation of one of the redundant safety trains; the other train is available to perform the safety function if one train fails. This instrumentation satisfies the functional requirements of IEEE 279; meets the separation requirements as discussed in Subsections 7.1.2.2 and 8.3.1.4; and typically has the following features:
: 1.      Control room or local indication to monitor the controlled variable
 
SEABROOK                    INSTRUMENTATION AND CONTROLS                    Revision 21 STATION              Engineered Safety Features Actuation System            Section 7.3 UFSAR                                                                        Page 28
: 2.      Independent alarm if the controlled variable exceeds the expected control band
: 3.      Capability to perform periodic calibration and functional tests. These tests can be performed without interfering with normal plant operation of the use of jury-rigs or lifted leads.
: e. The design of the turbine trip on reactor trip (P-4) function meets the Westinghouse interface criteria as the GE supplied turbine trip circuits are not environmentally or seismically qualified but are as reliable as reasonably achievable and they conform to the maximum extent practicable to the following sections of IEEE Std-279-1971:
: 1.      4.2, "Single Failure Criterion".
: 2.      4.3, "Quality of Components and Modules."
: 3.      4.5, "Channel Integrity," with the exception that some of the components are not designed to be functional following a seismic event. A seismic event that damages the mechanical trip solenoid circuit such that it cannot energize the solenoid would probably also result in de-energization of the electrical trip solenoid that will trip the turbine.
: 4.      4.6, "Channel Independence," with the exception that the turbine trip circuits are independent but are not separated.
: 5.      4.10, "Capability for Test and Calibration".
Different contacts on the reactor trip breaker auxiliary switches are used to provide the P-4 signals which are input to the turbine trip circuits or the SSPS.
See Section 10.2 and Table 7.3-2 for additional discussion of the turbine trip and P-4 functions.
7.3.2.4        Summary The effectiveness of the Engineered Safety Features Actuation System is evaluated in Chapters 6 and 15, based on the ability of the system to contain the effects of Condition III and IV faults, including loss of coolant, steam line break and fuel handling accidents. The engineered safety features actuation system parameters are based upon the component performance specifications which are given by the manufacturer or verified by test for each component. Appropriate factors to account for uncertainties in the data are factored into the constants characterizing system.
The Engineered Safety Features Actuation System must detect Condition III and IV faults and generate signals which actuate the Engineered Safety Features. The system must sense the accident condition and generate the signal actuating the protection function reliably and within a time determined by and consistent with the accident analyses in Chapters 6 and 15.
 
SEABROOK                    INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                Engineered Safety Features Actuation System            Section 7.3 UFSAR                                                                        Page 29 Much longer times are associated with the actuation of the mechanical and fluid system equipment associated with Engineered Safety Features. This includes the time required for switching, bringing pumps and other equipment to speed and the time required for them to take load.
Operating procedures require that the complete Engineered Safety Features Actuation System normally be operable. However, redundancy of system components is such that the system operability assumed for the safety analyses can still be met with certain instrumentation channels out of service. Channels that are out of service are to be placed in the tripped mode or the bypass mode for containment pressure Hi-3 and RWST level low.
: a.      Loss-of-Coolant Protection By analysis of loss-of-coolant accident and in system tests it has been verified that except for very small coolant system breaks which can be protected against by the charging pumps followed by an orderly shutdown, the effects of various loss-of-coolant accidents are reliably detected by the low pressurizer pressure signal; the Emergency Core Cooling System is actuated in time to prevent or limit core damage.
For large coolant system breaks, the passive accumulators inject first because of the rapid pressure drop. This protects the reactor during the unavoidable delay associated with actuating the active emergency core cooling system phase.
High containment pressure also actuates the Emergency Core Cooling System.
Therefore, emergency core cooling actuation can be brought about by sensing this other direct consequence of a primary system break; that is, the Engineered Safety Features Actuation System detects the leakage of the coolant into the Containment. The generation time of the actuation signal of about 1.5 second, after detection of the consequences of the accident, is adequate.
Containment spray will provide additional emergency cooling of Containment and also limit fission product release upon sensing elevated containment pressure (Hi-3) to mitigate the effects of a loss-of-coolant accident.
The delay time between detection of the accident condition and the generation of the actuation signal for these systems is assumed to be about 1.0 second, which is well within the capability of the protection system equipment. However, this time is short compared to that required for startup of the fluid systems.
The analyses in Chapters 6 and 15 show that the diverse methods of detecting the accident condition and the time for generation of the signals by the protection systems are adequate to provide reliable and timely protection against the effects of loss of coolant.
 
SEABROOK                  INSTRUMENTATION AND CONTROLS                    Revision 21 STATION              Engineered Safety Features Actuation System          Section 7.3 UFSAR                                                                      Page 30
: b.      Steam Line Break Protection The Emergency Core Cooling System is also actuated to protect against a steam line break. About 1.0 second elapses between sensing low steam line pressure (as well as high steam pressure rate) and generation of the actuation signal. Analysis of steam line break accidents assuming this delay for signal generation shows that the Emergency Core Cooling System is actuated for a steam line break in time to limit or prevent further core damage for steam line break cases.
Additional protection against the effects of steam line break is provided by feedwater isolation which occurs upon actuation of the Emergency Core Cooling System. Feedwater line isolation is initiated to prevent excessive cooldown of the reactor vessel and thus protect the reactor coolant system boundary.
Additional protection against a steamline break accident is provided by closure of all steam line isolation valves to prevent uncontrolled blowdown of all steam generators. The generation of the protection system signal (about 2.0 seconds) is again short compared to the time to trip the fast-acting steam line isolation valves which are designed to close in less than approximately 5 seconds.
In addition to actuation of the Engineered Safety Features, the effect of a steam line break accident also generates a signal resulting in a reactor trip on overpower or following emergency core cooling system actuation. However, the core reactivity is further reduced by the highly borated water injected by the Emergency Core Cooling System.
The analyses in Chapter 6 and 15 of the steam break accidents and an evaluation of the protection system instrumentation and channel design shows that the Engineered Safety Features Actuation Systems are effective in preventing or mitigating the effects of a steam break accident.
7.3.3          Electric Hydrogen Recombiner For a discussion on this system, refer to Subsection 6.2.5. The hydrogen recombiners are not automatically actuated.
7.3.4          References
: 1.      Reid, J.B., "Process Instrumentation for Westinghouse Nuclear Steam Supply System (4 Loop Plant Using WCID 7300 Series Process Instrumentation,"
WCAP-7913, January 1973.
: 2.      Katz, D.N., "Solid State Logic Protection System Description," WCAP-7488-L, January 1971 (Proprietary) and WCAP-7672, June 1971 (Nonproprietary).
: 3.      Swogger, J.W., "Testing of Engineered Safety Features Actuation System,"
WCAP-7705, Revision 2, January 1976. (Information only; i.e., not a generic topical WCAP.)
 
SEABROOK              INSTRUMENTATION AND CONTROLS                Revision 21 STATION        Engineered Safety Features Actuation System        Section 7.3 UFSAR                                                              Page 31
: 4. The Institute of Electrical and Electronics Engineers, Inc., "IEEE Standard:
Criteria for Protection System for Nuclear Power Generating Stations," IEEE Standard 279-1971.
: 5. Eggleston, F.T., Rawlins, D.H., and Petrow, J.R., "Failure Mode and Effects Analysis (FMEA) of the Engineered Safeguard Features Actuation System,"
WCAP-8584 (Proprietary) and WCAP-8760 (Nonproprietary), April 1976.
: 6.  "Evaluation of Surveillance Frequencies and Out of Service Times for the Reactor Protection Instrumentation System," WCAP-10271-P-A, May 1986, and Supplement 2, Revision 1, June 1990.
: 7.  "Risk/Reliability Evaluation of SSPS Input Relays and Timers in the Bypass Test Scheme," NAESCo Engineering Evaluation 95-20, August 1995.
: 8. Gruber, T.J. and Ryan, M.L., "Westinghouse SSPS Board Replacement Licensing Summary Report", WCAP-17867-P-A, Revision 1, October 2014 (Proprietary).
: 9. Surveillance Frequency Control Program as defined in Technical Specification 6.7.6.n approved by License Amendment No. 141 to the Facility License.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                        Revision 15 STATION                      Systems Required for Safe Shutdown                  Section 7.4 UFSAR                                                                              Page 1 7.4        SYSTEMS REQUIRED FOR SAFE SHUTDOWN The purpose of this section is to outline the capability for a safe shutdown as required by General Design Criteria 19, Appendix A to 10CFR Part 50. The functions necessary for initiation of safe shutdown are available from equipment that is associated with the major systems in both the primary and secondary portions of the plant systems. This equipment is normally aligned to serve a variety of operational functions, including startup and shutdown as well as protective functions. There are no identifiable safe shutdown systems, per se. However, prescribed procedures for securing and maintaining the plant in a safe condition can be instituted by appropriate alignment of selected systems. The discussion of these systems, together with the applicable codes, criteria and guidelines are found in other sections of the Updated FSAR. In addition, the shutdown functions associated with the Engineered Safety Features under postulated limiting fault situations are discussed in Chapter 6 and Section 7.3.
Discussion of the functions required and the equipment design bases for the fire scenario are not included in this section. A complete discussion describing shutdown capabilities in the event of fire is provided in the 10 CFR 50 Appendix R report "Fire Protection of Safe Shutdown Capability."
The functions discussed in this section are the minimum required for maintaining safe shutdown of the reactor under nonaccident conditions. These functions:
: a.      Provide adequate capability for controlling reactivity
: b.      Provide an adequate heat sink so that design and safety limits are not exceeded
: c.      Provide a path to achieve the cold shutdown condition.
7.4.1      Capabilities Required for Safe Shutdown The list provided below identifies the functions required for achieving and maintaining a safe shutdown. The determination of equipment and systems required for safe shutdown is based on providing these functions:
: a.      Decay Heat Removal
: b.      Reactor Coolant Inventory and Pressure Control
: c.      Negative Reactivity Addition Control
: d.      Electrical Power Supply
: e.      Plant Cooling
: f.      Process Monitoring
: g.      HVAC
: h.      Sampling.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                      Revision 15 STATION                      Systems Required for Safe Shutdown                Section 7.4 UFSAR                                                                          Page 2 7.4.2      Safe Shutdown Control Locations The main control room is the primary station for safe shutdown control of the plant. In the extremely unlikely event that the main control room becomes uninhabitable, the plant may be brought to and maintained in a hot standby condition using alternate control provisions outside the main control room and subsequently attain cold shutdown. Safe shutdown, remote from the main control room, can be accomplished by taking control of the plant from the following remote safe shutdown (RSS) locations. These are the minimum number of centralized locations from which hot standby (including emergency diesel startup and control) can be maintained on a unit basis:
: a. RSS Control Panels - MM-CP-108A and B
: b. Diesel Generator Local Control Panels - DG-CP-75A (DG-1A) and DG-CP-76A (DG-1B)
: c. MCCs, distribution panels, and switchgear in Switchgear Room A and Switchgear Room B
: d. RSS Disable Panels - MM-CP-450A and B
: e. RSS Auxiliary Control Panels - MM-CP-915A and B
: f. In addition, a limited number of manual operations will be performed locally (such as manual valve operations) to achieve and maintain cold shutdown.
7.4.3      Control Room Evacuation The main control room is designed to be available at all times. It is nevertheless postulated that main control room evacuation may be required in the event that control room habitability is compromised or insufficient controls and/or instrumentation are available due to a fire. In either case, transfer of control from the main control room to the RSS locations will be accomplished by procedure. Discussion of the actions required for evacuation of the main control room for a fire is contained in the Appendix R report.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                      Revision 15 STATION                      Systems Required for Safe Shutdown                  Section 7.4 UFSAR                                                                            Page 3 7.4.4        Initial Operator Actions Prior to evacuating the main control room, the operator will trip the reactor, the main steam isolation valves, and the reactor coolant pumps, thus establishing a hot standby condition. It should be noted however, that the capability exists outside the main control room to accomplish these functions. In the time interval required for the operators to evacuate the main control room and staff the RSS locations, decay heat removal is accomplished automatically by the steam generator safety valves. No other function is required initially to maintain a decay heat sink for the reactor. Upon arrival at the RSS locations the operators will, as dictated by the abnormal operating procedures, transfer control of safe shutdown equipment to the RSS locations by means of key-locked REMOTE-LOCAL selector switches. Access to the keys required for operation of the RSS location controls is administratively controlled and will be available when the main control room is evacuated.
Initially, control and monitoring of vital plant parameters for the functions listed in Subsection 7.4.5 will be performed by the minimum onsite operating crew. Hence, indications and controls for all pumps, fans, and critical valves, which may be operated initially by a limited number of operators, have been consolidated into a minimal number of locations.
Equipment that was operating prior to transfer to the RSS locations will continue to operate during and after the transfer.
7.4.5        Systems and Equipment to Support Safe Shutdown Functions Redundant safety-grade equipment is available to support safe shutdown functions. Control and monitoring capability is provided both in the main control room and RSS locations, unless stated otherwise. Further details for each of the safe shutdown functions are provided below.
7.4.5.1      Decay Heat Removal Decay heat transfer is made possible by natural circulation in the RCS. It will be monitored by Thot, Tcold, and RCS pressure indication.
RCS temperature is controlled by the steam generator atmospheric relief valves (ARVs). Steam generator water inventory is controlled by operating the emergency feed pump(s) and associated emergency feedwater flow control valves for each steam generator.
Long-term plant cooldown is provided by the RHR system which transfers decay heat from the RCS to the Primary Component Cooling Water (PCCW) System.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                      Revision 15 STATION                      Systems Required for Safe Shutdown                  Section 7.4 UFSAR                                                                            Page 4 7.4.5.2    Reactor Coolant Inventory and Pressure Control Operation of portions of the Chemical and Volume Control System (CVCS) to compensate for RCS leakage and cooldown volume shrink is accomplished using a centrifugal charging pump and a borated water supply. The charging flow path, while in hot standby, is either through the seal injection flow path or the high head injection flow path. Additionally, the normal charging flow to the RCS is isolated. This can be accomplished by temporarily stopping the charging pump to prevent overfill of the pressurizer. It can also be accomplished by the use of one of two functionally redundant (but non-credited for an RSS shutdown) valves (CS-V-142 or CS-V-143).
For cooldown, charging will be re-aligned to establish flow via the RCP seals to provide flow control capability to prevent charging pump cavitation. This is due to the limited flow capability from boric acid tanks (BATs), which are the required borated water sources during cooldown until expended. RCS inventory will be monitored through pressurizer level. The source of borated water for the charging flow will be from the boric acid tanks (BAT) and/or the refueling water storage tank (RWST) with the volume control tank (VCT) isolated. The pressurizer power-operated relief valves (PORVs) and pressurizer heaters, if available, are used for RCS pressure control.
Following the initiation of plant cooldown and depressurization from the RSS locations for a remote shutdown without a fire, the solid-state protection system output cabinets are de-energized to prevent ESF actuation. This removes automatic actuation signals from ESF equipment. If ESF equipment is needed during the plant cooldown, the SSPS output cabinets can be re-energized to provide the automatic actuation signals to the ESF equipment that was not transferred to the RSS control.
During the cooldown process, the safety injection accumulators are isolated or their cover gas vented. The safety injection pumps and one charging pump are disabled as part of the standard operating procedure for any shutdown to avoid low temperature over pressurization (LTOP) of the reactor vessel.
7.4.5.3    Negative Reactivity Addition Control Reactivity for hot standby at normal operating temperature is provided by insertion of the control rods.
Operation of the boration portion of the CVCS to assure sufficient shutdown margin for a plant cooldown and to maintain cold shutdown is accomplished by operating a single centrifugal charging pump taking suction from the boric acid tanks. During cooldown, the borated source must be the BAT volume until expended to at least the point that the volume injected or a boron sample demonstrates that sufficient shutdown margin for cold shutdown has been achieved, at which time the RWST may be aligned. The credited path for boration is gravity feed with the RWST isolated. The boric acid transfer pumps can be used, if available.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                        Revision 15 STATION                      Systems Required for Safe Shutdown                  Section 7.4 UFSAR                                                                              Page 5 7.4.5.4    Electrical Power Supply Emergency electric power (EDE system) controls and instruments which are required for RSS are provided at RSS locations. The EDE system, which includes the diesel generators, emergency buses, inverters, batteries, and their associated equipment, is designed to provide electric power to equipment required for safe shutdown.
The diesel generator units start automatically following a loss of offsite power or on a safety injection (SI) signal. Manual control of diesel startup is provided locally at the diesel generators as well as in the control room. Upon loss of offsite power, selected loads connected to the emergency electric power system are tripped by undervoltage relays. If diesel generator control has been transferred to the RSS locations, the operators will have to manually close the diesel generator breakers to energize the emergency buses.
Those loads that do not have their control transferred to the RSS locations will be automatically sequenced onto the diesel by the EPS. The loads that have been transferred to the RSS locations must be manually loaded on to the diesel generator. Manual loading will be coordinated with the operator at the diesel generator to prevent overloading.
7.4.5.5    Plant Cooling System Operation of at least one service water/PCCW train is required to maintain equipment cooling and for subsequent RHR operation. Intake tunnel failure that results in the complete loss of the seawater supply to the service water pumps or failure of nonseismic service water piping large enough to prevent adequate cooling of safety systems will result in automatic actuation of the cooling tower on low service water pump discharge pressure. The TA signal is also generated when the Cooling Tower is providing the cooling water to the station, and a loss of offsite power event occurs. Intake tunnel failure with subsequent cooling tower actuation is only applicable to safe shutdown from the main control room. RSS does not require cooling tower actuation. If the cooling towers are actuated there are manual actions required at the tower to detect a loss of inventory due to pipe or valve failure and to manually close the spray header bypass valve to start flow into the spray header after the basin is heated sufficiently to prevent icing. Cooling tower actuation, loss of offsite power, or safety injection, isolates the nonseismic SW piping to ensure adequate flow to the safety users.
7.4.5.6    Process Monitoring Monitoring of various vital plant parameters relied on to achieve and verify safe shutdown is available from redundant instrumentation in the main control room and the RSS locations. This instrumentation is listed in Table 7.4-1.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                        Revision 15 STATION                      Systems Required for Safe Shutdown                  Section 7.4 UFSAR                                                                            Page 6 7.4.5.7    HVAC Operation of the ventilation/cooling systems for the diesel-generator building, primary component cooling water pump area, Emergency Feedwater Pumphouse, Service Water Pumphouse, switchgear rooms and containment enclosure area is required to maintain the long-term operability of the equipment within these heat generating areas and keep temperatures below equipment limitations. The equipment function and safety evaluations for these systems are explained in the various subsections of Section 9.4.
7.4.5.8    Sampling Capability to obtain grab samples of the RCS is available to determine boron concentration for the cooldown. The boron concentration in the RHR system will also be verified prior to system initiation. Valves operated for sampling are not considered active unless they serve other safety functions such as containment isolation.
7.4.6      Design Basis and Analysis Hot standby is a stable plant condition, automatically reached following a plant trip. Seabrook is a hot standby safe shutdown design basis plant per UFSAR Subsection 5.4.7.2.i. The hot standby and hot shutdown conditions can be maintained safely for an extended period of time.
The plant can be safely kept at hot standby, hot shutdown or brought to cold shutdown, by use of the equipment listed in Table 7.4-1. The required indicators and controls are provided in the main control room and the RSS locations. Communications between the various RSS control locations are provided to coordinate actions and monitoring of the plant parameters in the performance of RSS procedures. The RSS equipment, with the exception of the pressurizer heaters and the indication at the RSS locations, is redundant and safety-grade and meets the applicable requirements of IEEE 279-1971, 323-1974 and 344-1975. It should be noted however, that for plant cooldown initiated shortly after reactor shutdown, the pressurizer heaters are not required to bring the reactor to a cold shutdown condition. Failure of a single component will not prevent safe shutdown from the main control room or the RSS locations. The quality group classification of equipment required for safety-grade shutdown is in compliance with guidelines set forth in Subsection 3.2.2. The pressurizer heaters meet the requirements of NUREG-0737, Item II.E.3.1.
Control provisions at the RSS locations consist of selector switches that isolate the main control room and transfer control to the RSS locations, and control switches to perform the manual control functions (the MSIVs only have selector switches that also close the MSIVs when local control is selected). Jumpers, lifted leads or temporary circuits are not required. Selecting local control for any component initiates an alarm in the main control room, turns off the MCB indicating lights and isolates all automatic functions, interlocks and main control room controls for that component, with the following exceptions:
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                        Revision 15 STATION                      Systems Required for Safe Shutdown                    Section 7.4 UFSAR                                                                              Page 7 Interlock/Control Equipment            Device              Function
: 1.      EPA-FN-47A            EPA-DP-373          These are inlet and exhaust damper position EPA-FN-47B            EPA-DP-374          interlocks which prevent the fans from starting or trip fans when the dampers are closed.
: 2.      PAH-FN-42A            PAH-DP-43A          These are inlet and exhaust damper position PAH-FN-42B            PAH-DP-44A          interlocks which prevent the fans from starting PAH-DP-43B          or trip the fans when the dampers are closed.
PAH-DP-44B
: 3.      SW-P-41A              SW-V-2*              *These are service water pump discharge valve SW-V-54**            position interlocks which prevent pumps from SW-P-41B              SW-V-29*            starting unless valves are closed. Coordinated SW-V-25**            fuses are provided to prevent degradation of the SW-P-41C              SW-V-22*            remote shutdown circuits due to faults in the SW-V-54**            control room indication circuit.
SW-P-41D              SW-V-31*            **These are cooling tower pump discharge SW-V-25**            valve position interlocks which prevent pumps from starting unless valves are closed.
: 4.      MS-V-395              MS-V-393            These are turbine-driven emergency feedwater MS-V-394            steam supply valve interlocks that are required for timed sequential opening to assure proper condensate drainage.
In addition to the above interlocks and control devices, all RSS equipment has electrical protective devices (i.e., overcurrent relays, undervoltage relays, motor overloads) which remain in the circuit when the "LOCAL" position of the selector switch is selected.
The indication of bypass of systems required for safe shutdown is discussed in Subsection 7.1.2.6.
Instrumentation at the RSS locations is independent of the main control room instrumentation. It is activated continuously so that its availability can be monitored. Provisions have been made for testing instrumentation channels during power operation. The RSS instrumentation will be available following all natural phenomena. The RSS controls can be tested during plant shutdowns.
 
SEABROOK                        INSTRUMENTATION AND CONTROLS                    Revision 15 STATION                        Systems Required for Safe Shutdown                Section 7.4 UFSAR                                                                            Page 8 Portions of the instrument air system may be used for the RHR air-operated valves necessary for safe shutdown. Normal operation of the RHR system uses instrument air for the control of the RHR heat exchanger outlet and bypass valves. Should the instrument air system be unavailable, the RHR heat exchanger bypass valve will fail to the closed position and the RHR heat exchanger outlet valve will fail to the full-open position. This failure mode provides full RHR flow through the RHR heat exchanger. Analysis of system startup and operation under these conditions has shown that an acceptable cooldown rate of less than 50°F/hr will result.
Therefore, plant operation at hot standby and cooldown to cold shutdown can be accomplished without the use of the instrument air system.
Safety grade backup air supplies have been provided to components which must remain operable for safe shutdown. Refer to Updated FSAR Section 9.3 for further discussion.
The station Service Water System is explained in Subsection 9.2.1. The safety evaluation is presented in Subsection 9.2.1.3. The Primary Component Cooling Water System is explained in Subsection 9.2.2 and the safety evaluation is presented in detail in Subsection 9.2.2.3.
The selection of instrumentation and controls for safe shutdown has included consideration of the event consequences that might jeopardize safe shutdown conditions.                  The event consequences that are germane are those that would tend to degrade the capabilities for boration, adequate supply for emergency feedwater, and residual heat removal.
The results of the analyses are presented in Chapter 15. Of these, the following events will produce the most severe consequences that are pertinent:
: 1.      Uncontrolled boron dilution (see Subsection 15.4.6)
: 2.      Loss of normal feedwater (see Subsection 15.2.7)
: 3.      Loss of external electrical load and/or turbine trip (see Subsections 15.2.2 and 15.2.3)
: 4.      Loss of nonemergency AC power to the station auxiliaries (Loss of Offsite Power). See Subsection 15.2.6.
It is shown by these analyses, that safety is not adversely affected by these events, assuming the equipment indicated in Subsection 7.4.7 is available in the main control room to control and/or monitor shutdown. These available systems will allow maintenance of hot standby and cooldown to cold shutdown even during the events listed above which would tend toward a return to criticality or a loss of heat sink.
In the unlikely event that the main control room is uninhabitable, alternate control provisions are provided at the RSS locations. Safety is not adversely affected by Event 1, uncontrolled boron dilution (see Subsection 15.4.6). Events 2, 3 and 4 do not have an adverse effect since the remote safe shutdown equipment can be powered by emergency power, and a plant trip initiated by main control room evacuation will put the plant in a safe condition.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                      Revision 15 STATION                      Systems Required for Safe Shutdown                Section 7.4 UFSAR                                                                            Page 9 The results of the analysis which determined the applicability of the NRC General Design Criteria, IEEE Standard 279-1971, applicable NRC Regulatory Guides, and other industry standards, to the equipment required for safe shutdown, are presented in Table 7.1-1.
Technical Specification (T/S) 3/4.3.3.5 requires surveillance testing of selected equipment used for safe shutdown from outside the control room at Remote Safe Shutdown (RSS) locations. The required equipment is listed in Table 3.3-9. The selection criteria for the Transfer Switch/Control Circuit portion of the table is the primary equipment which has remote/local selector switches and is required to perform the reactor coolant system inventory and pressure control, reactivity control and decay heat removal functions to achieve and maintain hot standby.
Redundant, safety grade equipment is provided for GDC 19 shutdown. Seabrook is a hot standby safe shutdown design basis plant (see UFSAR Section 5.4.7.2.i). Support equipment, and equipment required only to achieve and maintain cold shutdown, are not required to be included in the T/S table. Process monitoring instruments also have surveillance requirements.
7.4.7      Equipment Required for Safe Shutdown The equipment required to accomplish safe shutdown functions is listed in Table 7.4-1.
 
SEABROOK                    INSTRUMENTATION AND CONTROLS                      Revision 9 STATION                  Safety-Related Display Instrumentation              Section 7.5 UFSAR                                                                          Page 1 7.5            SAFETY-RELATED DISPLAY INSTRUMENTATION 7.5.1          Introduction Display instrumentation is provided in the main control room to enable the operator to monitor plant status under all operating conditions and to take any necessary manual actions. This display instrumentation consists of analog and digital indicators, recorders, status lamps, indicating lights, Video Alarm System (VAS) alarms, video displays and annunciators. Display instrumentation is also provided in the Technical Support Center (TSC) and the Emergency Operations Facility (EOF) to support the functions to be performed by the personnel in the TSC/EOF.
7.5.2          Definitions
: a.      Design Basis Accident Events Those events postulated in the plant safety analyses, any one of which may occur during the lifetime of the plant, and those events not expected to occur, but postulated in the plant safety analyses because their consequences would include the potential for release of significant amounts of radioactive material to the environs. These events are listed in Updated FSAR Chapter 15 as Conditions III and IV occurrences. Excluded are those events (defined as "normal" and "anticipated operational occurrences" in 10 CFR 50) expected to occur more frequently than once during the lifetime of the plant.
: b.      Task Analysis Process of identifying and examining tasks that must be performed by the control room operating crew when interacting with the plant systems.
7.5.3          Discussion An Accident Monitoring Instrumentation (AMI) list, Table 7.5-1, has been developed to define the instrumentation required by the operator for design basis accident events. The AMI enables the operator to monitor safety functions, take any manual actions required to support the accomplishment of safety functions and determine the effect of manual actions during and following a design basis accident event. The AMI also enables the operator to maintain the plant in a hot shutdown condition, or to proceed to cold shutdown. Details are provided in Subsection 7.5.4.
Table 7.5-2 lists additional information available to the operator for monitoring conditions in the reactor, the Reactor Coolant System, the containment and key process systems throughout all normal operating conditions of the plant, including anticipated operational occurrences.
 
SEABROOK                    INSTRUMENTATION AND CONTROLS                    Revision 9 STATION                  Safety-Related Display Instrumentation              Section 7.5 UFSAR                                                                        Page 2 Status lamp arrays are used to indicate both a demand for a protective function/ESF actuation and the appropriate valve position and equipment status for ESF actuations. These arrays are functionally arranged on the control board to enable the operator to quickly and accurately monitor system status. Status lamp arrays are provided to monitor bistable trips for the following safety functions:
* Reactor Trip
* Safety Injection
* Containment Isolation
* Steam Line Isolation
* Feedwater Line Isolation To monitor valve position, actuated equipment status and emergency power availability, status lamp arrays are provided for the following:
* Cold Leg Injection
* Cold Leg Recirculation
* Hot Leg Recirculation
* Containment Isolation, Phase A
* Containment Isolation, Phase B
* Main Steam and Feedwater Isolation
* Cooling Tower Actuation
* Diesel Generator Status
* Emergency Power Sequencer A computer-based Video Alarm System (VAS) is provided to alert the operator when various process limits are exceeded. The incoming alarms are prioritized to allow the operators to focus on high priority alarms during major plant upsets. Three levels of priority have been established.
Incoming alarms are also broken down into primary and secondary sides; primary side alarms are displayed on the alarm displays in main control board Sections A and D, while secondary side alarms are displayed on the alarm displays in Sections F and I.
 
SEABROOK                    INSTRUMENTATION AND CONTROLS                    Revision 9 STATION                  Safety-Related Display Instrumentation            Section 7.5 UFSAR                                                                        Page 3 An alarm suppression scheme is normally active on the VAS computer software to minimize the number of alarms that the operators must respond to during routine and transient plant operation.
Two types of alarm suppression are provided: one based on mode of plant operation and the other for selected plant transient events. Only alarms that are expected and do not represent an abnormal plant condition for a mode or event are suppressed. If required, the capability for operators to deactivate mode and/or event alarm suppression is available through the main control board VAS workstations.
An alarm horn silence switch has been provided at the Unit Supervisor's desk in the Control Room. This switch allows the Unit Supervisor to disable the main control board alarm audibles during periods of high alarm activity. When activated, this switch will reduce Control Room noise levels and the repetitive operator actions required to silence alarms. An amber lamp mounted next to the switch indicates when the alarm horn audibles have been silenced.
Various dynamic displays are provided to serve the needs of the operating crew. These displays supplement those described above. Video displays are provided in the Technical Support Center (TSC) and Emergency Operations Facility (EOF) to support the functions to be performed by the personnel in the TSC/EOF.
The computer system consists of two host computers, each of which is fed from a separate uninterruptible power supply. An automatic failover scheme is provided. The remainder of the system is configured so that system peripherals can be manually aligned to the available UPS.
Annunciators back up the VAS should a complete Computer System failure occur. The annunciators also have a limited "First Out" capability to assist the operator in determining the cause of a reactor trip or safety injection. A limited set of essential parameters is monitored for the following:
* Reactor Trip Signals
* ESF Actuation Signals
* Certain Technical Specification Deviations
* Important Systems The annunciators are powered from instrumentation power sources that are independent of the power sources for the VAS.
Bypassed/inoperable condition of safety systems is displayed on the VAS and on status lamp arrays on the MCB - one per train. Refer to Subsection 7.1.2.6 for a complete discussion of compliance with Regulatory Guide 1.47.
 
SEABROOK                  INSTRUMENTATION AND CONTROLS                      Revision 9 STATION                  Safety-Related Display Instrumentation              Section 7.5 UFSAR                                                                        Page 4 7.5.4        Accident Monitoring Instrumentation 7.5.4.1      Compliance with Regulatory Guide 1.97 Regulatory Guide 1.97, Revision 3 endorses, subject to certain clarifications, ANSI/ANS 4.5-1980, "Criteria for Accident Monitoring Functions in Light-Water-Cooled Nuclear Reactors." The guidance provided in Regulatory Guide 1.97 and ANS 4.5, with certain exceptions, and NUREG-0737 has been used in selecting the Seabrook Accident Monitoring Instrumentation (AMI).
The exceptions to the guidance provided in Regulatory Guide 1.97 and ANSI/ANS 4.5 are:
: a. Not all the variables recommended by Regulatory Guide 1.97, Table 3 have been included in the AMI List. Specific deviations and the associated justifications are provided in Appendix 7A.
: b. Not all the AMI characteristics recommended by Regulatory Guide 1.97, Table 3 have been met. Specific deviations and the associated justifications are provided in Appendix 7A.
: c. The determination of performance requirements for AMI did not follow the guidance of Regulatory Guide 1.97, Section C.2.4 in that:
: 1.      Required accuracy of measurement was not determined in procuring the instrumentation. Instead, the accuracy of the as-procured instrumentation was determined and then reviewed for acceptability. Further details are provided in Subsection 7.5.4.4e.5.
: 2.      Except for meteorological monitoring instrumentation, response characteristics (time) have not been determined for instrumentation channels that provide monitoring functions only. The response time for these channels is similar to the response time determined for ESF actuation channels since similar hardware is used.                Therefore, determination of the response time for each channel is not necessary. See Subsection 2.3.3.3a for a description of the meteorological monitoring system.
7.5.4.2      Description of Variable Types The accident monitoring variables are classified into five types (A, B, C, D or E) according to the monitoring function they perform. A definition of each type is provided in the following subsections.
 
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: a. Type A Variables Type A variables for Seabrook Station are those variables to be monitored that provide the primary information for the control room operators to take specific preplanned manual actions for which no automatic control is provided. These actions are required for safety systems to accomplish their safety function for design basis accident events. Actions taken as a result of equipment failures, e.g.,
the "Response Not Obtained" column in the Emergency Response Procedures (ERPs), are excluded.
: b. Type B Variables Type B variables provide the most direct indication to monitor the accomplishment of the critical safety functions (CSFs). CSFs are those safety functions that are essential to prevent a direct and immediate threat to the health and safety of the public. The accomplishment of these functions ensures the integrity of the physical barriers against radiation releases.
The six CSFs for Seabrook are:
: 1.      Subcriticality
: 2.      Containment Integrity (including radioactive effluent control)
: 3.      Heat Sink
: 4.      Core Cooling
: 5.      RCS Integrity
: 6.      RCS Inventory
: c. Type C Variables Type C variables provide the most direct indication of the potential for or the actual breach of the barriers to fission product releases. These barriers are: fuel cladding, primary coolant pressure boundary, and Containment.
: d. Type D Variables Type D variables are those variables that provide information to indicate the operation of individual safety systems and nonsafety systems used in the mitigation of design basis accidents.
: e. Type E Variables Type E variables are those variables to be monitored as required for use in determining the magnitude of the release of radioactive materials and continually assessing such releases.
 
SEABROOK                    INSTRUMENTATION AND CONTROLS                    Revision 9 STATION                    Safety-Related Display Instrumentation            Section 7.5 UFSAR                                                                        Page 6 7.5.4.3        Development of Accident Monitoring Instrument List As part of the Detailed Control Room Design Review (DCRDR), a task analysis was performed on the ERPs to identify the needed instrumentation and controls to support the execution of these procedures. For each instrument needed, a determination of the variable type was made based on its use in the ERPs and the definitions for each variable type. The task analysis included the ERP contingency guidelines (ECAs); instrumentation used only to support the execution of the ECAs is not considered AMI.
For each variable, a determination is made whether it is a key variable or backup variable in accordance with the following criteria.
Key variables are those variables that provide the primary information required to permit the control room operating crew to:
: a.      Perform the diagnosis specified in the ERPs for design basis accidents
: b.      Take any manual action required to mitigate the consequences of an accident
: c.      Monitor the operation of safety systems.
Primary information is information that is essential for the direct accomplishment of the specified safety functions.
Backup variables are those variables that also provide information in addition to the key variables to assist the control room operating staff in:
: a.      Performing the diagnosis specified in the emergency operating procedures for design basis accidents
: b.      Taking any manual actions required to mitigate the consequences of an accident
: c.      Monitoring the status of individual components and ESF demand signals
: d.      Resolving instrument ambiguity.
Variables are then assigned a design category using the following matrix:
Design Category Variable                        Key                        Backup Type                      Variables                    Variables A                              1                            3 B                              1                            3 C                              1                            3
 
SEABROOK                  INSTRUMENTATION AND CONTROLS                    Revision 9 STATION                  Safety-Related Display Instrumentation            Section 7.5 UFSAR                                                                      Page 7 Design Category Variable                        Key                        Backup Type                        Variables                    Variables D                    2 for safety systems                  3 3 for nonsafety systems                  3 E                              3                            3 The AMI list contains the instrumentation classified as Design Category 1 and 2, the instrumentation identified to monitor the performance of safety systems (Type D, Design Category 2) and Design Category 3 instrumentation included in Regulatory Guide 1.97, Table 3, Revision 3.
7.5.4.4      Design and Qualification Criteria
: a. Discussion The AMI are assigned design categories as discussed in Subsection 7.5.4.3. The design and qualifications criteria for each design category are provided in the following subsections.
: b. Design Category 1 - Design and Qualification Criteria
: 1.      Equipment Qualification Design Category 1 instrumentation is environmentally qualified in accordance with IEEE 323-1974 and associated daughter standards. This instrumentation is seismically qualified in accordance with IEEE 344-1975. Further details on the methods used and compliance with associated regulations and Regulatory Guides are provided in Sections 3.10 and 3.11 of the Updated FSAR.
: 2.      Redundancy No single failure within the AMI, its auxiliary supporting features, or its power sources concurrent with the failures that are a condition or result of a specific accident, will prevent the operators from being presented the information necessary to determine the safety status of the plant and to bring the plant to and maintain it in a safe condition following the accident. The electrical independence and physical separation of redundant channels is discussed in Sections 8.3 and 7.1.
 
SEABROOK          INSTRUMENTATION AND CONTROLS                    Revision 9 STATION        Safety-Related Display Instrumentation            Section 7.5 UFSAR                                                              Page 8 Where failure of one accident monitoring channel results in information ambiguity (i.e., the redundant displays disagree) that could lead operators to defeat or fail to accomplish a required safety function, backup information is provided to allow the operators to deduce the actual conditions in the plant. This is accomplished by providing additional independent channels of information of the same variable (an identical channel) or by providing an independent channel to monitor a different variable that bears a known relationship to the multiple channels (a diverse channel). Information on redundant/diverse channel availability is included in the operator training program.
For systems having redundant components, single channel monitoring of the redundant parts of the system is provided. Verifying the proper functioning of one the redundant parts of the system is sufficient to monitor the accomplishment of the safety function.
: 3. Power Source Design Category 1 instrumentation is powered from safety-related power sources.      Where momentary power interruption is not tolerable, uninterruptible power sources are used.
: 4. Availability The Design Category 1 instrumentation channels will be available prior to an accident except for testing and maintenance as provided in Paragraph 4.11 of IEEE Standard 279-1971 or as specified in the Technical Specifications.
: 5. Quality Assurance Quality Assurance for Design Category 1 instrumentation is provided in accordance with the QA Program described in Chapter 17 of the Updated FSAR. Conformance to appropriate regulatory guides is discussed both in Chapter 17 and Section 1.8 of the Updated FSAR.
: 6. Display and Recording Indication: For design Category 1 variables, continuous, redundant indication is provided. This indication meets the applicable requirements for design Category I instrumentation.
Recording: Recording of instrumentation readout information is provided for at least one of the redundant channels.
 
SEABROOK              INSTRUMENTATION AND CONTROLS                      Revision 9 STATION            Safety-Related Display Instrumentation              Section 7.5 UFSAR                                                                  Page 9 Trend Indication: Where direct and immediate trend or transient information is essential for operator information or action, this information is available from multiple displays such as:
* Dedicated recorders, or
* Dedicated ratemeters, or
* Video display (via the plant computer) available on demand, or
* Plasma displays - available on demand by use of dedicated function push buttons.
For trend display channels, at least one of the display devices meets the applicable requirements for design Category 1 instrumentation.
: 7. Identification Type A, B, C, & D instrumentation displays provided for operator use during accident conditions are identified by an orange nameplate containing black lettering.
: 8. Interfaces The transmission of signals to the accident monitoring equipment from protection equipment is through isolation devices, which are classified as part of the protection system.
No credible failure at the output of an isolation device will prevent the associated protection channel from meeting the minimum performance requirements considered in the design bases. Examples of credible failures include short circuits, open circuits, grounds, and the application of the maximum credible AC or DC potential (140V DC or 129V AC).
Refer to Updated FSAR Subsection 7.2.2.2c.7 for further discussion.
: c. Design Category 2 - Design and Qualification Criteria
: 1. Equipment Qualification Design Category 2 instrumentation is environmentally qualified in accordance with IEEE 323-1974 and associated daughter standards.
Further details on the methods used and compliance with associated regulations and Regulatory Guides are provided in Section 3.10.
: 2. Power Source Design Category 2 instrumentation is powered from highly reliable power sources, very often Class 1E. Where momentary power interruption is not tolerable, uninterruptible power sources are used.
 
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: 3. Quality Assurance Quality Assurance for Design Category 2 instrumentation is provided by United Engineers and Constructors for the design, procurement and installation phases. Their QA Program contains the measures necessary to insure that the instrumentation has been properly specified, procured and installed. This program contains the applicable elements of 10 CFR 50, Appendix B.
Quality Assurance for the testing phase is provided by the standard testing procedures of the NHY Startup and Test Department. Auditable records are available for each Design Category 2 instrument.
Quality Assurance during the operational phase is provided under the FPLE Seabrook Operational Quality Assurance Program (OQAP). Further details are provided in Section 17.2.
: 4. Display and Recording Indication For Design Category 2 instruments, either display on demand or continuous indication is provided.
Recording Effluent radioactivity and area radiation variables are recorded.
Trend Indication Where direct and immediate trend or transient information is essential for operator information or action, trend indication is provided. This indication consists of either dedicated recorders or video displays.
: 5. Identification Types A, B and C instrumentation displays provided for operator use during accident conditions are identified by an orange nameplate containing black lettering.
: 6. Channel Availability Design Category 2 instrumentation channels will be available prior to an accident as provided in the plant administrative procedures.
: 7. Interfaces Same as Design Category 1.
 
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: d. Design Category 3 - Design and Qualification Criteria
: 1. Quality Assurance This instrumentation is of high-quality commercial grade and is selected to withstand the expected plant service environment.
: 2. Display and Recording Indication The information display can be either continuous or available on demand.
Recording Effluent radioactivity variables and meteorological variables are recorded.
Trend Indication Where direct and immediate trend or transient information is essential for operation information or action, trend information is provided. Trend information may be from a dedicated recorder or available on demand from the plant computer system.
: e. Design and Qualification Criteria Applicable to Design Categories 1, 2, and 3
: 1. Range The range of the read-outs extends over the maximum expected range of the variable being measured. Where two or more instruments are needed to cover a particular range, overlapping of the instrument spans is provided.
: 2. Servicing, Testing, and Calibration Means are provided for checking, with a high degree of confidence, the operational availability of each sensor during reactor operation.
This may be accomplished in various ways, for example:
* By perturbing the monitoring variable; or
* By introducing and varying, as appropriate, a substitute input to the sensor of the same nature as the measured variable; or
* By cross-checking between channels that bear a known relationship to each other and that have read-outs available.
The AMI is designed to permit any channel to be maintained when required during power operation.
 
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: 3. Human Factors The AMI is designed to facilitate the recognition, location, replacement, repair, or adjustment of malfunctioning components or modules. The AMI is designed to minimize the development of conditions that cause meters, annunciators, recorders, etc., to give anomalous indications potentially confusing to the operator.
The displays are functionally arranged on the control board to provide the operator with ready understanding and interpretation of plant conditions.
Comparisons between duplicate information channels or between functionally related channels will enable the operator to readily identify a malfunction in a particular channel.
In accordance with the guidance provided in NUREG-0737, an integrated effort for both the Detailed Control Room Design Review (DCRDR) and the AMI review was undertaken. The results of this effort identified the instrumentation needed by the operating crew during the course of an accident or in the recovery phase. The DCRDR reviewed the adequacy of these instrumentation displays for use by the operating crews against human factors criteria. The AMI review determined the adequacy of instrumentation channels against the design criteria stated in this subsection. Changes made after the completion of the DCRDR will be subjected to human factors review.
: 4. Direct Measurement To the extent practicable, monitoring instrumentation inputs are from sensors that directly measure the desired variables. Indirect measurements are generally used to provide backup information only.
: 5. Instrument Accuracy The plant-specific background documents prepared for the ERPs verify and document that the installed AMI has sufficient accuracy to support the ERPs.
The accuracy of the AMI is addressed as part of the Operator Training Program.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                        Revision 12 STATION                      All Other Systems Required for Safety                Section 7.6 UFSAR                                                                              Page 1 7.6            ALL OTHER SYSTEMS REQUIRED FOR SAFETY 7.6.1          Instrumentation and Control System For a description of the instrumentation and control power supply system, see Section 8.3. For a description of the remote safe shutdown control features, see Section 7.4.
7.6.2          Residual Heat Removal Isolation Valves 7.6.2.1        Description The Residual Heat Removal System (RHRS) isolation valves are normally closed, and are only opened for residual heat removal after system pressure is reduced to approximately 362 psig and system temperature has been reduced to approximately 350°F (Subsection 5.4.7).
The residual heat removal valves are provided with red (open) and green (closed) position indication and power available lights located above the control switch for each valve at the MCB and the RSS panels.
There are two motor-operated valves in series in each of the two RHR pump suction lines from the RCS hot legs. The two valves nearest the RCS (RC-V22 and V87) are designated as the inner isolation valves, while the two valves nearest the RHR pumps (RC-V23 and V88) are designated as the outer isolation valves. Reactor Coolant System wide range pressure signals for the valve interlocks are derived from transmitters which are located outside of Containment. The transmitter associated with the interlocks for the inner isolation valves is diverse from the transmitter used for outer isolation valves' interlocks. Otherwise, the interlock features provided for the outer isolation valves, shown on Figure 7.6-1 are identical to those provided for the inner isolation valves, shown on Figure 7.6-2, Figure 5.4-7, sh.1 and sh.2.
Each valve is interlocked so that it cannot be opened unless the RCS pressure is below that which could result in the RHR system design pressure being exceeded. (This includes the effects of instrument uncertainty and bistable deadband.) Refer to the Station Technical Specifications.
This interlock prevents the valve from being opened when the RCS pressure would be above the RHR system design pressure.
 
SEABROOK                        INSTRUMENTATION AND CONTROLS                      Revision 12 STATION                      All Other Systems Required for Safety                Section 7.6 UFSAR                                                                              Page 2 7.6.2.2        Analysis Based on the scope definitions presented in References 1 and 2, these criteria do not apply to the residual heat removal isolation valve interlocks; however, in order to meet NRC requirements and because of the possible severity of the consequences of loss of function, the requirements of IEEE Standard 279-1971 will be applied with the following comments:
: a.      For the purpose of applying IEEE Standard 279-1971 to this circuit, the following definitions will be used:
: 1.      Protection System The two valves in series in each line and all components of their interlocking circuits.
: 2.      Protective Action The maintenance of Residual Heat Removal System isolation from the Reactor Coolant System when Reactor Coolant System pressures are above the preset value.
: b.      IEEE Standard 279-1971, paragraph 4.10: The above mentioned pressure interlock signals and logic will be tested on line to the maximum extent possible without adversely affecting safety. This test will include the analog signal through to the train signal which activates the slave relay (which provides the final output signal to the valve control circuit). This is done in the best interests of safety since an actual actuation to permit opening the valve could potentially leave only one remaining valve to isolate the low pressure Residual Heat Removal System from the Reactor Coolant System.
: c.      IEEE Standard 279-1971, paragraph 4.15: This requirement does not apply, as the setpoints are independent of mode of operation and are not changed.
Environmental qualification of the valves and wiring is discussed in Section 3.11.
7.6.3      Refueling Interlocks Electrical interlocks (i.e., limit switches), as discussed in Subsection 9.1.4.3, are provided for minimizing the possibility of damage to the fuel during fuel handling operations.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                        Revision 12 STATION                      All Other Systems Required for Safety                Section 7.6 UFSAR                                                                              Page 3 7.6.4      Accumulator Motor-Operated Valves The design of the signals to the accumulator isolation valves meets the following criteria established in previous NRC positions on this matter:
: a.      Automatic opening of the accumulator valves when (a) the primary coolant system pressure exceeds a preselected value (specified in the Technical Specifications) or (b) a safety injection signal has been initiated. Both signals shall be provided to the valves.
: b.      Use of a safety injection ("S") signal to automatically remove (override) any bypass features that are provided to allow an isolation valve to be closed for short periods of time when the Reactor Coolant System is at pressure (in accordance with the provisions of the Technical Specifications). As a result of the confirmatory "S" signal, isolation of an accumulator with the reactor at pressure is acceptable (see Drawing NHY-503907).
: c.      During plant operation, these valves are normally open, and the motor control center supplying power to the operators is de-energized.
The functional block diagram for these valves is shown on Figure 7.6-3. The valves and control logic are further discussed in Subsections 6.3.2.2 and 6.3.5.
The Safety Injection System accumulator discharge isolation valves are motor-operated, normally open valves which are controlled from the main control board.
These valves are interlocked so that:
: a.      They open automatically on receipt of an "S" signal with the main control board switch in either the "AUTO" or "CLOSE" position.
: b.      They open automatically whenever the Reactor Coolant System pressure is above the safety injection unblock pressure (P-11) specified in the Technical Specifications only when the main control board switch is in the "AUTO" position.
: c.      They cannot be closed as long as an "S" signal is present.
The four main control board switches for these valves provide a "spring return to AUTO" from the open position and a "maintain CLOSE" position.
The "maintain CLOSE" position is required to provide an administratively controlled manual block of the automatic opening of the valve at pressure above the safety injection unblock pressure (P-11). The manual block or "maintain CLOSE" position is required when performing a periodic check-valve leakage test when the reactor is at pressure. The maximum permissible time that an accumulator valve can be closed when the reactor is at pressure is specified in the Technical Specifications.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                      Revision 12 STATION                    All Other Systems Required for Safety                Section 7.6 UFSAR                                                                            Page 4 Administrative control is required to ensure that any accumulator valve, which has been closed at pressures above the safety injection unblock pressure, is returned to the "OPEN" position.
During plant shutdown, the accumulator valves are closed. To prevent an inadvertent opening of these valves during the shutdown period, whenever accumulator pressure is greater than 100 psig, power to the accumulator valve motor circuit is turned "OFF" by a separate control switch regulating power to the motor control center, which is administratively controlled.
Administrative control is again required to ensure that these motor control centers are energized during the pre-startup procedures.
The four accumulator motor-operated isolation valves are provided with red (open) and green (closed) position-indicating lights located above the control switch on the MCB and at the remote shutdown panels. A monitor light that goes "on" for each isolation valve when the valve is full open, is provided in an array of monitor lights also located at the MCB. An alarm is actuated by the motor operator limit switch whenever the isolation valve is not fully opened, coincident with pressurizer pressure greater than a set value. This alarm remains a high priority on the VAS until the isolation valve is reopened. "Control switch in close position" alarm is also available. Control power availability to each of the valves is indicated by a monitoring light at the MCB. Thus, the design of this system meets the requirements of Branch Technical Position ICSB-4 (NUREG-0800, Appendix 7-A).
7.6.5          Switchover from Injection to Recirculation The details of achieving cold leg recirculation following safety injection are given in Subsection 6.3.2.8 and on Table 6.3-7. Figure 7.6-4 and Figure 7.6-5 show the logic which is used to automatically open the containment sump isolation valves.
Four narrow-range level sensors are provided for measurement of RWST level.
7.6.6          Interlocks for RCS Pressure Control during Low Temperature Operation 7.6.6.1        Design and Function The basic function of the RCS pressure control during low temperature operation is discussed in Subsection 5.2.2. As noted in Subsection 5.2.2, this pressure control includes automatic actuation logic for two pressurizer power-operated relief valves (PORVs). The function of this actuation logic is to continuously monitor RCS temperature and pressure conditions, with the actuation logic only unblocked when plant operation is at a temperature below the Reference Nil Ductility Temperature (RNDT). The monitored RCS pressure signals are derived from wide-range pressure transmitters located outside of Containment. The monitored system temperature signals are processed to generate the reference pressure limit program, which is compared to the actual monitored RCS pressure. This comparison will provide an actuation signal to an actuation device which will cause the PORV to automatically open, if necessary, to prevent pressure conditions from exceeding allowable limits. See Figure 7.6-6 for the block diagram showing the interlocks for RCS pressure control during low temperature operation.
 
SEABROOK                        INSTRUMENTATION AND CONTROLS                    Revision 12 STATION                      All Other Systems Required for Safety            Section 7.6 UFSAR                                                                          Page 5 As shown on this figure, the generating station variables required for this interlock are channelized as follows:
: a. Protection Set I
: 1.      Wide range RCS temperature from hot legs
: 2.      Wide range RCS pressure.
: b. Protection Set II Wide range RCS temperature from cold legs
: c. Protection Set IV Wide range RCS pressure The wide-range temperature signals, as inputs to Protection Sets I and II, continuously monitor RCS temperature conditions whenever plant operation is at a temperature below the RNDT. In Protection Set I, the existing RCS hot leg wide-range temperature channels will continuously supply analog input through an isolator to two auctioneering devices, which are located in the Process Control Group No. 1.
The lowest reading as selected by one auctioneer is input to a function generator which calculates the reference pressure limit program, considering the plant's allowable pressure and temperature limits. Also available from Protection Set I, is the wide-range RCS pressure signal which is sent through an isolation device to Control Group 1. The reference pressure from the function generator is compared to the actual RCS pressure monitored by the wide-range pressure channel. The error signal derived from the difference between the reference pressure and the actual measured pressure will first annunciate a main control board alarm whenever the actual measured pressure approaches, within a predetermined amount, the reference pressure. On a further increase in measured pressure, the error signal will generate an actuation signal. The actuation signal available from the auxiliary relay rack will control PORV "A" whenever a temperature-dependent permissive signal from the lowest auctioneering temperature in Process Control Group 1 is present. The two auctioneering devices mentioned above select the lowest temperature. One low temperature is for use as a permissive, the other for use in the reference pressure limit program. The temperature-dependent permissive to the PORVs actuation device effectively disarms (blocks) the actuation signal at temperatures greater than the range of concern. This will prevent unnecessary system actuation when at normal RCS operating conditions as a result of a failure in the process sensors.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                          Revision 12 STATION                      All Other Systems Required for Safety                  Section 7.6 UFSAR                                                                                Page 6 The monitored generating station variables that generate the actuation signal for the "B" PORV are processed in a similar manner. In the case of PORV "B", the reference temperature is generated in Process Control Group 4 from the lowest auctioneered wide-range cold leg temperature, which is a separate auctioneering circuit from the circuit used for the PORV "A" permissive. The auctioneering device derives its input from the RCS wide-range temperature in Protection Set II. The actual measured pressure signal is available from Protection Set IV.
Therefore, the generating station variables used for PORV "B" are derived from a protection set that is independent of the sets from which generating station variables used for PORV "A" are derived. The error signal derivation itself used for the actuation signals is available from the control group.
Upon receipt of the actuation signal, the actuation device will automatically cause the PORV to open. Upon sufficient RCS inventory letdown, the operating RCS pressure will decrease, clearing the actuation signal. Removal of this signal causes the PORV to close.
7.6.6.2        Analysis of Interlock Many criteria presented in IEEE 279-1971 and IEEE 388-1975 standards do not apply to the interlocks for RCS pressure control during low temperature operation, because the interlocks do not perform a protective function but rather provide automatic pressure control at low temperatures as a backup to the operator. However, although IEEE 279 criteria do not apply, some advantages of the dependability and benefits of an IEEE 279 design have accrued by including selected elements as noted above in the protection sets and by organizing the control of the two PORVs into dual channels, wherever practical, either of which can accomplish the RCS pressure control function.
The design of the low temperature interlocks for RCS pressure control is such that pertinent features include:
: a. No credible failure at the output of the protection set racks, after the output leaves the racks to interface with the interlocks, will prevent the associated protection system channel from performing its protective function, because such outputs that leave the racks go through an isolation device as shown in Figure 7.6-6.
No single random failure in either channel of the control system will defeat required actuation of both PORVs. It is noted that the lowest of four wide-range temperatures in each channel is derived twice by the two lowest auctioneering temperature circuits. One of these circuits is used to generate the reference pressure limit program for one PORV; the other of these auctioneering circuits is used as a permissive for the redundant PORV. A failure high of either auctioneering circuit in a given channel will not defeat operation of both PORVs.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                      Revision 12 STATION                      All Other Systems Required for Safety                Section 7.6 UFSAR                                                                            Page 7
: b. Testing capability for elements of the interlocks within (not external to) the protection system is consistent with the testing principles and methods discussed in Subsection 7.2.2. An alarm is provided in the control room when there is low auctioneered RCS temperature (below RNDT) coincident with a closed position of the motor-operated (MOV) pressurizer relief isolation valve. This MOV is in the same fluid path as the PORV, with separate MOV and alarms used with the second PORV.
: c. A loss of offsite power will not defeat the provisions for an electrical power source for the interlocks, because these provisions are through onsite power which is described in Section 8.3.
In addition, associated with each motor-operated isolation valve for each PORV is a pressure interlock that opens the isolation valves on a high pressurizer pressure signal.
7.6.7          Fire Protection Instrumentation and Detection System These systems are discussed in Subsection 9.5.1 and in the report, "Seabrook Station Fire Protection Program Evaluation and Comparison to Branch Technical Position APCSB 9.5.1, Appendix A."
7.6.8          Isolation of NNS Components in Primary Component Cooling Water System A head tank is provided for each PCCW loop. The tank instrumentation is identical for both the loops. PCCW supply to nonessential (NNS) components is isolated on the head tank isolation signal. Isolation of the NNS portion of the PCCW system from its safety-related portion is accomplished in two phases. The first phase is the isolation of the waste processing building heat loads which are isolated either on a safeguard "T" signal (containment isolation phase-A) or upon a head tank low level isolation signal (see Drawing NHY-503273). The latter signal is indicative of a possible break in the NSS portion of the PCCW loop. The head tank isolation signal is generated using a two-out-of-three logic from the head tank level measurements in each tank (see Drawing NHY-503278). The second phase of PCCW isolation is the isolation of the loads in the Containment. These are isolated on either a safeguard "P" signal (containment isolation phase-B) or a low-low level in the PCCW head tank (see Drawing NHY-503268). The system is designed single failure-proof at the system level and meets the requirements of IEEE 279-1971. The sensors, activation logic components, and the solenoid valves are all classified as Class 1E equipment. The environmental qualification of the Class 1E components is discussed in Section 3.11.
7.6.9          Protection Against Spurious Valve Actuation
: a. For the motor-operated valves listed below, protection against spurious actuation is provided by removal of motor and control power by de-energizing their Motor Control Centers (MCC 522 and MCC 622). Control of the breakers supplying power to these MCCs is provided in the main control room.
 
SEABROOK                        INSTRUMENTATION AND CONTROLS                      Revision 12 STATION                        All Other Systems Required for Safety                Section 7.6 UFSAR                                                                              Page 8 Valve                          Function
: 1.      RH-V14 and -V26            Residual Heat Removal Cold Leg Injection Valves
: 2.      RH-V32 and -V70            Residual Heat Removal Hot Leg Injection Valves
: 3.      SI-V3, -V17, -V32 and Safety Injection Accumulator Isolation Valves
                        -V47
: 4.      SI-V114                    Safety Injection Cold Leg Isolation Valves
: 5.      SI-V102 and -V77          Safety Injection Pump to Hot Leg Isolation Valves For all these valves, redundant valve position indication lights are provided at the Main Control Board (MCB), powered by different sources and actuated by different limit switches. "Control Power Available" indication is provided at the MCB for these valves.
: b.      SI-V93 (Safety injection pumps discharge to refueling water storage tank) is protected against spurious actuation by providing a nonreversing contactor in series with the normal reversing contactor. Control of this extra contactor is provided through a separate key-locked selector switch on the MCB. Position indication is from the normal valve control circuit (see Drawing NHY-503901).
SI-V93 cannot be operated until the applicable interlocks are satisfied, the control switch for SI-V93 has been placed in "open" or "close," the key-locked selector switch has been unlocked and placed in "on."
: c.      Other safety-related motor-operated valves have power removed for reasons other than to prevent a single failure from preventing a safety function (BTP EICSB 18). These valves are provided with control room position indication that is independent of the motor-operator power supply. Position indication is available when power is removed from the motor operator.
7.6.10          High Energy Line Break Sensing System On the basis of Standard Review Plan Subsections 3.6.1 and 3.6.2, types and locations of line breaks are postulated that would result in severe environmental conditions at the location of safety grade equipment. To mitigate the effects of such harsh environmental conditions, affected lines are isolated automatically by high energy line break (HELB) signals which are generated by redundant fast response thermocouples strategically located near postulated line breaks in PAB and containment enclosure areas. On a predetermined high temperature (on a per train basis) at any one of the locations described, a HELB signal is automatically generated which closes the following valves:
 
SEABROOK                        INSTRUMENTATION AND CONTROLS                      Revision 12 STATION                      All Other Systems Required for Safety              Section 7.6 UFSAR                                                                            Page 9 a)      The steam generator blowdown containment isolation valves b)      The auxiliary steam isolation valves c)      The letdown line containment isolation valves.
Refer to Subsections 9.3.4.5o, 10.4.8.6a, and 10.4.11.2 for further details.
7.6.11          Shutdown Monitor The shutdown monitor measures the count rate from a neutron counting instrument. It performs a statistical time average of the neutron count rate and displays this average in the source range from 0.1 counts per second (cps) to 104 cps. It also provides an alarm output to indicate a decrease in reactor shutdown margin when the neutron count rate increases by an amount equal to the preset alarm ratio. The shutdown monitor alarm setpoint is continuously recalculated and automatically reduced as the reactor is shut down and the neutron flux is reduced. When the neutron count rate achieves steady value and then eventually increases, the alarm setpoint remains at its lowest value unless it is manually reset. An alarm will occur when the time averaged neutron count rate increases due to a reactivity addition to a value equal to the preset alarm setpoint. The response time for the alarm depends on the initial count rate and the rate of change of neutron flux. The preset alarm ratio is chosen to ensure an early alarm will occur during an inadvertent boron dilution event. Analysis of inadvertent boron dilution events is discussed in Subsection 15.4.6.
There are two redundant alarm channels. The alarm from one shutdown monitor channel is annunciated on the VAS and the alarm for the other channel is annunciated on a hardwired alarm on the main control board. Each shutdown monitor channel receives an input signal from an independent source range neutron flux monitoring channel.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                      Revision 12 STATION                      All Other Systems Required for Safety              Section 7.6 UFSAR                                                                            Page 10 7.6.12          ATWS Mitigation System Generic analyses of Anticipated Transients Without Scram (ATWS) events for NSSS designs similar to Seabrook Station have determined that acceptable consequences would result provided the turbine trips and emergency feedwater are initiated in a timely fashion (References 3 and 4).
Seabrooks licensed power level exceeds the power level assumed in the generic ATWS analysis.
As a result, acceptable ATWS consequences were confirmed by explicit transient analyses at Seabrooks licensed power level. The most severe ATWS scenarios were those in which there is complete loss of normal feedwater. These include loss of normal feedwater and loss of load caused by a loss of main condenser vacuum, which results in a loss of both feedwater pumps.
The primary safety concern for these two transients is the potential for high pressures within the Reactor Coolant System (RCS). If a common mode failure in the protection system incapacitates Emergency Feedwater (EFW) flow initiation and/or turbine trip in addition to prohibiting a scram, then an alternate method of providing EFW flow and a turbine trip is required to maintain the RCS pressure below 3200 psig. This is the pressure corresponding to the ASME Boiler and Pressure Vessel Code Level C service limit stress criteria. The ATWS Mitigation System (AMS) provides an alternative means for automatically tripping the turbine and actuating Emergency Feedwater (EFW) flow apart from the protection system in the event of a loss of normal feedwater and/or a loss of load ATWS. The system design complies with the generic functional requirements established by References 5 and 6. Quality Assurance procedures for the AMS comply with the requirements of Reference 7.
The AMS actuation signal is initiated on low-low-low steam generator level, on three-out-of-four steam generators (one sensor for each steam generator). The setpoint is lower than the low-low steam generator level reactor trip/EFW actuation setpoint, and a time delay is added to the actuation signal in order to permit the protection system to actuate prior to AMS actuation. The maximum time delay is limited by the response time requirement from the ATWS analysis.
A permissive (C-20) is provided which will permit an AMS actuation when both turbine impulse pressure transmitters indicate more than the setpoint. The analyses (Reference 4) show that the AMS is not required to actuate at or below 70 percent reactor power to limit peak Reactor Coolant System pressure; however, in order to limit the amount of RCS voiding to that previously predicted in Reference 4, the C-20 setpoint is set to a nominal 20% reactor power to ensure that AMSAC is armed whenever reactor power is greater than or equal to 40 percent. The C-20 permissive is maintained following a turbine trip from above the C-20 setpoint long enough to allow the AMS to perform its function, if necessary. In the event of a turbine trip below the P-9 setpoint the AMSAC will not be armed; however, based on the analysis in reference 8, AMSAC is not required below the P-9 setpoint since the amount of RCS voiding is less than that predicted at 100% power with AMSAC.
The AMS actuation signal is maintained after an initiation, long enough so that the EFW turbine steam supply valve will go to its full open position and latch in. Once the AMS is initiated, separate deliberate manual actions are required to secure EFW flow and to reset the turbine.
Figure 7.6-7 shows the logic for the system.
 
SEABROOK                        INSTRUMENTATION AND CONTROLS                        Revision 12 STATION                      All Other Systems Required for Safety                Section 7.6 UFSAR                                                                              Page 11 The AMS is not safety related or seismically qualified. The system shares narrow-range steam generator level and turbine impulse pressure sensors with the protection system; however, the AMS inputs are isolated from the protection system. The AMS bistables and logic network are of a different design and manufacturer than the protection system and are physically located in a separate cabinet. The logic cabinet is powered from a non-Class 1E 125V DC power source which is capable of providing uninterrupted power during a loss of offsite power. The outputs of the AMS are electrically isolated from the safety-related EFW pump circuit by relays in the isolation relay cabinet. The system has been designed so that a single failure will not result in an inadvertent actuation. The system may be bypassed to allow testing at power.
7.6.13          References
: 1.      The Institute of Electrical and Electronic Engineers, Inc., "IEEE Standard:
Criteria for Protection Systems for Nuclear Power Generating Stations,"
IEEE Standard 279-1971.
: 2.      The Institute of Electrical and Electronic Engineers, Inc., "IEEE Criteria for the Periodic Testing of Nuclear Power Generating Station Protection Systems," IEEE Standard 338-1975.
: 3.      "Westinghouse Anticipated        Transients  Without      Trip  Analysis,"
WCAP-8330, August 1974.
: 4.      NS-TMA-2182, Anderson, T.M. "Anticipated Transients Without Scram for Westinghouse Plants," December 1979.
: 5.      "AMSAC" Generic Design Package," WCAP-10858-P-A, Revision 1, July 1987.
: 6.      ATWS Final Rule - Code of Federal Regulations 10 CFR 50.62 and Supplementary Information Package, "Reduction of Risk from Anticipated Transients Without Scram (ATWS) Events for Light-Water-Cooled-Nuclear Power Plants."
: 7.      "Quality Assurance Guidance for ATWS Equipment That Is Not Safety-Related," Generic Letter 85-06; April 16, 1985.
: 8.      Westinghouse Technical Bulletin ESBU-TB-97-08, "AMSAC C-20 Interlock Permissive," November 1997.
 
SEABROOK                        INSTRUMENTATION AND CONTROLS                        Revision 21 STATION                                                                            Section 7.7 Control Systems Not Required for Safety UFSAR                                                                              Page 1 7.7            CONTROL SYSTEMS NOT REQUIRED FOR SAFETY The general design objectives of the plant control systems are:
* To establish and maintain power equilibrium between primary and secondary systems during steady-state unit operation;
* To constrain operational transients so as to preclude unit trip and re-establish steady-state unit operation;
* To provide the reactor operator with monitoring instrumentation that indicates all required input and output control parameters of the systems and ensures the capability for the operator to assume manual control of the system.
7.7.1          Description The plant control systems described in this section perform the following functions:
: 1. Reactor Control System
: a.      Enables the nuclear plant to accept a step-load increase of 10 percent or decrease of 15 percent and a ramp increase or decrease of 5 percent per minute within the load range of 15 percent to 100 percent without reactor trip, steam dump, or pressurizer relief actuation, subject to possible xenon limitations.
: b.      Maintains reactor coolant average temperature (Tavg) within prescribed limits by creating the bank demand signals for moving groups of full-length road cluster control assemblies during normal operation and operational transients. The Tavg control also supplies a signal to pressurizer water level control, and steam dump control.
: 2. Rod Control System Provides for reactor power modulation by manual or automatic control of full length control rod banks in a preselected sequence and for manual operation of individual banks.
: 3. Systems for Monitoring and Indicating
: a.      Provide alarms to alert the operator if the required core reactivity shutdown margin is not available due to excessive control rod insertion.
: b.      Display control rod position.
: c.      Provide alarms to alert the operator in the event of control rod deviation exceeding a preset limit.
 
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: 4. Plant Control System Interlocks
: a.      Prevent further withdrawal of the control banks when signal limits are approached that predict the approach of a DNBR limit or kW/ft limit.
: b.      Inhibit automatic turbine load change as required by the Nuclear Steam Supply System.
: 5. Pressurizer Pressure Control Maintains or restores the pressurizer pressure to the design pressure +/-50 psi (which is well within reactor trip and relief and safety valve actuation setpoint limits) following normal operational transients that induce pressure changes by control (manual or automatic) of heaters and spray in the pressurizer. Provides steam relief by controlling the power-operated relief valves.
: 6. Pressurizer Water Level Control Establishes, maintains, and restores pressurizer water level within specified limits as a function of the average coolant temperature. Changes in level are caused by coolant density changes induced by loading, operational, and unloading transients. Level changes are produced by means of charging flow control (manual or automatic) as well as by manual selection of modulate letdown valves. Maintaining coolant level in the pressurizer within prescribed limits by actuating the charging and letdown system thus provides control of the reactor coolant water inventory.
: 7. Steam Generator Water Level Control
: a.      Establishes and maintains the steam generator water level to within predetermined physical limits during normal operating transients.
: b.      Restores the steam generator water level to within predetermined limits at unit trip conditions. Regulates the feedwater flow rate so that under operational transients the heat sink for the Reactor Coolant System is maintained.
: 8. Steam Dump Control
: a.      Permits the nuclear plant to accept a sudden loss of load without incurring reactor trip. Steam is dumped to the condenser and/or the atmosphere as necessary to accommodate excess power generation in the reactor during turbine load reduction transients.
: b.      Insures that stored energy and residual heat are removed following a reactor trip to bring the plant to equilibrium no load conditions without actuation of the steam generator safety valves.
: c.      Maintains the plant at no load conditions and permits a manually controlled cooldown of the plant.
 
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: 9.      Incore Instrumentation Provides information on the neutron flux distribution and on the core outlet temperatures at selected core locations.
7.7.1.1        Reactor Control System The Reactor Control System enables the nuclear plant to follow load changes automatically, including the acceptance of step load increase of 10 percent or decreases of 15 percent and ramp increases or decreases of 5 percent per minute within the load range of 15 percent to 100 percent, without reactor trip, steam dump, or pressure relief (subject to possible xenon limitations). The system is also capable of restoring coolant average temperature to within the programmed temperature deadband following a change in load. Manual control rod operation may be performed at any time, including during end-of-cycle coastdowns.
The Reactor Control System controls the reactor coolant average temperature by regulation of control rod bank position. The reactor coolant loop average temperatures are determined from three hot leg and one cold leg measurements in each reactor coolant loop. There is an average coolant temperature (Tavg) computed for each loop, where:
T hot + T cold          T H1 +T H2 + T H3 T AVG =                  T hot =
2                        3 The error between the programmed reference temperature (based on turbine impulse chamber pressure) and the average of the Tavg measured temperatures (which is processed through a lead-lag compensation unit) from each of the reactor coolant loops constitutes the primary control signal as shown in general on Figure 7.7-1 and in more detail on the functional diagrams shown in Figure 7.2-9. The system is capable of restoring coolant average temperature to the programmed value following a change in load. The programmed coolant temperature increases linearly with turbine load from zero power to full power condition. The Tavg also supplies a signal to pressurizer level control and steam dump control and rod insertion limit monitoring.
The temperature channels needed to derive the temperature input signals for the Reactor Control System are fed from protection channels via isolation amplifiers.
An additional control input signal is derived from the reactor power versus turbine load mismatch signal. This additional control input signal improves system performance by enhancing response and reducing transient peaks.
The core axial power distribution is controlled during load follow maneuvers by changing (a manual operator action) the boron concentration in the Reactor Coolant System. The control board  displays (Subsection 7.7.1.3a) indicate the need for an adjustment in the axial power distribution. Adding boron to the reactor coolant will reduce Tavg and cause the rods (through the Rod Control System) to move toward the top of the core. This action will reduce power peaks in the bottom of the core. Likewise, removing boron from the reactor coolant will move the rods further into the core to control power peaks in the top of the core.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                                                                          Section 7.7 Control Systems Not Required for Safety UFSAR                                                                            Page 4 7.7.1.2        Rod Control System The full-length rod control system receives rod speed and direction signals from the Tavg control system. The rod speed demand signal varies over the corresponding range of 3.75 to 45 inches per minute (6 to 72 steps/minute) depending on the magnitude of the input signal. Manual control is provided to move a control bank in or out at a prescribed fixed speed.
When the turbine load reaches approximately 15 percent of rated load, the operator may select the "AUTOMATIC" mode, and rod motion is then controlled by the reactor control systems. A permissive interlock C-5 (see Table 7.7-1) derived from measurements of turbine impulse chamber pressure prevents automatic withdrawal when the turbine load is below 15 percent. In the "AUTOMATIC" mode, the rods are again withdrawn (or inserted) in a predetermined programmed sequence by the automatic programming with the control interlocks (see Table 7.7-1).
The shutdown banks are always in the fully withdrawn position during normal operation, and are moved to this position at a constant speed by manual control prior to criticality. A reactor trip signal causes them to fall by gravity into the core. There are five shutdown banks.
The control banks are the only rods that can be manipulated under automatic control. Each control bank is divided into two groups to obtain smaller incremental reactivity changes per step.
All Rod Cluster Control Assemblies in a group are electrically paralleled to move simultaneously. There is individual position indication for each Rod Cluster Control Assembly.
Power to rod drive mechanisms is supplied by two motor-generator sets operating from two separate 480-volt, three-phase buses. Each generator is the synchronous type and is driven by a 200-Hp induction motor. The AC power is distributed to the rod control power cabinets through the two series connected reactor trip breakers.
The variable speed rod drive programmer provides the ability to insert small amounts of reactivity at low speed to accomplish fine control of reactor coolant average temperature about a small temperature deadband, as well as furnishing control at high speed. A summary of the rod cluster control assembly sequencing characteristics is given below.
: a.      Two groups within the same bank are stepped so that the relative position of the groups will not differ by more than one step.
: b.      The control banks are programmed so that withdrawal of the banks is sequenced in the following order: control bank A, control bank B, control bank C, and control bank D. The programmed insertion sequence is the opposite of the withdrawal sequence, i.e., the last control bank withdrawn (bank D) is the first control bank inserted.
 
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: c.      The control bank withdrawals are programmed so that when the first bank reaches a preset position, the second bank begins to move out simultaneously with the first bank which continues to move toward its fully withdrawn position. When the second bank reaches a preset position, the third bank begins to move out, and so on. This withdrawal sequence continues until the unit reaches the desired power level. The control bank insertion sequence is the opposite.
: d.      Overlap between successive control banks is adjustable between 0 to 50 percent (0 to 115 steps,) with an accuracy of +/-1 step.
: e.      Rod speeds for either the shutdown banks or manual operation of the control banks can be controlled between a minimum of 6 steps per minute and a maximum of 72 (+0,-0) steps per minute.
Credible rod control equipment malfunctions which could potentially cause inadvertent positive reactivity insertions due to inadvertent rod withdrawal, incorrect overlap or malpositioning of the rods are the following:
Failures in the manual rod controls:
: 1.      Rod Motion Control Switch (In-Hold-Out)
: 2.      Bank Selector Switch Failures in the overlap and bank sequence program control:
: 1.      Logic Cabinet Systems
: 2.      Power Supply Systems
: a.      Failure in the Manual Rod Controls
: 1.      Rod Motion Control Switch (In-Hold Out) Failure The Rod Motion Control Switch is a three position lever switch. The three positions are "In," "Hold" and "Out." These positions are effective when the bank selector switch is in manual. Failure of the rod motion control switch (contacts failing short or activated relay failures) would have the potential, in the worst case, to produce positive reactivity insertion by rod withdrawal when the bank selector switch is in the manual position or in a position which selects one of the banks.
When the bank selector switch is in the automatic position the rods would obey the automatic commands, and failures in the rod motion control switch would have no effect on the rod motion regardless of whether the rod motion control switch is in "In," "Hold" or "Out."
 
SEABROOK            INSTRUMENTATION AND CONTROLS                        Revision 21 STATION                                                                  Section 7.7 Control Systems Not Required for Safety UFSAR                                                                    Page 6 In the case where the bank selector switch is selecting a bank, and a failure occurs in the rod motion switch that would command the bank "Out" even when the rod motion control switch was in an "In" or "Hold" position, the selected bank could inadvertently withdraw. This failure is bounded in the safety analysis (Chapter 15) by the uncontrolled bank withdrawal subcritical and at power transients. A reactivity insertion of up to 75 pcm/sec is assumed in the analysis due to rod movement. This value of reactivity insertion rate is consistent with the withdrawal of two banks.
Failure that can cause more than one group of four mechanisms to be moved at one time within a power cabinet is not a credible event, because the circuit arrangement for the movable and lift coils would cause the current available to the mechanisms to divide equally between coils in the two groups (in a power supply). The drive mechanism is designed so that it will not operate on half current. A second feature in this scenario would be the multiplexing failure detection circuit included in each power cabinet. This circuit would stop rod withdrawal (or insertion).
The second case considered in the potential for inadvertent reactivity insertion due to possible failures is when the selector switch is in the manual position. Such a case could produce with a failure in the rod motion control switch, a scenario where the rods could inadvertently withdraw in a programmed sequence. The overlap and bank sequence are programmed when the selection is in either automatic or manual. This scenario is also bounded by the reactivity values assumed in the SAR accident analysis. In this case, the operator can trip the reactor, or the protection system would trip the reactor via Power Range Neutron Flux-High, or Overtemperature T.
: 2. Bank Selector Switch Failure A failure of the bank selector switch produces no consequences when the "In-Hold-Out" manual switch is in the "Hold" position. This is due to the following design feature:
The bank selector switch is series wired with the "In-Hold-Out" lever switch for manual and individual control rod operation. With the "In-Hold-Out" lever switch in the "Hold" position, the bank selector switch can be positioned without rod movement.
 
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: b. Failures in the Overlap and Bank Sequence Program Control The rod control system design prevents the movement of the groups out of sequence, as well as limiting the rate of reactivity insertion. The main feature that performs the function of preventing malpositioning produced by groups out of sequence is included in the block supervisory memory buffer and control. This circuitry accepts and stores the externally generated command signals. In the event of out-of-sequence input command to the rods while they are in movement, this circuit will inhibit the buffer memory from accepting the command. If a change of signal command appears, this circuit would stop the system after allowing the slave cyclers to finish their current sequencing. Failure of the components related to this system will also produce rod deviation alarm and insertion limit alarm (see Subsection 7.7.1.3). Failures within the system such as failures of supervisory logic cards, pulser cards, etc., will also cause an urgent alarm. An urgent alarm will be followed by the following actions:
        -      Automatic de-energizing of the lift coil and reduced current energizing of the stationary gripper coils and movable gripper coils
        -      Activation of the alarm light (urgent failure) on the power suppler cabinet front panel
        -      Activation of rod control urgent failure annunciation window on the plant annunciator.
The urgent alarm is produced in general by:
        -      Regulation failure detector
        -      Phase failure detector
        -      Logic error detector
        -      Multiplexing error detector
        -      Interlock failure detector.
 
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: 1. Logic Cabinet Failures The Rod Control System is designed to limit the rod speed control signal output to a value that causes the pulser (logic cabinet) to drive the control rod driving mechanism at 72 steps per minute. If a failure should occur in the pulses or the Reactor Control System, the highest stepping rate possible is 77 steps per minute, which corresponds to one step every 780-milliseconds. A commanded stepping rate higher than 77 steps per minute would result in "GO" pulses entering a slave cycler while it is sequencing its mechanisms through a 780-millisecond step. This condition stops the control bank motion automatically and alarms are activated locally and in the control room. It also causes the affected slave cycler to reflect further "GO" pulses until it is reset.
Failures that cause the 780-millisecond step sequence time to shorten will not result in higher rod speeds since the stopping rate is proportional to the pulsing rate. Simultaneous failures in the pulser or Rod Control System and in the clock circuits that determine the 780-millisecond stepping sequence could result in higher CRDM speed; however, in the unlikely event of these simultaneously multiple failures, the maximum CRDM operation speed would be no more than approximately 100 steps per minute due to mechanical limitation. This speed has been verified by tests conducted on the CRDMs.
Surveillance testing of the Reactor Control System and the Rod Control System is performed at periodic intervals to detect failures that could lead to an increase in rod speed.
Relative to failures causing movement of the rods out of sequence, no single failure was discovered (WCAP 8976) that would cause a rapid uncontrolled withdrawal of Control Bank D (taken as worst case) when operating in the automatic bank overlap control mode with the reactor at near full-power output. The analysis revealed that many of the failures postulated were in a safe direction and that rod movement is blocked by the rod urgent alarm.
 
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: 2.      Power Supply System Failures Analysis of the power cabinet disclosed no single component failures that would cause the uncontrolled withdrawal of a group of rods serviced by the power cabinet. The analysis substantiates that the design of a power cabinet is "fail-preferred" in regard to a rod withdrawal accident if a component fails. The end results of the failure are either that of blocking rod movement, or that of dropping an individual rod or rods, or a group of rods. No failure within the power cabinet which could cause erroneous drive mechanism operation will remain undetected. Sufficient alarm monitoring (including "urgent" alarm) is provided in the design of the power cabinet for fault detection of those failures which could cause erroneous operation of a group of mechanisms. As noted in the foregoing, diverse monitoring systems are available for detection of failures that cause the erroneous operation of an individual control rod drive mechanism.
In summary, no single failure within the Rod Control System can cause either reactivity insertions or malpositioning of the control rods, resulting in core thermal conditions not bounded by analyses contained in Chapter 15.
7.7.1.3    Plant Control Signals for Monitoring and Indicating
: a. Monitoring Functions Provided by the Nuclear Instrumentation System The power range channels are important because of their use in monitoring power distribution in the core within specified safe limits. They are used to measure power level, axial flux imbalance and radial flux imbalance. These channels are capable of recording overpower excursions up to 200 percent of full power.
Suitable alarms are derived from these signals as described below.
Basic power range signals are:
: 1.      Total current from a power range detector (four such signals from separate detectors); these detectors are vertical and have a total active length of 10 feet.
: 2.      Current from the upper half of each power range detector (four signals).
: 3.      Current from the lower half of each power range detector (four signals).
 
SEABROOK                INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                                                                    Section 7.7 Control Systems Not Required for Safety UFSAR                                                                      Page 10 Derived from these basic signals are the following (including standard signal processing for calibration):
: 1.      Indicated nuclear power (four signals)
: 2.      Indicated axial flux imbalance (I), derived from upper half flux minus lower half flux (four signals)
Alarm functions derived are as follows:
: 1.      Deviation (maximum minus minimum of four) in indicated nuclear power
: 2.      Upper radial tilt (maximum to average of four) on upper-half currents
: 3.      Lower radial tilt (maximum to average of four) on lower-half currents.
Nuclear power (SR, IR and PR) is continuously recorded on the control board.
Indicators are provided on the control board for nuclear power and for axial flux imbalance.
The axial flux difference (AFD) monitor alarms are derived from the plant process computer which determines the one minute values of the excore detector outputs to monitor  in the reactor core and alerts the operator where I alarm conditions exist. Two types of alarm messages are output. An alarm message is output immediately upon determining a I outside any of the acceptable spaces as defined in Technical Specification Bases.
Additional background information on the Nuclear Instrumentation System can be found in Reference 1.
 
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: b. Rod Position Monitoring of Full Length Rods Two separate systems are provided to sense and display control rod position as described below:
: 1. Digital Rod Position Indication System The digital rod position indication system measures the actual position of each full-length rod using a detector which consists of discrete coils mounted concentrically with the rod drive pressure housing. The coils are located axially along the pressure housing and magnetically sense the entry and presence of the rod drive shaft through its centerline. For each detector, the coils are interlaced into two data channels, and are connected to the containment electronics (Data A and B) by separate multi-conductor cables. By employing two separate channels of information, the digital rod position indication system can continue to function (at reduced accuracy) when one channel fails. Multiplexing is used to transmit the digital position signals from the containment electronics to the control board display unit.
The control board display unit contains a column of light-emitting diodes (LEDs) for each rod. At any given time, the one LED illuminated in each column shows the position for that particular rod. Since shutdown rods are always fully withdrawn with the plant at power, their position is displayed to +/-4 steps only from rod bottom to 18 steps and from 210 steps to 228 steps. All intermediate positions of the rod are represented by a single "transition" LED. Each rod of the control banks has its position displayed to +/-4 steps throughout its range of travel.
Included in the system is a rod at bottom signal for each rod that operates a local alarm. Also a control room annunciator is actuated when any control rod in a withdrawn bank is at bottom.
: 2. Demand Position System The demand position system counts pulses generated in the rod drive control system to provide a digital readout of the demanded bank position.
The demand position and digital rod position indication systems are separate systems, but safety criteria were not involved in the separation, which was a result only of operational requirements. Operating procedures require the reactor operator to compare the demand and indicated (actual) readings from the rod position indication system to verify operation of the Rod Control System.
 
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: c. Control Bank Rod Insertion Monitoring When the reactor is critical, the normal indication of reactivity status in the core is the position of the control bank in relation to reactor power (as indicated by the reactor coolant system loop T) and coolant average temperature. These parameters are used to calculate insertion limits for the control banks. Two alarms are provided for each control bank:
: 1.      The "low" alarm alerts the operator of an approach to the rod insertion limits which may require boron addition by following normal procedures with the Chemical and Volume Control System.
: 2.      The "low-low" alarm alerts the operator to take immediate action to verify shutdown margin and, if required add boron to the Reactor Coolant System by any one of several alternate methods.
The purpose of the control bank rod insertion monitor is to give warning to the operator of excessive rod insertion. The insertion limit maintains sufficient core reactivity shutdown margin following reactor trip, provides a limit on the maximum inserted rod worth in the unlikely event of a hypothetical rod ejection, and limits rod insertion so that acceptable nuclear peaking factors are maintained.
Since the amount of shutdown reactivity required for design shutdown margin following a reactor trip increases with increasing power, the allowable rod insertion limits must be decreased (the rods must be withdrawn further) with increasing power. Two parameters which are proportional to power are used as inputs to the insertion monitor. These are the T between the hot leg and the cold leg, which is a direct function of reactor power, and Tavg, which is programmed as a function of power. The rod insertion monitor uses parameters for each control rod bank as follows:
ZLL    = A(T)auct    +      B(Tavg)average +      C Where:
ZLL          =  Maximum permissible insertion limit for affected control bank (T)auct      =  Highest T of all loops (Tavg)average =  Average Tavg of all loops A, B, C      =  Constants chosen to maintain ALL  actual limit based on physics calculations The control rod bank demand position (Z) is compared to ZLL as follows:
If Z - ZLL  D a low alarm is actuated If Z - ZLL  E a low-low alarm is actuated
 
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Actuation of the low alarm alerts the operator of an approach to a reduced shutdown reactivity situation. Administrative procedures require the operator to add boron through the Chemical and Volume Control System. Actuation of the low-low alarm requires the operator to initiate emergency boration procedures.
The value for "E" is chosen so that the low-low alarm would normally be actuated before the insertion limit is reached. The value for "D" is chosen to allow the operator to follow normal boration procedures. Figure 7.7-2 shows a block diagram representation of the control rod bank insertion monitor. The monitor is shown in more detail on the functional diagrams shown in Figure 7.2-9. In addition to the rod insertion monitor for the control banks, the plant computer, which monitors individual rod positions, provides an alarm that is associated with the rod deviation alarm discussed in Subsection 7.7.1.3d to warn the operator if any shutdown Rod Cluster Control Assembly leaves the fully withdrawn position.
Rod insertion limits are established by:
: 1.      Establishing the allowed rod reactivity insertion at full power consistent with the purposes given above
: 2.      Establishing the differential reactivity worth of the control rods when moved in normal sequence
: 3.      Establishing the change in reactivity with power level by relating power level to rod position
: 4.      Linearizing the resultant limit curve. All key nuclear parameters in this procedure are measured as part of the initial and periodic physics testing program.
Any unexpected change in the position of the control bank under automatic control, or a change in coolant temperature under manual control, provides a direct and immediate indication of a change in the reactivity status of the reactor.
In addition, samples are taken periodically of coolant boron concentration.
Variations in concentration during core life provide an additional check on the reactivity status of the reactor, including core depletion.
: d. Rod Deviation Alarm A rod deviation function is performed as part of the Digital Rod Position Indication System, where an alarm is generated if a preset limit is exceeded as a result of a comparison of any control rod against the other rods in a bank. The deviation alarm of a shutdown rod is based on a preset insertion limit being exceeded.
 
SEABROOK                        INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                                                                            Section 7.7 Control Systems Not Required for Safety UFSAR                                                                              Page 14 The demanded and measured rod position signals are also monitored by the plant computer which provides a visual printout and an audible alarm whenever an individual rod position signal deviates from the other rods in the bank by a preset limit. The alarm can be set with appropriate allowance for instrument error and within sufficiently narrow limits to preclude exceeding core design hot channel factors.
Figure 7.7-3 is a block diagram of the rod deviation comparator and alarm system implemented by the plant computer. Additionally, the DRPI system contains rod deviation circuitry that detects and alarms the following conditions:
: 1.      When any 2 rods within the same control bank are misaligned by a preset distance ( 12 steps) and
: 2.      When any shutdown rod is below the full-out position by a preset distance (18 steps).
: e.      Rod Bottom Alarm A rod bottom signal for the control rods in the digital rod position system is used to operate a control relay, which generates a rod drop alarm.
7.7.1.4        Plant Control System Interlocks The listing of the plant control system interlocks, along with the description of their derivations and functions, is presented in Table 7.7-1. It is noted that the designation numbers for these interlocks are preceded by "C." The development of these logic functions is shown in the functional diagrams (Figure 7.2-4, Figure 7.2-5, Figure 7.2-9, Figure 7.2-10, and Figure 7.2-15.)
: a.      Rod Stops Rod stops are provided to prevent abnormal power conditions which could result from excessive control rod withdrawal initiated by either a control system malfunction or operator violation of administrative procedures.
Rod stops are the C-1, C-2, C-5 and C-11 control interlocks identified in Table 7.7-1.
: b.      Turbine Loading Stop An interlock (C-16) is provided to limit turbine loading during a rapid return to power transient when a reduction in reactor coolant temperature is used to increase reactor power (through the negative moderator coefficient). This interlock limits the drop in coolant temperature to exceed cooldown accident limits and preserves satisfactory steam generator operating conditions.
Subsequent automatic turbine loading can begin after the interlock has been cleared by an increase in coolant temperature which is accomplished by reducing the boron concentration in the coolant.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                        Revision 21 STATION                                                                            Section 7.7 Control Systems Not Required for Safety UFSAR                                                                              Page 15 7.7.1.5        Pressurizer Pressure Control The reactor coolant system pressure is controlled by using either the heaters (in the water region) or the spray (in the steam region) of the pressurizer plus steam relief for large transients. The electrical immersion heaters are located near the bottom of the pressurizer. A portion of the heater group is proportionally controlled to correct small pressure variations. These variations are caused by heat losses, including heat losses due to a small continuous spray. The remaining (backup) heaters are turned on when the pressurizer pressure controlled signal demands approximately 100 percent proportional heater power.
The pressurizer heaters are controlled from nonredundant pressurizer pressure and level signals through contacts developed in the nonsafety-related auxiliary relay racks. Two groups of backup heaters are supplied from the redundant onsite power supplies.
Equipment associated with the pressurizer heater power circuits inside Containment have been qualified as Class 1E components up to the point of the pressurizer heater connection.
The spray nozzles are located on the top of the pressurizer. Spray is initiated when the pressure controller spray demand signal is above a given setpoint. The spray rate increases proportionally with increasing spray demand signal until it reaches a maximum value.
Steam condensed by the spray reduces the pressurizer pressure. A small continuous spray is normally maintained to reduce thermal stresses and thermal shock and to help maintain uniform water chemistry and temperature in the pressurizer.
Power-operated relief valves operation may prevent unnecessary challenges to the pressurizer safety valves during some positive pressure transients. See UFSAR Subsection 5.2.2 for a discussion of the overpressure protection provided by the safety valves.
Each pressurizer relief line consists of a motor-operated and a solenoid-operated valve in series.
These valves are manually operable from either the main control board or the remote safe shutdown panel. Valve control point is switch selectable from the RSS panel.
A block diagram of the Pressurizer Pressure Control System is shown on Figure 7.7-4.
7.7.1.6        Pressurizer Water Level Control The pressurizer operates by maintaining a steam cushion over the reactor coolant. As the density of the reactor coolant adjusts to the various temperatures, the steam water interface moves to absorb the variations with relatively small pressure disturbances.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                                                                          Section 7.7 Control Systems Not Required for Safety UFSAR                                                                            Page 16 The water inventory in the Reactor Coolant System is maintained by the Chemical and Volume Control System. During normal plant operation, the charging flow varies to produce the flow demanded by the pressurizer water level controller. The pressurizer water level is programmed as a function of coolant average temperature. The pressurizer water level decreases as the load is reduced from full load. This is a result of coolant contraction following programmed coolant temperature reduction from full power to low power. The programmed level is designed to match as nearly as possible the level changes resulting from the coolant temperature changes.
To control pressurizer water level during startup and shutdown operations, the charging flow is manually regulated from the main control room. The letdown line isolation valves are closed on low pressurizer level.
A block diagram of the Pressurizer Water Level Control System is shown on Figure 7.7-5.
7.7.1.7        Steam Generator Water Level Control Each steam generator is equipped with a three element feedwater flow controller which is planned to operate with a constant level setpoint. The three-element feedwater controller regulates the feedwater valve by continuously comparing the feedwater flow signal, the water level signal, the constant setpoint and the pressure compensated steam flow signal. The feedwater pump speed is varied to maintain a programmed pressure differential between the steam header and the feed header. The speed controller continuously compares the actual P with a programmed Pref which is a linear function of steam flow. Continued delivery of feedwater to the steam generators is required as a sink for the heat stored and generated in the reactor following a reactor trip and turbine trip. An override signal closes all feedwater valves when the average coolant temperature is below a given temperature and the reactor has tripped, on steam generator high-high level or safety injection. Manual override of the Feedwater Control System is available at all times.
Block diagrams of the Steam Generator Water Level Control System and the Main Feedwater Pump Speed Control System are shown in Figure 7.7-6 and Figure 7.7-7.
7.7.1.8        Steam Dump Control The Steam Dump System is designed to accept a 50 percent loss of net load without tripping the reactor.
The automatic Steam Dump System is able to accommodate this abnormal load rejection and to reduce the effects of the transient imposed upon the Reactor Coolant System. By bypassing main steam directly to the condenser and/or the atmosphere, an artificial load is thereby maintained on the primary system. The Rod Control System can then reduce the reactor temperature to a new equilibrium value without causing overtemperature and/or overpressure conditions. The nominal steam dump design steam flow capacity is 40 percent of full load steam flow at full load steam pressure.
 
SEABROOK                        INSTRUMENTATION AND CONTROLS                        Revision 21 STATION                                                                            Section 7.7 Control Systems Not Required for Safety UFSAR                                                                              Page 17 If the difference between the reference Tavg (Tref) based on turbine impulse chamber pressure and the lead/lag compensated average Tavg exceeds a predetermined amount, and the interlock mentioned below is satisfied, a demand signal will actuate the steam dump to maintain the reactor coolant system temperature within control range until a new equilibrium condition is reached.
To prevent actuation of steam dump on small load perturbations, an independent load rejection sensing circuit is provided. This circuit senses the rate of decrease in the turbine load as detected by the turbine impulse chamber pressure. It is provided to unblock the dump valves when the rate of load rejection exceeds a preset value corresponding to a 15 percent step load decrease or a sustained ramp load decrease of 5 percent/minute.
A block diagram of the Steam Dump Control System is shown on Figure 7.7-8.
: a. Load Rejection Steam Dump Controller This circuit prevents large increases in reactor coolant temperature following a large, sudden load decrease. The error signal is a difference between the lead/lag compensated average Tavg and the reference Tavg as based on turbine impulse chamber pressure. The Tavg signal is the same as that used in the Reactor Coolant System. The lead/lag compensation for the Tavg signal is to compensate for lags in the plant thermal response and in valve positioning. Following a sudden load decrease, Tref is immediately decreased and Tavg tends to increase, thus generating an immediate demand signal for steam dump. Since control rods are available, in this situation, steam dump terminates as the error comes within the maneuvering capability of the control rods.
: b. Plant Trip Steam Dump Controller Following a reactor trip, the load rejection steam dump controller is defeated and the plant trip steam dump controller becomes active. Since control rods are not available in this situation, the demand signal is the error signal between the lead/lag compensated average Tavg.          When the error signal exceeds a predetermined setpoint the dump valves are tripped open in a prescribed sequence. As the error signal reduces in magnitude indicating that the reactor coolant system Tavg is being reduced toward the reference no-load value, the dump valves are modulated by the plant trip controller to regulate the rate of removal of decay heat and thus gradually establish the equilibrium hot shutdown condition.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                                                                          Section 7.7 Control Systems Not Required for Safety UFSAR                                                                            Page 18
: c. Steam Header Pressure Controller Residual heat removal is maintained by the steam generator pressure controller (manually selected) which controls the amount of steam flow to the condensers.
This controller operates a portion of the same steam dump valves to the condensers which are used during the initial transient following turbine reactor trip on load rejection.
7.7.1.9        Incore Instrumentation The Incore Instrumentation System consists of 58 detector assemblies, each containing five fixed detectors, one Type K thermocouple, each detector assembly being at a fixed core location.
Replacement detector assemblies replicate the design of the original assemblies that affect the performance of the fixed detectors. Operation with less than the design number of incore detectors or incore thermocouples is permitted provided that the minimum functionality requirements for each system are met. Additional discussion of the incore instrumentation and use of the core exit thermocouples for accident monitoring instrumentation is provided in Subsections 4.4.6.1 and 7.5.
: a. Detector Assembly The detector assembly consisting of a seamless inconel housing, or housing tube; a seamless inconel calibration tube; five axially-spaced, fixed, self-powered platinum detectors plus a Type K thermocouple. The self-powered fixed detectors are spirally wrapped around the calibration tube. Each fixed detector provides a signal proportional to the local power density within selected fuel assemblies.
During reactor operation, the retractable detector assemblies are stationary. They are extracted downward from the core during refueling to avoid interference within the core. A space above the seal table is provided for the retraction operation.
: b. Fixed Incore Detectors The Fixed Incore Detector System uses platinum self-powered detectors to provide information on the gamma and neutron flux levels in the same 58 instrumented assembly locations within the reactor core.              From this information in conjunction with analytical predictions of the fluxes, the incore three-dimensional power distribution can be inferred.          Once the power distribution has been inferred, the maximum local power peaking and hot channel factors can be derived and compared to established limits.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                                                                          Section 7.7 Control Systems Not Required for Safety UFSAR                                                                            Page 19 The Fixed Incore Detector Data Acquisition System (FIDDAS) collects and stores the 290 detector signals. The hardware used to generate the signal consists of two trains. Each train contains 145 detector and compensator lead inputs into a multiplexer. The multiplexer performs the compensation subtraction and voltage generation. Each multiplexer performs an analog-to-digital data conversion, and the resultant value (signal) is then sent to the main plant computer. The 290 incore instrumentation signals are saved once per minute as a data record on the main plant computer.
The FIDDAS data can be processed by off-line software to infer the measured three-dimensional power distribution and corresponding peaking factors.
References 2, 4, and 5 demonstrated that the Fixed Incore Detector System is acceptable for performing power distribution surveillance compliance.
: c. Thermocouples Type K thermocouples are part of the fixed detector assembly as described in Subsection 7.7.1.9a and thus enter the reactor vessel through the bottom head.
During operation, the thermocouples are located at the exit-flow end of the instrumentation thimble in the fuel assemblies. Each thermocouple measures the temperature of the fluid in the instrumentation guide tube that is heated by conduction from the bulk core fluid and by gamma heating of the components in the guide tube. The thermocouples are sealed at the seal table along with the electrical leads from the fixed neutron flux detectors. Thermocouple readings are displayed on the MCB, Inadequate Core Cooling (ICC) monitor, and the Main Plant Computer System. The information is used as part of the ICC monitor and for monitoring core temperature distribution. Further discussion of this ICC monitor is provided in Subsection 4.4.6.5.
7.7.2          Analysis The plant control systems are designed to assure high reliability in any anticipated operational occurrences. Equipment used in these systems is designed and constructed with a high level of reliability. Conformance to General Design Criterion 13 for instrumentation and control is as indicated in Table 7.1-1.
Instruments including sensing and sample lines are protected from freezing by being (1) located in an area with a heating system; (2) located in an enclosure with a heated tank; or (3) provided with heat tracing. The environmental monitoring and control system satisfy the requirements of Regulatory guide 1.151.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                        Revision 21 STATION                                                                          Section 7.7 Control Systems Not Required for Safety UFSAR                                                                            Page 20 Proper positioning of the control rods is monitored in the control room by bank arrangements of the individual position columns for each Rod Cluster Control Assembly. A rod deviation alarm alerts the operator of a deviation of one Rod Cluster Control Assembly from the other rods in that bank position. There are also insertion limit monitors with visual and audible annunciation.
A rod bottom alarm signal is provided to the control room for each full length Rod Cluster Control Assembly. Four excore long ion chambers also detect asymmetrical flux distribution indicative of rod misalignment.
Overall reactivity control is achieved by the combination of soluble boron and Rod Cluster Control Assemblies. Long-term regulation of core reactivity is accomplished by adjusting the concentration of boric acid in the reactor coolant. Short-term reactivity control for power changes is accomplished by the plant control system which automatically moves Rod Cluster Control Assemblies. This system uses input signals including neutron flux, coolant temperature, and turbine load.
The axial core power distribution is controlled by moving the control rods through changes in reactor coolant system boron concentration. Adding boron causes the rods to move out, thereby reducing the amount of power in the bottom of the core, allowing power to redistribute toward the top of the core. Reducing the boron concentration causes the rods to move into the core, thereby reducing the power in the top of the core; the result redistributes power towards the bottom of the core.
The plant control systems will prevent an undesirable condition in the operation of the plant that, if reached, will be protected by reactor trip. The description and analysis of this protection is covered in Section 7.2. Worst-case failure modes of the plant control systems are postulated in the analysis of off-design operational transients and accidents covered in Chapter 15, such as the following:
: a.      Uncontrolled rod cluster control assembly withdrawal from a sub-critical condition
: b.      Uncontrolled rod cluster control assembly withdrawal at power
: c.      Rod cluster control assembly misalignment
: d.      Loss of external electrical load and/or turbine trip
: e.      Loss of all AC power to the station auxiliaries (Station Blackout)
: f.      Excessive heat removal due to feedwater system malfunctions
: g.      Excessive load increase incident
: h.      Accidental depressurization of the Reactor Coolant System.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                          Revision 21 STATION                                                                              Section 7.7 Control Systems Not Required for Safety UFSAR                                                                                Page 21 These analyses show that a reactor trip setpoint is reached in time to protect the health and safety of the public under those postulated incidents and that the resulting coolant temperatures produce a DNBR well above the limiting value of 1.30. Thus, there will be no cladding damage and no release of fission products to the Reactor Coolant System under the assumption of these postulated worst-case failure modes of the plant control system.
7.7.2.1        Separation of Protection and Control System In some cases, it is advantageous to employ control signals derived from individual protection channels through isolation amplifiers contained in the protection channel. As such, a failure in the control circuitry does not adversely affect the protection channel. Test results have shown that a short circuit or the application (credible fault voltage from within the cabinets) of 118V AC or 140V DC on the isolated output portion of the circuit (nonprotection side of the circuit) will not affect the input (protection) side of the circuit. Table 7.1-1 indicates the conformance to General Design Criterion 24.
Where a single random failure can cause a control system action that results in a generating station condition requiring protective action and can also prevent proper action of a protection system channel designed to protect against the condition, the remaining redundant protection channels are capable of providing the protective action even when degraded by a second random failure. This meets the applicable requirements of Section 4.7 of IEEE Standard 279-1971.
7.7.2.2        Response Considerations of Reactivity Reactor shutdown with control rods is completely independent of the control functions since the trip breakers interrupt power to the full-length rod drive mechanisms regardless of existing control signals. The design is such that the system can withstand accidental withdrawal of control groups or unplanned dilution of soluble boron without exceeding acceptable fuel design limits. The design meets the requirements of the 1971 General Design Criteria 25.
No single electrical or mechanical failure in the Rod Control System could cause the accidental withdrawal of a single Rod Cluster Control Assembly from the partially inserted bank at full power operation. The operator could deliberately withdraw a single Rod Cluster Control Assembly in the control bank; this feature is necessary in order to retrieve a rod, should one be accidentally dropped. In the extremely unlikely event of simultaneous electrical failures which could result in single rod cluster control assembly withdrawal, rod deviation would be displayed on the plant annunciator, and the individual rod position readouts would indicate the relative positions of the rods in the bank. Withdrawal of a single Rod Cluster Control Assembly by operator action, whether deliberate or by a combination of errors, would result in activation of the same alarm and the same visual indications.
 
SEABROOK                        INSTRUMENTATION AND CONTROLS                        Revision 21 STATION                                                                            Section 7.7 Control Systems Not Required for Safety UFSAR                                                                              Page 22 Each bank of control and shutdown rods in the system is divided into two groups (group 1 and group 2) of up to 4 to 5 mechanisms each. The rods comprising a group operate in parallel through multiplexing thyristors. The two groups in a bank move sequentially so that the first group is always within one step of the second group in the bank. The group 1 and group 2 power circuits are installed in different cabinets as shown in Figure 7.7-14, which also shows that one group is always within one step ( inch) of the other group. A definite schedule of actuation or deactuation of the stationary gripper, movable gripper, and lift coils of a mechanism is required to withdraw the Rod Cluster Control Assembly attached to the mechanism. Since the four stationary gripper, movable gripper, and lift coils associated with the Rod Cluster Control Assemblies of a rod group are driven in parallel, any single failure which could cause rod withdrawal would affect a minimum of one group of Rod Cluster Control Assemblies.
Mechanical failures are in the direction of insertion, or immobility.
Figure 7.7-15 is provided for a discussion of design features that ensure that no single electrical failure could cause the accidental withdrawal of a single Rod Cluster Control Assembly from the partially inserted bank at full power operation.
Figure 7.7-15 shows the typical parallel connections on the lift, movable and stationary coils for a group of rods. Since single failures in the stationary or movable circuits will result in dropping or preventing rod (or rods) motion, the discussion of single failure will be addressed to the lift coil circuits. (1) Due to the method of wiring the pulse transformers which fire the lift coil multiplex thyristors, three of the four thyristors in a rod group could remain turned off when required to fire, if for example, the gate signal lead failed open at point X1. Upon "up" demand, one rod in group 1 and 4 rods in group 2 would withdraw. A second failure at point X2 in the group 2 circuit is required to withdraw one Rod Cluster Control Assembly; (2) timing circuit failures will affect the four mechanisms of a group or the eight mechanisms of the bank and will not cause a single rod withdrawal; (3) more than two simultaneous component failures are required (other than the open wire failures) to allow withdrawal of a single rod.
The identified multiple failure involving the least number of components consists of open circuit failure of the proper two out of sixteen wires connected to the gate of the lift coil thyristors. The probability of open wire (or terminal) failure is 0.016x10-6 per hour by MIL-HDB-217A. These wire failures would have to be accompanied by failure, or disregard, of the indications mentioned above. The probability of this occurrence is therefore too low to have any significance.
Concerning the human element, to erroneously withdraw a single Rod Cluster Control Assembly, the operator would have to improperly set the bank selector switch, the lift coil disconnect switches, and the in-hold out switch. In addition, the three indications would have to be disregarded or ineffective. Such series of errors would require a complete lack of understanding and administrative control. A probability number cannot be assigned to a series of errors such as these.
 
SEABROOK                        INSTRUMENTATION AND CONTROLS                        Revision 21 STATION                                                                            Section 7.7 Control Systems Not Required for Safety UFSAR                                                                              Page 23 The Rod Position Indication System provides direct visual displays of each control rod assembly position. The plant computer alarms for deviation of rods from their banks. In addition, a rod insertion limit monitor provides an audible and visual alarm to warn the operator of an approach to an abnormal condition due to dilution. The low-low insertion limit alarm alerts the operator to follow emergency boration procedures. The facility reactivity control systems are such that acceptable fuel damage limits will not be exceeded even in the event of a single malfunction of either system.
An important feature of the Control Rod System is that insertion is provided by gravity fall of the rods.
In all analyses involving reactor trip, the single, highest worth Rod Cluster Control Assembly is postulated to remain untripped in its full out position.
One means of detecting a stuck control rod assembly is available from the actual rod position information displayed on the control board. The control board position read-outs, one for each full length rod, give the plant operator the actual position of the rod in steps. The indications are grouped by banks (e.g., control bank A, control bank B, etc.) to indicate to the operator the deviation of one rod with respect to other rods in a bank. This serves as a means to identify rod deviation.
The plant computer monitors the actual position of all rods. Should a rod be misaligned from the other rods in that bank by more than 15 inches, the rod deviation alarm is actuated.
Misaligned Rod Cluster Control Assemblies are also detected and alarmed in the control room via the flux tilt monitoring system which is independent of the plant computer.
Isolated signals derived from the Nuclear Instrumentation System are compared with one another to determine if a preset amount of deviation of average power level has occurred. Should such a deviation occur, the comparator output will operate a bistable unit to actuate a control board annunciator. This alarm will alert the operator to a power imbalance caused by a misaligned rod.
Using individual rod position read-outs, the operator can determine the deviating control rod and take corrective action. The design of the plant control systems meets the requirements of the 1971 General Design Criteria 23.
Refer to Section 4.3 for additional information on response considerations due to reactivity.
7.7.2.3          Step Load Changes without Steam Dump The plant control system restores equilibrium conditions, without a trip, following a plus 10 percent or minus 15 percent change in load demand, over the 15 to 100 percent power range for automatic control. Steam dump is blocked for load decrease less than or equal to 15 percent.
A load demand greater than full power is prohibited by the turbine control load limit devices.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                                                                          Section 7.7 Control Systems Not Required for Safety UFSAR                                                                            Page 24 The plant control system minimizes the reactor coolant average temperature deviation during the transient within a given value and restores average temperature to the programmed setpoint.
Excessive pressurizer pressure variations are prevented by using spray and heaters and power-operated relief valves in the pressurizer.
The control system must limit nuclear power overshoot to acceptable values following a 10 percent increase in load to 100 percent.
7.7.2.4        Loading and Unloading Ramp loading and unloading of 5 percent per minute can be accepted over the 15 to 100 percent power range under automatic control without tripping the plant. The function of the control system is to maintain the coolant average temperature as a function of turbine-generator load.
The coolant average temperature increases during loading and causes a continuous insurge to the pressurizer as a result of coolant expansion. The sprays limit the resulting pressure increase.
Conversely, as the coolant average temperature is decreasing during unloading, there is a continuous outsurge from the pressurizer resulting from coolant contraction. The pressurizer heaters limit the resulting system pressure decrease. The pressurizer water level is programmed so that the water level is above the setpoint for heater cut out during the loading and unloading transients. The primary concern during loading is to limit the overshoot in nuclear power and to provide sufficient margin in the Overtemperature T setpoint.
The automatic load controls are designed to adjust the unit generation to match load requirements within the limits of the unit capability and licensed rating. During rapid loading transients, a drop in reactor coolant temperature is sometimes used to increase core power. This mode of operation is applied when the control rods are not inserted deeply enough into the core to supply all the reactivity requirements of the rapid load increase (the boron control system is relatively ineffective for rapid power changes). The reduction in temperature is initiated by continued turbine loading past the point where the control rods are completely withdrawn from the core. The temperature drop is recovered and nominal conditions restored by a boron dilution operation.
Excessive drops in coolant temperature are prevented by interlock C-16. This interlock circuit monitors the auctioneered low coolant temperature indications and the programmed reference temperature which is a function of turbine impulse pressure and causes a turbine loading stop when the decreased temperature reaches the setpoints.
The core axial power distribution is controlled during the reduced temperature return to power by placing the control rods in the manual mode when the  operating limits are approached.
Placing the rods in manual will stop further changes in , and it will also initiate the required drop in coolant temperature. Normally power distribution control is not required during a rapid power increase and the rods will proceed, under the automatic Rod Control System, to the top of the core. The bite position is re-established at the end of the transient by decreasing the coolant boron concentration.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                                                                          Section 7.7 Control Systems Not Required for Safety UFSAR                                                                            Page 25 7.7.2.5          Load Rejection Furnished by Steam Dump System When a load rejection occurs, if the difference between the required temperature setpoint of the Reactor Coolant System and the actual average temperature exceeds a predetermined amount, a signal will actuate the steam dump to maintain the reactor coolant system temperature within control range until a new equilibrium condition is reached.
The reactor power is reduced at a rate consistent with the capability of the Rod Control System.
Reduction of the reactor power is automatic. The steam dump flow reduction is as fast as Rod Cluster Control Assemblies are capable of inserting negative reactivity.
The Rod Control System can then reduce the reactor coolant temperature to a new equilibrium value without causing overtemperature and/or overpressure conditions. The nominal steam dump steam flow capacity is 40 percent of full load steam flow at full-load steam pressure.
The steam dump flow reduces proportionally as the control rods act to reduce the average coolant temperature. The artificial load is therefore removed as the coolant average temperature is restored to its programmed equilibrium value.
The dump valves are modulated by the reactor coolant average temperature signal. The required number of steam dump valves can be tripped quickly to stroke full open or modulate, depending upon the magnitude of the temperature error signal resulting from loss of load.
7.7.2.6          Turbine-Generator Trip with Reactor Trip Whenever the turbine-generator unit trips at an operating power level above the P-9 setpoint, the reactor also trips. The unit is operated with a programmed average temperature as a function of load, with the full load average temperature significantly greater than the equivalent saturation pressure of the steam generator safety valve setpoint. The thermal capacity of the Reactor Coolant System is greater than that of the secondary system, and because the full load average temperature is greater than the no load temperature, a heat sink is required to remove heat stored in the reactor coolant to prevent actuation of steam generator safety valves for a trip from full power. This heat sink is provided by the combination of controlled release of steam to the condenser and by makeup of feedwater to the steam generators.
The Steam Dump System is controlled from the reactor coolant average temperature signal whose setpoint values are programmed as a function of turbine load. Actuation of the steam dump is rapid to prevent actuation of the steam generator safety valves. With the dump valves open, the average coolant temperature starts to reduce quickly to the no load setpoint. A direct feedback of temperature acts to proportionally close the valves to minimize the total amount of steam which is bypassed.
The feedwater flow is cut off following reactor trip when the average coolant temperature decreases below a given temperature or when the steam generator water level reaches a given high level.
 
SEABROOK                      INSTRUMENTATION AND CONTROLS                      Revision 21 STATION                                                                          Section 7.7 Control Systems Not Required for Safety UFSAR                                                                            Page 26 Additional feedwater makeup is then controlled manually to restore and maintain steam generator water level while assuring that the reactor coolant temperature is at the desired value.
Residual heat removal is maintained by the steam header pressure controller (manually selected) which controls the amount of steam flow to the condensers. This controller operates a portion of the same steam dump valves to the condensers which are used during the initial transient following turbine and reactor trip.
The pressurizer pressure and level fall rapidly during the transient because of coolant contraction. The pressurizer water level is programmed so that the level following the turbine and reactor trip is above the heaters. However, if the heaters become uncovered following the trip, they are turned off and the Chemical and Volume Control System will provide full charging flow to restore water level in the pressurizer. Heaters are then turned on to restore pressurizer pressure to normal.
The Steam Dump and Feedwater Control Systems are designed to prevent the average coolant temperature from falling below the programmed no-load temperature following the trip to ensure adequate reactivity shutdown margin.
7.7.3            References
: 1.      Lipchak, J.B. and Stokes, R.A., "Nuclear Instrumentation System," WCAP-8255, January 1974 (for background information only).
: 2.      Gorski, Joseph P., "Seabrook Station Unit 1 Fixed Incore Detector System Analysis," YAEC-1855PA, October 1992.
: 3.      Shopsky, W.E., "Failure Mode and Effects Analysis (FMEA) of the Solid State Full Length Rod Control System," WCAP-8976.
: 4.      Gorski, Joseph P., "Seabrook Station Fixed Incore Detector System Extended Operation," YAEC 1931, February 1996.
: 5.      ANP-3243P, "Seabrook Station Unit 1 Fixed Incore Detector System Analysis Supplement to YAEC-1855PA," Revision 1, May 2014.
 
Seabrook                  INSTRUMENTATION AND CONTROLS                      Revision 21 Station          Deviations Of AMI Variables From Reg. Guide 1.97/          Appendix 7A UFSAR                UFSAR Subsection 7.5.4.4 Design Criteria              Page 7A-1 Regulatory Guide 1.97, Revision 3 Review APPENDIX 7A DEVIATIONS AND JUSTIFICATIONS List Of Deviations And Variables Deviation Number  Variable                                                            Page 1    Steam Generator Pressure                                            7A-3 2    Pressurizer Level                                                    7A-4 3    RWST Level                                                          7A-5 4    Containment Hydrogen Concentration                                  7A-6 5    RCS Soluble Boron Concentration                                      7A-7 6    RCS Hot Leg Water Temperature                                        7A-8 7    RCS Cold Leg Water Temperature                                      7A-9 8    Radiation Level in Circulating Primary Coolant                      7A-10 9    Effluent Radioactivity - Noble Gases (Inside buildings or areas      7A-11 where penetrations or hatches are located) 10    Accumulator Tank Level                                              7A-12 11    Accumulator Tank Pressure                                            7A-13 12    Pressurizer Relief Tank Temperature (Quench Tank)                    7A-14 13    Containment Spray Flow                                              7A-15 14    Containment Atmosphere Temperature                                  7A-16 15    Containment Sump Water Temperature                                  7A-17 16    Makeup Flow-In                                                      7A-18 17    Letdown Flow-Out                                                    7A-19 18    Volume Control Tank Level                                            7A-20 19    Component Cooling Water Temperature                                  7A-21
 
Seabrook                      INSTRUMENTATION AND CONTROLS                        Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/          Appendix 7A UFSAR                    UFSAR Subsection 7.5.4.4 Design Criteria                Page 7A-2 Regulatory Guide 1.97, Revision 3 Review List Of Deviations And Variables Deviation Number        Variable                                                              Page 20          High-Level Radioactive Liquid Tank Level                              7A-22 21          Dissolved Oxygen in Primary Coolant (Grab Sample)                    7A-23 22          RHR Heat Exchanger Outlet Temperature                                7A-24 23          Containment Drainage Sump Water Level                                7A-25 24          (Not Used)                                                            7A-26 25          Heat Removal by the Containment Fan Heat Removal System              7A-27 26          Radioactive Gas Holdup Tank Pressure                                  7A-28 27          Boric Acid Charging Flow (Emergency Boration Flow)                    7A-29 28          Wind Direction                                                        7A-30 29          Wind Speed                                                            7A-31 30          Control Room Temperature                                              7A-32 Deviations And Justifications Appendix 7A contains a listing of all Accident Monitoring Instrumentation (AMI) variables that have deviations from the design criteria stated in Subsection 7.5.4.4 or the recommendations in Regulatory Guide 1.97. The "Data Table" headings in Appendix 7A refer to Table 7.5-1 items.
AMI variables not included in Appendix 7A have no deviations from the above criteria.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                      Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/          Appendix 7A UFSAR                      UFSAR Subsection 7.5.4.4 Design Criteria              Page 7A-3 Regulatory Guide 1.97, Revision 3 Review Deviation No. 1 Data Table Variable                                                                              Item No.
Steam Generator Pressure                                                              A2, D18 Deviation From Regulatory Guide 1.97 Guidance The range deviates from the recommended range for Type D variable.
Actual range is 0-1300 psig, versus 0-1425 psig recommended (based on 20 percent margin above lowest safety valve setpoint-1185 psig).
Justification The range of the installed instruments extends beyond the lowest safety valve setting with a margin of approximately 10 percent. This range envelops the highest safety valve setting (1255 psig). Therefore, the existing range is adequate to monitor the expected steam generator pressures.
In addition to these instruments, nonqualified main steam pressure indication with a range of 0-1500 psig for each steam generator is available at the MCB. This envelops the recommended range of 0-1425 psig. The transmitters are MS-PT-3001, 3002, 3003, 3004.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                      Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/        Appendix 7A UFSAR                      UFSAR Subsection 7.5.4.4 Design Criteria            Page 7A-4 Regulatory Guide 1.97, Revision 3 Review Deviation No. 2 Data Table Variable                                                                            Item No.
Pressurizer Level                                                                    A5, D12 Deviation From Regulatory Guide 1.97 Guidance Actual range is 61.75"-581.25" above the bottom reference versus a recommended range from the bottom to the top.
Justification This range covers from approximately 10 percent to 94 percent of the pressurizer volume and is sufficient for the required monitoring function.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                    Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/          Appendix 7A UFSAR                      UFSAR Subsection 7.5.4.4 Design Criteria            Page 7A-5 Regulatory Guide 1.97, Revision 3 Review Deviation No. 3 Data Table Variable                                                                              Item No.
RWST Level                                                                              A6 Deviation From Regulatory Guide 1.97 Guidance The actual range starts at 22,000 gallons versus the recommended range starting at the bottom of the tank.
Justification The indicated range measures the usable volume of the RWST and is adequate for the required monitoring function.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                        Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/            Appendix 7A UFSAR                    UFSAR Subsection 7.5.4.4 Design Criteria                Page 7A-6 Regulatory Guide 1.97, Revision 3 Review Deviation No. 4 Data Table Variable                                                                                Item No.
Containment Hydrogen Concentration                                                        C10 Deviation From Regulatory Guide 1.97 Guidance
: 1.      Continuous indication is not provided since the hydrogen analyzer is normally isolated from the Containment.
: 2.      Containment hydrogen concentration is classified as a Design Category 3 variable as opposed to Design Category 1 in Regulatory Guide 1.97.
Justification
: 1.      The hydrogen analyzer is normally in the "Standby" mode to preclude a long warm-up time. The analyzer can be operational within 30 minutes of the initiation of an SI signal.
Since hydrogen buildup is a slow process and sufficient time is available to put the analyzer into operation, continuous indication is not required during power operation.
: 2.      The Nuclear Regulatory Commission (NRC) is amending its regulations for combustible gas control systems. The revised regulatory requirements and guidance are addressed within the NRC Notice of Availability published on September 25, 2003 (68 FR 55416),
Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler TSTF-447, "Elimination of Hydrogen Recombiners and Change to Hydrogen and Oxygen Monitors," and the documentation associated with the 10 CFR 50.44 rulemaking. The amended regulations concluded that the hydrogen release from a design basis LOCA is not risk significant and therefore the Regulatory Guide 1.97 design requirements for hydrogen monitoring can be relaxed from Category 1 to Category 3 as defined in Regulatory Guide 1.97.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                        Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/            Appendix 7A UFSAR                    UFSAR Subsection 7.5.4.4 Design Criteria                Page 7A-7 Regulatory Guide 1.97, Revision 3 Review Deviation No. 5 Data Table Variable                                                                                Item No.
RCS Soluble Boron Concentration                                                            B3 Deviation From Regulatory Guide 1.97 Guidance This variable is not considered AMI.
Justification Under accident conditions, determination of boron concentration will be made by analysis of samples obtained via the post-accident sample panel. Analysis capability is available to envelop the recommended range of 0-6000 ppm boron. The Seabrook-specific ERPs do not require that the operating crew monitor this variable with online instrumentation; therefore, it is not considered AMI.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                        Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/            Appendix 7A UFSAR                    UFSAR Subsection 7.5.4.4 Design Criteria                Page 7A-8 Regulatory Guide 1.97, Revision 3 Review Deviation No. 6 Data Table Variable                                                                                Item No.
RCS Hot Leg Water Temperature                                                              B5 Deviations From Regulator Guide 1.97 Guidance All four channels (indication and recording) are powered from the same power supply.
Justification The hot leg RTDs provide the primary temperature measurement for each hot leg. Diverse measurement is provided by the core exit thermocouples. The core exit thermocouples are redundant, thereby assuring the availability of this indication in the event UPS-I-1A is lost.
 
Seabrook                        INSTRUMENTATION AND CONTROLS                    Revision 21 Station                Deviations Of AMI Variables From Reg. Guide 1.97/        Appendix 7A UFSAR                      UFSAR Subsection 7.5.4.4 Design Criteria            Page 7A-9 Regulatory Guide 1.97, Revision 3 Review Deviation No. 7 Data Table Variable                                                                              Item No.
RCS Cold Leg Water Temperature                                                          B4, B6 Deviation From Regulatory Guide 1.97 Guidance All channels (indication and recording) are powered from the same power supply.
Justification The cold leg RTDs provide the primary temperature measurement for each cold leg. Diverse measurement is provided by the steam generator pressure channels. The Westinghouse Nuclear Steam Supply System is designed so that the cold leg temperature approximates the saturation temperature corresponding to secondary pressure. It has been confirmed that there would be only a small variance between the actual cold leg temperature and the saturation temperature corresponding to steamline pressure during cooldown to cold shutdown.1 This correlation has been verified during actual plant operations.
The steam generator pressure channels (Item No. A2) are redundant, thereby assuring the availability of this indication in the event power to the cold leg RTDs is lost.
: 1.      Letter from J. J. Sheppard, Westinghouse Owner's Group to D. G. Eisenhut, U.S. Nuclear Regulatory Commission, OG-94 (revised), dated June 14, 1983.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                      Revision 21 Station                Deviations Of AMI Variables From Reg. Guide 1.97/        Appendix 7A UFSAR                      UFSAR Subsection 7.5.4.4 Design Criteria            Page 7A-10 Regulatory Guide 1.97, Revision 3 Review Deviation No. 8 Data Table Variable                                                                              Item No.
Radiation Level in Circulating Primary Coolant                                          C2 Deviation From Regulatory Guide 1.97 Guidance This variable is not considered AMI.
Justification The post-accident sampling system and analysis will be used to obtain measurements of the radiation levels in the primary coolant loops to satisfy ERP requirements. The Seabrook-specific ERPs do not require that the operating crew monitor this variable with online instrumentation; therefore, it is not considered AMI.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                      Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/          Appendix 7A UFSAR                      UFSAR Subsection 7.5.4.4 Design Criteria              Page 7A-11 Regulatory Guide 1.97, Revision 3 Review Deviation No. 9 Data Table Variable                                                                              Item No.
Effluent Radioactivity - Noble Gases                                                      C13 (Inside buildings or areas where penetrations or hatches are located)
Deviation From Regulatory Guide 1.97 Guidance The installed range, 101 to 106 CPM (corresponding to 6x10-4 to 101 Ci/cc), does not envelope the recommended range (10-6 to 103 Ci/cc). This variable is classified as Design Category 3 instead of Design Category 2 as recommended in Regulatory Guide 1.97.
Justification The containment structure and all penetration/hatch areas are surrounded by the Containment Enclosure Building. The exhaust from the Containment Enclosure Building is monitored for gross activity. The Containment Enclosure Building exhaust is routed to the main plant vent stack, where it is monitored (10-7-105 Ci/cc) prior to discharge.
The Main Plant Vent Stack Monitor (Table 7.5-1, Item E7) monitors all releases to the atmosphere that may result from design basis accident events. The Containment Enclosure Monitor is a backup to the Main Plant Vent Stack Monitor to assist the operators in identifying the source of the release. Both the Main Plant Vent Stack Monitor and the Containment Enclosure Monitor provide indication of containment breach, which is the purpose, identified in Regulatory Guide 1.97. Backup Type C variables are considered to be Design Category 3.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                            Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/                Appendix 7A UFSAR                      UFSAR Subsection 7.5.4.4 Design Criteria                    Page 7A-12 Regulatory Guide 1.97, Revision 3 Review Deviation No. 10 Data Table Variable                                                                                    Item No.
Accumulator Tank Level                                                                        D3 Deviation From Regulatory Guide 1.97 Guidance This variable is not considered AMI.
Justification The primary function of these indications is to assure adequate volume in the accumulators prior to any transient requiring injection. This indication, in conjunction with accumulator tank pressure and outlet isolation valve position indication, will ensure that these accumulators are capable of performing their safety function which is to inject water into the cold legs upon major depressurization of the RCS.
Assuming that the isolation valves are open, there is no action that the operating crew can take in an accident situation if these accumulators do not perform their intended safety function.
Therefore, this instrumentation does not have to be designed for accident-monitoring service.
The only operator action relative to the accumulators in an accident situation is to isolate them.
The instrumentation used to make this determination is RCS hot leg temperature and RCS subcooling. If RCS subcooling is greater than 80°F and RCS hot leg temperature is less than 400°F, then the operator is directed to isolate the accumulator. This action occurs whether or not the accumulator has discharged. The successful completion of this step requires monitoring the position of the isolation valves. If an isolation valve fails to fully close, then the operator is directed to vent the unisolated accumulator by opening the vent valves. An open vent valve is sufficient to determine successful completion of this step.
The Seabrook-specific ERPs do not require that the operating crew monitor accumulator level in an emergency; therefore, it is not considered AMI.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                      Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/          Appendix 7A UFSAR                    UFSAR Subsection 7.5.4.4 Design Criteria              Page 7A-13 Regulatory Guide 1.97, Revision 3 Review Deviation No. 11 Data Table Variable                                                                              Item No.
Accumulator Tank Pressure                                                                D4 Deviation From Regulatory Guide 1.97 Guidance The accumulator tank pressure range deviates from the recommended range of 0 to 750 psig.
Justification The actual range of 0 to 700 psig is adequate to monitor the expected values of accumulator pressure. At the maximum allowable value, the indicator reading will be slightly less than 95 percent of full scale.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                      Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/          Appendix 7A UFSAR                    UFSAR Subsection 7.5.4.4 Design Criteria              Page 7A-14 Regulatory Guide 1.97, Revision 3 Review Deviation No. 12 Data Table Variable                                                                                Item No.
Pressurizer Relief Tank (Quench Tank) Temperature                                          D15 Deviation From Regulatory Guide 1.97 Guidance The actual range (50-350°F) deviates from the recommended range (50-750°F).
Position This range adequately monitors the maximum Pressurizer Relief Tank (PRT) saturation temperature (338°F at the rupture disk pressure of 100 psig) during any accident that lifts the pressurizer relief valves.
 
Seabrook                        INSTRUMENTATION AND CONTROLS                      Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/            Appendix 7A UFSAR                      UFSAR Subsection 7.5.4.4 Design Criteria              Page 7A-15 Regulatory Guide 1.97, Revision 3 Review Deviation No. 13 Data Table Variable                                                                                Item No.
Containment Spray Flow                                                                    D23 (a) Containment Spray Pump Suction Pressure (b) Containment Spray Pump Discharge Pressure Deviation From Regulatory Guide 1.97 Guidance A direct indication of containment spray flow is not provided.
Justification Containment spray pump head can be determined from the containment spray pump suction and discharge pressure indications provided side by side on the MCB. The operating crews are trained in the use of this instrumentation to verify proper operation of the Containment Spray System. Quantitative determination of flow is not required to support the Seabrook-specific ERPs.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                        Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/            Appendix 7A UFSAR                    UFSAR Subsection 7.5.4.4 Design Criteria                Page 7A-16 Regulatory Guide 1.97, Revision 3 Review Deviation No. 14 Data Table Variable                                                                                Item No.
Containment Atmosphere Temperature                                                        D25 Deviation From Regulatory Guide 1.97 Guidance The range of the Containment Air Temperature Monitoring System is 50ºF to 420ºF versus the recommended range of 40ºF to 400ºF.
Justification The minimum containment air temperature will be greater than 50°F when this instrumentation is required to function (during and/or after an accident). Therefore, the range of this instrumentation is adequate for its intended monitoring function.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                      Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/          Appendix 7A UFSAR                    UFSAR Subsection 7.5.4.4 Design Criteria              Page 7A-17 Regulatory Guide 1.97, Revision 3 Review Deviation No. 15 Data Table Variable                                                                              Item No.
Containment Sump Water Temperature                                                      D26 Deviation From Regulatory Guide 1.97 Guidance Containment sump water temperature is monitored at the inlet to the containment spray heat exchanger.
Justification The net positive suction head (NPSH) calculations for the Containment Building Spray (CBS) and Residual Heat Removal (RHR) pumps assume saturation conditions in the containment sump (Seabrook UFSAR, Subsection 6.2.2.2 and 6.3.2.2). Saturation conditions result in the maximum possible sump temperature. There is no containment sump water temperature limit for RHR or CBS pump starting or operation; therefore, the temperature sensor for monitoring system performance can be located outside of the containment. The instrument located on the containment spray piping at the inlet to each CBS pump (which is located upstream of the heat exchanger) is not required for emergency response. Its function is to provide the temperature required for containment energy balance calculations and for monitoring containment spray heat exchanger performance.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                          Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/              Appendix 7A UFSAR                      UFSAR Subsection 7.5.4.4 Design Criteria                Page 7A-18 Regulatory Guide 1.97, Revision 3 Review Deviation No. 16 Data Table Variable                                                                                  Item No.
Makeup Flow-In                                                                                D27 Deviation From Regulator Guide 1.97 Guidance Makeup flow-in is classified as a Design Category 3 variable as opposed to Design Category 2 in Regulatory Guide 1.97.
Justification Normal charging and letdown is not required in the mitigation of design basis accidents. It is classified as a nonsafety system and is used to assist in recovery if it can be placed in service.
Therefore, the monitoring of charging flow is classified as Design Category 3.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                          Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/              Appendix 7A UFSAR                      UFSAR Subsection 7.5.4.4 Design Criteria                Page 7A-19 Regulatory Guide 1.97, Revision 3 Review Deviation No. 17 Data Table Variable                                                                                  Item No.
Letdown Flow-Out                                                                              D28 Deviation From Regulatory Guide 1.97 Guidance "Letdown flow-out" is classified as a Design Category 3 variable as opposed to Design Category 2 in Regulatory Guide 1.97.
Justification Normal charging and letdown is not required in the mitigation of design basis accidents. It is classified as a nonsafety system and is used to assist in recovery if it can be placed in service.
Therefore, the monitoring of letdown flow is classified as Design Category 3.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                        Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/            Appendix 7A UFSAR                      UFSAR Subsection 7.5.4.4 Design Criteria                Page 7A-20 Regulatory Guide 1.97, Revision 3 Review Deviation No. 18 Data Table Variable                                                                                Item No.
Volume Control Tank Level                                                                  D29 Deviation From Regulatory Guide 1.97 Guidance
: 1.      Volume control tank level is classified as a Design Category 3 variable as opposed to Design Category 2 in Regulatory Guide 1.97.
: 2.      The range of this measurement is 0 inches - 80 inches versus a recommended range of top to bottom (141 inches total).
Justification
: 1.      Normal charging and letdown are not required in the mitigation of design basis accidents.
If charging and letdown can be re-established, then they will be used to assist in the recovery. Therefore, the volume control tank level is not required for accident-monitoring service. It will be used only if charging and letdown are re-established. Therefore, the monitoring of Volume Control Tank Level is classified as Design Category 3.
: 2.      The level channel monitors the straight shell portion of the tank only. The hemispherical heads are not monitored, since the volume to level ratio is not linear. The range of this channel is acceptable for the intended monitoring functions.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                    Revision 21 Station            Deviations Of AMI Variables From Reg. Guide 1.97/        Appendix 7A UFSAR                    UFSAR Subsection 7.5.4.4 Design Criteria            Page 7A-21 Regulatory Guide 1.97, Revision 3 Review Deviation No. 19 Data Table Variable                                                                            Item No.
Component Cooling Water Temperature                                                    D30 Deviation From Regulatory Guide 1.97 Guidance The actual range (0°F-175°F) deviates from the recommended range (40°F-200°F).
Justification The maximum design temperature for component cooling water under accident conditions is 120°F. The actual range envelops this temperature with substantial margin. Therefore, this instrumentation is adequate for the required monitoring function.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                            Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/                Appendix 7A UFSAR                    UFSAR Subsection 7.5.4.4 Design Criteria                    Page 7A-22 Regulatory Guide 1.97, Revision 3 Review Deviation No. 20 Data Table Variable                                                                                    Item No.
High-Level Radioactive Liquid Tank Level                                                      D33 Deviation From Regulatory Guide 1.97 Guidance The range of this measurement is (0-14 feet) versus a recommended range of top to bottom of the tank (18 feet total).
Justification The range covers the top 14 feet of these tanks. The bottom section of the tank is hemispherical.
The volume-to-level ratio is not linear in this region; therefore, is not in the span of the instrument. The range is acceptable for the intended monitoring function.
 
Seabrook                        INSTRUMENTATION AND CONTROLS                      Revision 21 Station                Deviations Of AMI Variables From Reg. Guide 1.97/          Appendix 7A UFSAR                      UFSAR Subsection 7.5.4.4 Design Criteria              Page 7A-23 Regulatory Guide 1.97, Revision 3 Review Deviation No. 21 Data Table Variable                                                                                Item No.
Dissolved Oxygen in Primary Coolant (Grab Sample)                                          E18 Deviation From Regulatory Guide 1.97 Guidance The 02 concentration in the Primary Coolant System is not analyzed.
Justification NUREG-0737, Item II.B.3, Criterion (4) states that measuring 02 concentration is recommended but not mandatory. In NHY letter from J. DeVincentis to G. W. Knighton, SBN-648, dated April 16, 1984, the clarification on Criterion (4) provided by the NRC staff to NHY was restated as follows:
NRC Criterion (4) Clarification The determination of dissolved oxygen can be satisfied by analyzing a post-accident gas sample from the Reactor Coolant System for dissolved hydrogen. If the reactor coolant dissolved hydrogen concentration is greater than 10 cc/kg, the NRC considers the dissolved oxygen level to be less than 100 ppb. If the post-accident dissolved hydrogen level is less than 10 cc/kg, the NRC will require NHY to provide justification that no damage to plant systems has occurred prior to plant startup, but considers the analysis requirement for oxygen satisfied. The NHY response was as follows:
NHY Response The amount of dissolved gases in the reactor coolant will be determined by extracting a gaseous sample from the post-accident sampling panel using a shielded syringe if necessary. This sample will be analyzed for hydrogen and gamma spectrum only.
This has been accepted in the Safety Evaluation Report, Supplement 3, Section 9.3.4.3.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                          Revision 21 Station            Deviations Of AMI Variables From Reg. Guide 1.97/              Appendix 7A UFSAR                    UFSAR Subsection 7.5.4.4 Design Criteria                  Page 7A-24 Regulatory Guide 1.97, Revision 3 Review Deviation No. 22 Data Table Variable                                                                                  Item No.
RHR Heat Exchanger Outlet Temperature                                                        D2 Deviation From Regulatory Guide 1.97 Guidance The lower end of the temperature range extends down to 50°F as opposed to a recommended lower end of 40°F.
Justification The RHR heat exchangers are cooled by the Component Cooling Water System. The normal operating temperature is 85°F, automatic temperature control is provided by a safety-related temperature control loop. VAS alarms are provided should the temperature of the component cooling water drop below 65°F. This allows sufficient time for corrective action before the component cooling water temperature drops to 60°F, which is the minimum temperature for this system. Thus, the installed range is adequate since it will remain on-scale at all times.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                      Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/          Appendix 7A UFSAR                    UFSAR Subsection 7.5.4.4 Design Criteria              Page 7A-25 Regulatory Guide 1.97, Revision 3 Review Deviation No. 23 Data Table Variable                                                                              Item No.
Containment Drainage Sump Water Level                                                  B12A Deviation From Regulatory Guide 1.97 Guidance This variable is not considered AMI.
Justification Containment drainage sump water level instrumentation is provided that meets the guidance in Regulatory Guide 1.45, Reactor Coolant Pressure Boundary Leakage Detection System and NUREG-0737, Item II.F.l. The purpose of these instruments is to detect abnormal leakage into the Containment when the leakage rate is insufficient to actuate the Engineered Safety Features (Condition II events).
The Seabrook-specific ERPs do not require that the operating crew monitor this variable during a design basis accident event; therefore, it is not considered AMI.
 
Seabrook                    INSTRUMENTATION AND CONTROLS            Revision 21 Station            Deviations Of AMI Variables From Reg. Guide 1.97/ Appendix 7A UFSAR                    UFSAR Subsection 7.5.4.4 Design Criteria    Page 7A-26 Regulatory Guide 1.97, Revision 3 Review Deviation No. 24: Not used.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                        Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/            Appendix 7A UFSAR                    UFSAR Subsection 7.5.4.4 Design Criteria                Page 7A-27 Regulatory Guide 1.97, Revision 3 Review Deviation No. 25 Data Table Variable                                                                                Item No.
Heat Removal by the Containment Fan Heat Removal System                                    D24 Deviation From Regulatory Guide 1.97 Guidance This variable is not considered AMI.
Justification Operation of the containment fan/coolers is not required for the mitigation of design basis accident events. The Seabrook-specific ERPs do not require that the operating crew monitor this variable in an emergency; therefore, it is not considered AMI.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                      Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/          Appendix 7A UFSAR                    UFSAR Subsection 7.5.4.4 Design Criteria              Page 7A-28 Regulatory Guide 1.97, Revision 3 Review Deviation No. 26 Data Table Variable                                                                              Item No.
Radioactive Gas Holdup Tank Pressure                                                    D34 Deviation From Regulatory Guide 1.97 Guidance This variable is not considered AMI.
Justification Holdup of radioactive gas for decay is provided by carbon delay beds instead of pressurized storage tanks. Therefore, this variable is not applicable.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                        Revision 21 Station            Deviations Of AMI Variables From Reg. Guide 1.97/            Appendix 7A UFSAR                    UFSAR Subsection 7.5.4.4 Design Criteria                Page 7A-29 Regulatory Guide 1.97, Revision 3 Review Deviation No. 27 Data Table Variable                                                                                Item No.
Boric Acid Charging Flow (Emergency Boration Flow)                                        D6 Deviation From Regulatory Guide 1.97 Guidance Boric acid charging flow is classified as a Design Category 3 variable as opposed to Design Category 2 in Regulatory Guide 1.97.
Justification Emergency boration is not required in the mitigation of design basis accidents. The RWST provides the required volume of borated water for all design basis accidents. Emergency boration may be used to assist in the recovery, if available. Therefore, the monitoring of emergency boration flow is classified as Design Category 3.
 
Seabrook                        INSTRUMENTATION AND CONTROLS                    Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/          Appendix 7A UFSAR                      UFSAR Subsection 7.5.4.4 Design Criteria              Page 7A-30 Regulatory Guide 1.97, Revision 3 Review Deviation No. 28 Data Table Variable                                                                              Item No.
Wind Direction                                                                            E15 Deviation From Regulatory Guide 1.97 Guidance Damping ratio and delay distance are characteristic of the mechanical response for a rotational wind vane. The rotational wind vanes have been replaced by Ultrasonic Anemometers that monitor wind direction and wind speed. Mechanical response characteristic such as damping ratio and delay distance required by RG 1.97 are not applicable to Ultrasonic Anemometers.
Justification Ultrasonic Anemometers leverage the relationship between wind and sound wave propagation to detect wind speed and direction. Since Ultrasonic Anemometers have no moving parts that need to be actuated by wind force, the response to changes in wind direction is much quicker and more stable than a rotating wind vane. Mechanical response delays, which describe the dynamic and typically lagged response limit of wind vane to measure wind direction under turbulent flow, are not applicable to an Ultrasonic Anemometer.
The Seabrook Station dose assessment techniques characterize atmospheric stability as a function of lapse rate (vertical temperature difference, Item No. E17). The wind direction monitoring system is only utilized to derive average wind direction values for dose assessment purposes and the system's response to changes in wind direction do not significantly affect these values.
 
Seabrook                        INSTRUMENTATION AND CONTROLS                    Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/          Appendix 7A UFSAR                      UFSAR Subsection 7.5.4.4 Design Criteria              Page 7A-31 Regulatory Guide 1.97, Revision 3 Review Deviation No. 29 Data Table Variable                                                                              Item No.
Wind Speed                                                                                E16 Deviation From Regulatory Guide 1.97 Guidance Distance Constant is a characteristic of the mechanical response delays for cup or propeller (rotational) anemometer. The rotational Anemometers have been replaced by Ultrasonic Anemometers that monitor wind speed and wind direction. Mechanical response delays such as the distance constant required by RG 1.97 are not applicable to Ultrasonic Anemometers.
Justification Ultrasonic Anemometers leverage the relationship between wind and sound wave propagation to detect wind speed and direction. Since Ultrasonic Anemometers have no moving parts that need to be actuated by wind force, the response to changes in wind speed is much quicker than a rotating Anemometer. Mechanical response delays, which describe the dynamic and typically lagged response limit of cup anemometers to measure wind speed under turbulent flow, are not applicable to an Ultrasonic Anemometer.
The Seabrook Station dose assessment techniques characterize atmospheric stability as a function of lapse rate (vertical temperature difference, Item No. E17). The wind direction monitoring system is only utilized to derive average wind direction values for dose assessment purposes and the system's response to changes in wind direction do not significantly affect these values.
 
Seabrook                      INSTRUMENTATION AND CONTROLS                        Revision 21 Station              Deviations Of AMI Variables From Reg. Guide 1.97/            Appendix 7A UFSAR                      UFSAR Subsection 7.5.4.4 Design Criteria                Page 7A-32 Regulatory Guide 1.97, Revision 3 Review Deviation No. 30 Data Table Variable                                                                                Item No.
Control Room Temperature                                                                A9, D35j Deviation From Regulatory Guide 1.97 Guidance A deviation is taken to the requirement to provide Design Category 1, Type A AMI for this variable.
Justification Pre-planned manual operator actions are assumed to maintain control room cooling capability on failure in the safety or non-safety related control room cooling subsystem. Since manual actions are required, control room temperature would be classified as Type A, Design Category 1 variable to comply with the requirements of Regulatory Position C.1.2 of Regulatory Guide 1.97.
The basis for this deviation credits the operating crew's awareness of the control room environment and indication of control room cooling system performance via Design Category 3, Type D indicator CBA-TI-8617. Since the control room is continuously manned, high temperature conditions will be detected by the operating crew as a change in control room comfort level. Control room temperature conditions would then be confirmed using indicator CBA-TI-8617 with the necessary manual actions initiated to start the redundant safety related cooling system if necessary.
Since credit can be taken for operator awareness of the environmental conditions in the control room, deviation from Regulatory Guide 1.97 guidance is acceptable for this variable.
 
SEABROOK STATION UPDATED FINAL SAFETY ANALYSIS REPORT CHAPTER 7 INSTRUMENTATION AND CONTROLS TABLES 7.1-1    Listing of Applicable Criteria 7.2-1    List of Reactor Trips 7.2-2    Protection System Interlocks 7.2-3    Reactor Trip System Instrumentation 7.2-4    Reactor Trip Correlation 7.3-1    Engineered Safety Features Actuation System Instrumentation 7.3-2    Interlocks for Engineered Safety Features Actuation System 7.4-1    Equipment Required for Safe Shutdown 7.5-1    Accident Monitoring Instrumentation List 7.5-2    Control Room Indicators and/or Recorders Available to the Operator to Monitor Significant Plant Parameters during Normal Operation Including Operational Occurrences 7.7-1    Plant Control System
 
SEABROOK INSTRUMENTATION AND CONTROLS                                              Revision:      8 STATION                                                                TABLE 7.1-1                                            Sheet:    1 of 7 UFSAR TABLE 7.1-1        LISTING OF APPLICABLE CRITERIA Criteria                                              Title                                            Conformance Discussed In
: 1. General Design Criteria (GDC), Appendix A to 10 CFR Part 50 GDC 1                      Quality Standards and Records                                      3.1, 7.2.2.2 GDC 2                      Design Bases for Protection Against Natural Phenomena              3.1, 7.2.1.1k, 7.2.1.2e GDC 3                      Fire Protection                                                    3.1, 7.1.2.2c GDC 4                      Environmental and Missile Design Bases                            3.1, 7.2.2.2 GDC 5                      Sharing of Structures, Systems, and Components                    3.1 GDC 10                    Reactor Design                                                    3.1, 7.2.2.2 GDC 12                    Suppression of Reactor Power Oscillations                          3.1 GDC 13                    Instrumentation and Control                                        3.1, 7.3.1, 7.3.2, 7.4, 7.7.2 GDC 15                    Reactor Coolant System Design                                      3.1, 7.2.2.2 GDC 17                    Electric Power Systems                                            3.1, 8.3.1 GDC 19                    Control Room                                                      3.1, 7.4 GDC 20                    Protection System Functions                                        3.1, 7.2.2.2, 7.3.1, 7.3.2 GDC 21                    Protection System Reliability and Testability                      3.1, 7.2.2.2, 7.3.1, 7.3.2 GDC 22                    Protection System Independence                                    3.1, 7.1.2.2, 7.2.2.2, 7.3.1, 7.3.2 GDC 23                    Protection System Failure Modes                                    3.1, 7.2.2.2, 7.3.1, 7.3.2, 7.7.2.2 GDC 24                    Separation of Protection and Control Systems                      3.1, 7.2.2.2, 7.3.1, 7.3.2,7.7.2.1 GDC 25                    Protection System Requirements for Reactivity Control Malfunctions 3.1, 7.7.2.2 GDC 26                    Reactivity Control System Redundancy and Capability                3.1 GDC 27                    Combined Reactivity Control Systems Capability                    3.1
 
SEABROOK INSTRUMENTATION AND CONTROLS                                            Revision:          8 STATION                                                                  TABLE 7.1-1                                            Sheet:        2 of 7 UFSAR Criteria                                                Title                                                Conformance Discussed In GDC 28                        Reactivity Limits                                                    3.1 GDC 29                        Protection Against Anticipated Operational Occurrences                3.1, 7.2.2.2 GDC 33                        Reactor Coolant Makeup                                                3.1 GDC 34                        Residual Heat Removal                                                3.1, 7.4 GDC 35                        Emergency Core Cooling                                                3.1, 7.3.1, 7.3.2, 7.4 GDC 37                        Testing of Emergency Core Cooling System                              3.1, 7.3.2 GDC 38                        Containment Heat Removal                                              3.1, 7.3.1, 7.3.2, 7.4 GDC 40                        Testing of Containment Heat Removal System                            3.1, 7.3.2 GDC 41                        Containment Atmosphere Cleanup                                        3.1, 6.5.1 GDC 43                        Testing of Containment Atmosphere Cleanup Systems                    3.1, 7.3.2 GDC 44                        Cooling Water                                                        3.1 GDC 46                        Testing of Cooling Water System                                      3.1, 7.3.2 GDC 50                        Containment Design Basis                                              3.1 GDC 54                        Piping Systems Penetrating Containment                                3.1 GDC 55                        Reactor Coolant Pressure Boundary Penetrating Containment            3.1 GDC 56                        Primary Containment Isolation                                        3.1, 7.3.1.1 GDC 57                        Closed Systems Isolation Valves                                      3.1
: 2. Institute of Electrical and Electronics Engineers (IEEE) Standards:
IEEE Std 279-1971            Criteria for Protection Systems for Nuclear Power Generating Stations 7.1, 7.2, 7.3, 7.6, 7.4 (ANSI N42.7-1972)
IEEE Std 308-1974            Criteria for Class 1E Electric Systems for Nuclear Power Generating  8.1, 8.3 Stations
 
SEABROOK INSTRUMENTATION AND CONTROLS                                            Revision:          8 STATION                                                          TABLE 7.1-1                                          Sheet:        3 of 7 UFSAR Criteria                                        Title                                              Conformance Discussed In IEEE Std 317-1972  Electric Penetration Assemblies in Containment Structures for Nuclear  8.1, 7.1.2.9 Power Generating Stations IEEE Std 323-1974  IEEE Standard for Qualifying Class 1E Equipment for Nuclear Power      3.11, 1.8, (RG 1.89)
Generating Stations IEEE Std 334-1971  Type Tests of Continuous-Duty Class I Motors Installed Inside the      1.8, (RG 1.40)
Containment of Nuclear Power Generating Stations IEEE Std 336-1971  Installation, Inspection and Testing Requirements for Instrumentation  7.1.2.10 (ANSI N45.2.4-1972) and Electric Equipment During the Construction of Nuclear Power Generating Stations IEEE Std 338-1975  Criteria for the Periodic Testing of Nuclear Power Generating Station  7.1.2.11 Protection Systems IEEE Std 344-1975  Guide for Seismic Qualification of Class I Electrical Equipment for    3.10 (ANSI N41.7)        Nuclear Power Generating Stations IEEE Std 379-1972  Guide for the Application of the Single Failure Criterion to Nuclear    7.1.2.7 (ANSI N41.2)        Power Generating Station Protection Systems IEEE Std 381-1977  Type Tests of Class IE Modules Used in Nuclear Power Generating        3.11 Stations IEEE Std 382-1972  Type Test of Class I Electric Valve Operators                          3.11 IEEE Std 383-1974  Standard for Type Test of Class IE Electronic Cables, Field Splices and 3.11 Connections for Nuclear Power Generating Stations IEEE Std 384-1974  Criteria for Separation of Class IE Equipment and Circuits              7.1.2.2a (ANSI N41.14)
IEEE Std 420-1973  Trial Use Guide for Class IE Control Switchboards for Nuclear Power    7.1.2.2b Generating Stations
 
SEABROOK INSTRUMENTATION AND CONTROLS                                              Revision:        8 STATION                                                                TABLE 7.1-1                                            Sheet:      4 of 7 UFSAR Criteria                                            Title                                              Conformance Discussed In
: 3. Regulatory Guides (RG)
RG 1.6                    Independence Between Redundant Standby (Onsite) Power Sources and    8.3 Between Their Distribution System RG 1.7                    Control of Combustible Gas Concentrations in Containment Following a 1.8 Loss-of-Coolant Accident RG 1.11                  Instrument Lines Penetrating Primary Reactor Containment            1.8, 6.2.4.1d, 6.2.4.2m, 7.3.1.1b, 7.1.2.2a RG 1.12                  Instrumentation for Earthquakes                                      1.8 RG 1.22                  Periodic Testing of Protection System Actuation Functions            1.8, 7.1.2.5, 7.3.2.2e, 7.4 RG 1.29                  Seismic Design Classification                                        1.8 RG 1.30                  Quality Assurance Requirements for the Installation, Inspection, and 1.8, Chapter 17 Testing of Instrumentation and Electric Equipment RG 1.32                  Criteria for Safety-Related Electric Power Systems for Nuclear Power 1.8, 8.1 Plants RG 1.40                  Qualification Tests of Continuous Duty Motors Installed Inside the  1.8, 3.1 Containment of Water Cooled Nuclear Power Plants RG 1.45                  Reactor Coolant Pressure Boundary Leakage Detection Systems          1.8 RG 1.47                  Bypassed and Inoperable Status Indication for Nuclear Power Plant    1.8, 7.1.2.6, 7.4 Safety Systems RG 1.53                  Application of the Single-Failure Criterion to Nuclear Power Plant  7.1.2.7, 1.8, 7.4 Protection Systems RG 1.62                  Manual Initiation of Protection Actions                              1.8, 7.3.2.2g, 7.2, 7.4, 7.6 RG 1.63                  Electric Penetration Assemblies in Containment Structures for        1.8, 8.1 Water-Cooled Nuclear Power Plants RG 1.67                  Installation of Overpressure Protection Devices                      1.8
 
SEABROOK INSTRUMENTATION AND CONTROLS                                              Revision:          8 STATION                                                      TABLE 7.1-1                                          Sheet:        5 of 7 UFSAR Criteria                                    Title                                                Conformance Discussed In RG 1.68          Preoperational and Initial Startup Test Programs for Water-Cooled      1.8, 14.2.6, 7.4 Power Reactors RG 1.70          Standard Format and Content in Safety Analysis Reports for Nuclear    1.8 Power Plants, Rev. 3.
RG 1.73          Qualification Test of Electric Valve Operators Installed Inside the    1.8, 8.1 Containment RG 1.75          Physical Independence of Electric Systems                              1.8, 7.1.2.2a, 8.1, 7.4 RG 1.78          Assumptions for Evaluating the Habitability of a Nuclear Power Plant  1.8 Control Room during a Postulated Hazardous Chemical Release RG 1.80          Preoperational Testing of Instrument Air                              1.8 RG 1.89          Qualification of Class IE Equipment for Nuclear Power Plants          1.8, 3.11 RG 1.95          Protection of Nuclear Power Plant Control Room Operators Against an    1.8 Accidental Chlorine Release RG 1.96          Design of Main Steam Isolation Valve Leakage Control System for        Not Applicable Boiling Water Reactor Nuclear Power Plants RG 1.97          Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess  1.8, 7.5 Plant Conditions During and Following an Accident RG 1.100        Seismic Qualification of Electric Equipment for Nuclear Power Plants  1.8, 3.10 RG 1.105        Instrument Spans and Setpoints                                        1.8, 7.1.2.1 RG 1.106        Thermal Overload Protection for Electric Motors on Motor-Operated      1.8, 8.1 Valves RG 1.108        Periodic Testing of Diesel Generators Used as Onsite Electric Power    1.8, 8.1 System t Nuclear Power Plants RG 1.118        Periodic Testing of Electric Power and Protection Systems 1.8, 7.1.2.1
 
SEABROOK INSTRUMENTATION AND CONTROLS                                                Revision:            8 STATION                                                              TABLE 7.1-1                                                  Sheet:        6 of 7 UFSAR Criteria                                              Title                                                Conformance Discussed In RG 1.120                  Fire Protection Guidelines for Nuclear Power Plants                    1.8 RG 1.141                  Containment Isolation Provisions for Fluid Systems 1.8, 6.2.4.1d, 6.2.4.2m, ,.1.2.2a, 7.3.1.1b RG 1.151                  Instrument Sensing Lines                                              1.8, 3.2.2.2, 7.1.2.2, 7.1.2.3, 7.1.2.12, 7.7
: 4. Branch Technical Positions (BTP) EICSB BTP EICSB 1                Backfitting of the Protection and Emergency Power Systems of Nuclear  7.0, 8.0 BTP EICSB 3                Isolation of Low Pressure Systems from the High Pressure Reactor      7.6.2 Coolant System BTP EICSB 4                Requirements on Motor-Operated Valves in the ECCS Accumulator          7.6.4 Lines BTP EICSB 5                Scram Breaker Test Requirements -Technical Specifications              7.2.2.2c (Item 10),NUREG 1386 (Technical Specifications Seabrook Station, Unit 1)
BTP EICSB 9                Definition and Use of "Channel Calibration" - Technical Specifications NUREG 1386 (Technical Specifications Seabrook Station, Unit 1)
BTP EICSB 10              Electrical and Mechanical Equipment Seismic Qualification Program      3.10 BTP EICSB 12              Protection System Trip Point changes for Operation with Reactor        7.2.2.2a NUREG 1386 (Technical Specifications Seabrook Coolant Pumps Out of Service                                          Station, Unit 1)
BTP EICSB 13              Design Criteria for Auxiliary Feedwater Systems                        7.3.2.3 BTP EICSB 14              Spurious Withdrawals of Single Control Rods in Pressurized Water      7.7.2.2, 15.2.1, 15.2.2, 15.3.6 Reactors BTP EICSB 15              Reactor Coolant Pump Breaker Qualification                            3.10, 7.1.2.5, 7.2.1.1b BTP EICSB 16              Control Element Assembly (CEA) Interlocks in Combustion Engineering    Not Applicable Reactors
 
SEABROOK INSTRUMENTATION AND CONTROLS                                              Revision:          8 STATION                                                              TABLE 7.1-1                                          Sheet:        7 of 7 UFSAR Criteria                                          Title                                                Conformance Discussed In BTP EICSB 18          Application of the Single Failure Criteria to Manually-Controlled      7.6.9 Electrically-Operated Valves BTP EICSB 19          Acceptability of Design Criteria for Hydrogen Mixing and Drywell      Not Applicable Vacuum Relief Systems BTP EICSB 20          Design of Instrumentation and Controls Provided to Accomplish          7.6.5, 6.3.2.2b, 6.3-7 Changeover from Injection to Recirculation Mode BTP EICSB 21          Guidance for Application of Reg. Guide 1.47                            7.1.2.6 BTP EICSB 22          Guidance for Application of Reg. Guide 1.22                            7.1.2.5 BTP EICSB 23          Qualification of Safety-Related Display Instrumentation for            7.5 Post-Accident Condition Monitoring and Safe Shutdown BTP EICSB 24          Testing of Reactor Trip System and Engineered Safety Feature Actuation 7.1.2.11 System Sensor Response Times BTP EICSB 25          Guidance for the Interpretation of General Design Criterion 37 for    3.1 Testing the Operability of the Emergency Core Cooling System as a Whole BTP EICSB 26          Requirements for Reactor Protection System Anticipatory Trips          7.2.1.1b BTP EICSB 27          Design Criteria for Thermal Overload Protection for Motors of          8.3.1 Motor-Operated Valves
: 5. Federal Regulations 10 CFR 50.62          Requirements for Reduction of Risk From Anticipated Transients        7.6.12 Without Scram (ATWS) Events for Light-Water-Cooled Nuclear Power Plants
 
SEABROOK INSTRUMENTATION AND CONTROLS                              Revision:                    9 STATION                                      TABLE 7.2-1                              Sheet:                  1 of 2 UFSAR TABLE 7.2-1            LIST OF REACTOR TRIPS Coincidence Reactor Trip                  Logic              Interlocks                        Comments
: 1. High neutron flux                  2/4        Manual block of low      High and low setting; manual block and (Power Range)                                  setting permitted by P-10 automatic reset of low setting by P10
: 2. Intermediate range neutron          1/2        Manual block permitted    Manual block and automatic reset flux                                          by P-10
: 3. Source range neutron flux          1/2        Manual block permitted    Manual block and automatic reset.
by P-6, interlocked with  Automatic block above P-10 P-10
: 4. Power range high positive          2/4        No interlocks neutron flux rate
: 5. Deleted
: 6. Overtemperature T                  2/4        No interlocks (Lead/lag compensated)
: 7. Overpower T (Lead/lag              2/4        No interlocks compensated)
: 8. Pressurizer low pressure            2/4        Interlocked with P-7      Blocked below P-7 (Lead/lag compensated)
: 9. Pressurizer high pressure          2/4        No interlocks
: 10. Pressurizer high water level        2/3        Interlocked with P-7      Blocked below P-7
: 11. Low reactor cool ant flow    2/3 in any loop  Interlocked with P-8      Low flow in one loop will cause a reactor trip when above P-8 2/3 in any loop  Interlocked with P-7      Low flow in two loops will cause a reactor trip when above P-7.
Blocked below P-7.
: 12. Reactor coolant pump        1/2 on both buses Interlocked with P-7      Low voltage on 1/2 pump motors on both undervoltage                                                            buses will cause a reactor trip.
Reactor trip blocked below P-7.
: 13. Reactor coolant pump            1/2 on both    Interlocked with P-7      Underfrequency on 1/2 pump motors on under- frequency                                                        both buses will trip all reactor coolant pump breakers and cause reactor trip; reactor trip blocked below P-7.
: 14. Low-low steam generator      2/4 in any loop  No interlocks water level
: 15. Safety injection signal            None        No interlocks            (See Section 7.3 for Engineered Safety Features actuation conditions)
: 16. Turbine trip (Anticipatory) a) Low trip fluid pressure          2/3        Interlocked with P-9      Blocked below P-9 b) Turbine stop valve close        4/4        Interlocked with P-9      Blocked below P-9
 
SEABROOK INSTRUMENTATION AND CONTROLS                  Revision:                      9 STATION                            TABLE 7.2-1                      Sheet:                  2 of 2 UFSAR Coincidence Reactor Trip        Logic            Interlocks                Comments
: 17. Manual                    1/2      No interlock
: 18. General Warning          2/2      No interlock      General warning alarm on both trains of the Solid-State Protection System at the same time will cause a reactor trip.
 
SEABROOK INSTRUMENTATION AND CONTROLS                            Revision:                8 STATION                                  TABLE 7.2-2                            Sheet:              1 of 1 UFSAR TABLE 7.2-2        I POWER ESCALATION PERMISSIVES Designation                  Derivation                                      Function II Power Escalation Permissives P-6          Presence of P-6: 1/2 neutron flux          Allows manual block of source range reactor trip (intermediate range) above setpoint        Defeats the block of source range reactor trip Absence of P-6: 2/2 neutron flux (intermediate range) below setpoint P-10        Presence of P-10: 2/4 neutron flux (power  Allows manual block of power range (low range) above set point                    setpoint) reactor trip Allows manual block of inter-mediate range reactor trip and intermediate range rod stops (C-1)
Blocks source range reactor trip Absence of P-10: 3/4 neutron flux (power  Input to P-7 range) below set point                    Defeats the block of power range (low setpoint) reactor trip Defeats the block of inter-mediate range reactor trip and intermediate range rod stops (C-1)
II Blocks Of Reactor Trips P-7          Absence of P-7: 3/4 neutron flux (power    Blocks reactor trip on: Low reactor coolant flow range) below set point (from P-10) and 2/2 in more than one loop, undervoltage, turbine impulse chamber pressure below    underfrequency, pressurizer low pressure, and setpoint (from P-13)                      pressurizer high level P-8          Absence of P-8: 3/4 neutron flux (power    Blocks reactor trip on low reactor coolant flow in range) below setpoint                      a single loop P-9          Absence of P-9: 3/4 neutron flux (power    Blocks reactor trip on turbine trip range) below setpoint P-11        Presence of P-11: 2/3 pressurizer pressure Allows manual block of safety injection and below setpoint                            steam line isolation actuation on low pressurizer pressure signal. With this manual block active, steamline isolation on high rate of decrease in steamline pressure is allowed.
Absence of P-11: 2/3 pressurizer pressure  Defeats manual block of safety safety injection above setpoint                            and steamline isolation on low pressurizer pressure.
Defeats steamline isolation actuation on high rate of decrease in steamline pressure.
Defeats (opens) all accumulator isolation valves.
P-13        Absence of P-13: 2/2 turbine impulse      Input to P-7 chamber pressure below setpoint
 
SEABROOK INSTRUMENTATION AND CONTROLS                                      Revision:          19 STATION                                                                  TABLE 7.2-3                                    Sheet:          1 of 2 UFSAR TABLE 7.2-3            REACTOR TRIP SYSTEM INSTRUMENTATION Typical Time Reactor Trip Signal                              Typical Range                    Typical Trip Accuracy        Response (sec)
: 1. Power range high neutron flux          1 to 120 percent full power              +/-6.0 percent of span                      0.5
: 2. Intermediate range high neutron        8 decades of neutron flux overlapping    +/-9.8 percent of span                      N/A flux                                    source range by 2 decades                +/-1 percent of span from 10-4 to 50 percent full power (1)
: 3. Source range high neutron flux          6 decades of neutron flux                +/-11.5 percent of span (1)                N/A (1 to 106 counts/sec)
: 4. Power range high positive neutron      +15 percent of full power                +/-1.4 percent of span (1)                  0.65 flux rate
: 5. Deleted
: 6. Overtemperature T:                    TH 530 to 650°F                          +/-5.1 percent of span                      6.0 TC 510 to 630°F TAV 530 to 630°F PPRZR 1600 to 2500 psig F1(I) -60 to +60 T Setpoint 0 to 100°F
: 7. Overpower T                            TH 530 to 650°F                        +/-5.5 percent of span                      6.0 TC 510 to 630°F TAV 530 to 630°F T Setpoint 0 to 100°F F2(I) -60 to +60
: 8. Pressurizer low pressure                1600 to 2500 psig                      +/-2.14 percent of span (compensated        2.0 signal)
(1) Reproducibility (see definitions in Section 7.1)
 
SEABROOK INSTRUMENTATION AND CONTROLS                                            Revision:          19 STATION                                                                  TABLE 7.2-3                                        Sheet:          2 of 2 UFSAR Typical Time Reactor Trip Signal                              Typical Range                    Typical Trip Accuracy            Response (sec)
: 9. Pressurizer high pressure              1600 to 2500 psig                        +/-2.14 percent of span                        2.0 (noncompensated signal)
: 10. Pressurizer high water level            Entire cylindrical portion of pressurizer +/-4.59 percent of span                        N/A (distance between taps)
: 11. Low reactor coolant flow                0 to 120 percent rated flow              +/-2.6 percent of span within range of          1.0 70 percent to 100 percent of full flow (1)
: 12. Reactor coolant pump bus                61 to 87 percent nominal bus voltage      +/-10.5 percent of span                        2.25 undervoltage
: 13. Reactor coolant pump                    44 to 61 Hz                              +/-1.0 percent of span                          0.6 underfrequency
: 14. Low-low steam generator water            0 - 100% N. R. Span                      +/-19.6 percent of span (2)                      2.0 level
: 15. Turbine Trip                            150 to 3000 psig                          +/-3.3 percent of span                          N/A (1) Reproducibility (see definitions in Section 7.1)
(2) Bounding Uncertainty
 
SEABROOK INSTRUMENTATION AND CONTROLS                              Revision:                  17 STATION                                          TABLE 7.2-4                            Sheet:                  1 of 3 UFSAR TABLE 7.2-4              REACTOR TRIP CORRELATION Trip(a)                                          Accident(b)                                  Tech Spec(c)
: 1. Power Range              1.      Uncontrolled Rod Cluster Control Assembly Bank              2.2.1 Table 2.2-1 High Neutron                    Withdrawal from a Subcritical Condition (15.4.1)
Flux Trip              2.      Excessive Heat Removal Due to Feedwater System (Low Setpoint)                  Malfunctions (15.1.2)
: 3.      Rupture of a Control Rod Drive Mechanism Housing (Rod Cluster Control Assembly Ejection) (15.4.8)
: 2. Power Range              1.      Uncontrolled Rod Cluster Control Assembly Bank              2.2.1 Table 2.2-1 High Neutron                    Withdrawal from a Subcritical Condition (15.4.1)
Flux Trip              2.      Uncontrolled Rod Cluster Control Assembly Bank (High Setpoint)                  Withdrawal at Power (15.4.2)
: 3.      Excessive Heat Removal Due to Feedwater System Malfunctions (15.1.2)
: 4.      Excessive Load Increase Incident (15.1.3)
: 5.      Accidental Depressurization of the Main Steam System (15.1.4)
: 6.      Major Secondary System Pipe Ruptures (15.1.5)
: 7.      Rupture of a Control Rod Drive Mechanism Housing (Rod Cluster Control Assembly Ejection) (15.4.8)
: 3. Intermediate              1.      Uncontrolled Rod Cluster Control Assembly Bank              See Note (d) 2.2.1 Range High                      Withdrawal from a Subcritical Condition (15.4.1)            Table 2.2-1 Neutron Flux Trip
: 4. Source Range              1.      Uncontrolled Rod Cluster Control Assembly Bank              See Note (d) 2.2.1 High Neutron                    Withdrawal from a Subcritical Condition (15.4.1)            Table 2.2-1 Flux Trip
: 5. Power Range              1.      Rupture of a Control Rod Drive Mechanism Housing            2.2.1 Table 2.2-1 High Positive                    (Rod Cluster Control Assembly Ejection) (15.4.8)
Neutron Flux Rate      2.      Uncontrolled Rod Cluster Control Assembly Bank Trip                            Withdrawal from a Subcritical Condition (15.4.1)
: 3.      Uncontrolled Rod Cluster Control Assembly Bank Withdrawal at Power (15.4.2)
: 6. Deleted (a)
Trips are listed in order of discussion in Section 7.2.
(b)
References refer to accident analyses presented in Chapter 15.
(c)
References refer to Technical Specifications.
(d)
A Technical Specification is not required because this trip is not assumed to function in the accident analyses.
 
SEABROOK INSTRUMENTATION AND CONTROLS                            Revision:              17 STATION                              TABLE 7.2-4                              Sheet:              2 of 3 UFSAR
: 7. Overtemperature  1. Uncontrolled Rod Cluster Control Assembly Bank            2.2.1 Table 2.2-1 T Trip                Withdrawal at Power (15.4.2)
: 2. Uncontrolled Boron Dilution (15.4.6)
: 3. Loss of External Electrical Load and/or Turbine Trip (15.2.2 and 15.2.3)
: 4. Excessive Heat Removal Due to Feedwater System Malfunctions (15.1.2)
: 5. Excessive Load Increase Incident (15.1.3)
: 6. Accidental Depressurization of the Reactor Coolant System (15.6.1)
: 7. Accidental Depressurization of the Main Steam System (15.1.4)
: 8. Steam Generator Tube Rupture (15.6.3)
: 9. Feedwater System Pipe Break (15.2.8)
: 8. Overpower T      1. Uncontrolled Rod Cluster Control Assembly Bank            2.2.1 Table 2.2-1 Trip                  Withdrawal at Power (15.4.2)
: 2. Excessive Heat Removal Due to Feedwater System Malfunctions (15.1.2)
: 3. Excessive Load Increase Incident (15.1.3)
: 4. Accidental Depressurization of the Main Steam System (15.1.4)
: 5. Major Secondary System Pipe Ruptures (15.1.5)
: 6. Rod Cluster Control Assembly Misoperation (15.4.3)
: 9. Pressurizer Low  1. Accidental Depressurization of the Reactor Coolant        2.2.1 Table 2.2-1 Pressure Trip          System (15.6.1)
: 2. Loss-of-Coolant Accidents Resulting from a Spectrum of Postulated Piping Breaks within the Reactor Coolant Pressure Boundary (15.6.5)
: 3. Major Reactor Coolant System Pipe Ruptures (LOCA)
(15.6.5)
: 4. Steam Generator Tube Rupture (15.6.3)
: 5. Inadvertent Operation of Emergency Core Cooling System during Power Operation (15.5.1)
: 10. Pressurizer High 1. Uncontrolled Rod Cluster Control Assembly Bank            2.2.1 Table 2.2-1 Pressure Trip          Withdrawal at Power (15.4.2)
: 2. Loss of External Electrical Load and/or Turbine Trip (15.2.2 and 15.2.3)
: 3. Feedwater System Pipe Break (15.2.8)
: 11. Pressurizer High 1. Uncontrolled Rod Cluster Control Assembly Bank at        2.2.1 Table 2.2-1 Water Level Trip      Power (15.4.2)
: 2. Loss of External Electrical Load and/or Turbine Trip (15.2.2 and 15.2.3)
 
SEABROOK INSTRUMENTATION AND CONTROLS                                  Revision:                  17 STATION                                        TABLE 7.2-4                              Sheet:                  3 of 3 UFSAR
: 12. Low Reactor          1.        Partial Loss of Forced Reactor Coolant Flow (15.3.1)          2.2.1 Table 2.2-1 Coolant Flow          2.        Loss of Offsite Power to the Station Auxiliaries (Station Blackout) (15.2.6)
: 3.        Complete Loss of Forced Reactor Coolant Flow (15.3.2)
: 4.        Reactor Coolant Pump Shaft Seizure, (Locked Rotor)
(15.3.3)
: 5.        Reactor Coolant Pump Shaft Seizure (Locked Rotor)
Followed by Loss of Offsite Power (15.3.4)
: 6.        Startup of an Inactive Reactor Coolant Pump at an Incorrect Temperature (15.4.4)
: 13. Reactor Coolant      1.        Complete Loss of Forced Reactor Coolant Flow (15.3.2)          2.2.1 Table 2.2-1 Undervoltage Trip
: 14. Reactor Coolant      1.        Complete Loss of Forced Reactor Coolant Flow (15.3.2)          2.2.1 Table 2.2-1 Underfrequency Trip
: 15. Low-low Steam        1.        Loss of Normal Feedwater Flow (15.2.7)                        2.2.1 Table 2.2-1 Generator Water      2.        Loss of External Load (15.2.2)
Level Trip            3.        Loss of Nonemergency AC Power to the Plant Auxiliaries (Loss of Offsite Power) (15.2.6)
: 4.        Feedwater System Pipe Break (15.2.8)
: 16. Reactor Trip on      1.        Loss of External Electrical Load and/or Turbine Trip          See Note (d) 2.2.1 Turbine Trip                    (15.2.2 and 15.2.3)                                            Table 2.2-1
: 2.        Loss of Offsite Power to the Station Auxiliaries (Station      See Note (d) 2.2.1 Blackout) (15.2.6)                                            Table 2.2-1
: 17. Safety Injection      1.        Accidental Depressurization of the Main Steam System          See Note (e)
Signal Actuation                (15.1.4)
Trip                  2.        Loss of Nonemergency AC Power to the Plant Auxiliaries (Loss of Offsite Power) (15.2.6)
: 3.        Feedwater System Pipebreak (15.2.8)
: 4.        Loss-of-Coolant Accidents Resulting from a Spectrum of Postulated Piping Breaks Within the Reactor Coolant Pressure Boundary (15.6.5)
: 5.        Steam Generator Tube Rupture (15.6.3)
: 6.        Steam System Piping Failure (15.1.5)
: 18. Manual Trip          Available for all Accidents (Chapter 15)                                See Note (d)
(d)
A Technical Specification is not required because this trip is not assumed to function in the accident analyses.
(e)
Accident assumes that the reactor is tripped at end-of-life (EOL) which is the worst initial condition for this case.
 
SEABROOK INSTRUMENTATION AND CONTROLS                                  Revision:                  8 STATION                                      TABLE 7.3-1                                Sheet:                1 of 2 UFSAR TABLE 7.3-1            ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION No. Functional Unit                                      No. of Channels            No. of Channels To Trip
: 1. Safety Injection
: a. Manual                                                      2                              1
: b. Containment Pressure-Hi-1                                  3                              2
: c. Low Steamline Pressure (Lead-Lag                    12 (3/steam line)            2 in any one steam line compensated) *
: d. Pressurizer Low Pressure*                                  4                              2
: 2. Containment Spray
: a. Manual **                                                  2                1 with 2 coincident switches
: b. Containment Pressure-Hi-3                                  4                              2
: 3. Containment Isolation
: a. Phase "A" Isolation
: 1) Manual Initiation                                        2                              1
: 2) Safety Injection                                See item number 1
: b. Phase "B" Isolation
: 1) Manual Initiation of Containment Spray                  2                1 with 2 coincident switches
: 2) Containment Pressure-Hi-3                                4                              2
: c. Containment Ventilation Isolation
: 1) Manual Initiation of Phase "A" Isolation        See item number 3a
: 2) Safety Injection Radioactivity High            See item number 1
: 3) Containment Online Purge                                2                              1
: 4) Manipulator Crane High Radiation                        2                              1 Permissible bypass if reactor coolant pressure less than P-11.
Manual actuation of a train of containment spray is accomplished by actuating either of two sets (two switches per set). Both switches in a set must be actuated to obtain a manually initiated spray signal for the respective train.
The sets are wired to meet separation and single failure requirements of IEEE Standard 279-1971. Simultaneous operation of two switches is desirable to prevent inadvertent spray actuation.
 
SEABROOK INSTRUMENTATION AND CONTROLS                Revision:                  8 STATION                                    TABLE 7.3-1                Sheet:                2 of 2 UFSAR No. Functional Unit                                  No. of Channels No. of Channels To Trip
: 4. Steam Line Isolation
: a. Low Steamline Pressure                          3/steam line  2 in any one steam line
: b. Containment Pressure-Hi-2                              3                  2
: c. Steam Generator Pressure - Negative - High      3/steam line  2 in any one steam line
: d. Manual
: 1) Individual                                      1/loop              1/loop
: 2) System                                              2                  1
: 5. Feedwater Line Isolation
: a. Safety Injection                                See Item No. 1
: b. Steam Generator Level High-High on any          4/Steam Gen.        2/Steam Gen.
Steam Generator (P-14)
: c. Low Tavg Coincident with Reactor Trip (P4)          1/loop          any two loops (see Table 7.3-2)
: 6. Emergency Feedwater
: a. Manual
: 1) Motor-Driven Pump                                  1                  1
: 2) Turbine-Driven Pump                                2                  1
: b. Steam gen. water level low-low                  4/Steam Gen.        2/Steam Gen.
: c. Safety Injection                                                    See item No. 1
: d. Loss of Offsite Power Start Motor-Driven            2/bus              2/bus Pump and Turbine-Driven Pump
: 7. Automatic Switchover to Containment Sump
: a. RWST Level - low-low coincident with safety            4                  2 injection
 
SEABROOK INSTRUMENTATION AND CONTROLS                                Revision:                8 STATION                                        TABLE 7.3-2                            Sheet:              1 of 1 UFSAR TABLE 7.3-2            INTERLOCKS FOR ENGINEERED SAFETY FEATURES ACTUATION SYSTEM Designation                        Input                                Function Performed P-4                      Reactor Trip                      Actuates turbine trip (independent of the SSPS, see Section 7.2.1.1 and 7.3.2.3 Closes main and bypass feedwater valves on Tavg below setpoint Prevents opening of main and bypass feedwater valves which were closed by safety injection or High-High steam generator water level Allows manual block of the automatic reactuation of safety injection Used in the control of steam dump valves (Figure 7.2-10)
Reactor not tripped                Defeats the block which is preventing automatic reactuation of safety injection P-11                      2/3 Pressurizer pressure below    Allows manual block of safety injection actuation on setpoint                          low pressurizer pressure signal Allows manual block of safety injection actuation and steamline isolation on low compensated steamline pressure signal, and allows steamline isolation on high steamline negative pressure rate 2/3 Pressurizer pressure above    Defeats manual block of safety injection actuation setpoint P-12                      2/4 Tavg below setpoint            Blocks steam dump Allows manual bypass of steam dump block for the cooldown valves only 3/4 Tavg above setpoint            Defeats the manual bypass of steam dump block P-14                      2/4 Steam Generator water level    Closes all feedwater control valves and isolation above setpoint on any steam        valves generator
* Trips all main feedwater pumps Actuates turbine trip The level channels, which have condensate pots common to both steam flow transmitters and level transmitters, are lag compensated to prevent spurious trips caused by short-term pressure waves which are generated during rapid closure of the turbine control valves.
 
SEABROOK INSTRUMENTATION AND CONTROLS                        Revision:        15 STATION TABLE 7.4-1                              Sheet:      1 of 13 UFSAR TABLE 7.4-1        EQUIPMENT REQUIRED FOR SAFE SHUTDOWN Instrumentation Location Description                    Device    RSS Control Location MCB CP108A          CP108B    Local
: a. Decay Heat Removal:
Emergency Feedwater Pump          MS-V-393        CP-108A (FW-P-37A)
MS-V-394        CP-108B MS-V-395        CP-108A & B Emergency Feedwater Pump          FW-P-37B          Bus E6 Emergency Feedwater Recirc. Valves FW-V-346          CP-108A FW-V-347          CP-108B SG A EFW Control Valve            FW-FV-4214A      CP-108A & CP-450A SG A EFW Control Valve            FW-FV-4214B      CP-108B & CP-450B SG B EFW Control Valve            FW-FV-4224A      CP-108A & CP-450A SG B EFW Control Valve            FW-FV-4224B      CP-108B & CP-450B SG C EFW Control Valve            FW-FV-4234A      CP-108A & CP-450A SG C EFW Control Valve            FW-FV-4234B      CP-108B & CP-450B SG D EFW Control Valve            FW-FV-4244A      CP-108A & CP-450A SG D EFW Control Valve            FW-FV-4244B      CP-108B & CP-450B SG A EFW Flow                      FW-FI-4214-5                                  X FW-FI-4214-2                            X SG B EFW Flow                      FW-FI-4224-5                                                  X FW-FI-4224-2                            X
 
SEABROOK INSTRUMENTATION AND CONTROLS                        Revision:        15 STATION TABLE 7.4-1                              Sheet:      2 of 13 UFSAR Instrumentation Location Description                  Device    RSS Control Location MCB CP108A          CP108B    Local SG C EFW Flow                      FW-FI-4234-5                                  X FW-FI-4234-2                            X SG D EFW Flow                      FW-FI-4244-5                                                  X FW-FI-4244-2                            X RC Loop 1 Hot Leg Temp.            RC-TI-9406                                    X RC Loop 1 Hot Leg Temp.            RC-TI-413A                              X RC Loop 4 Hot Leg Temp.            RC-TI-9407                                                    X RC Loop 2 Hot Leg Temp.            RC-TI-423A                              X RC Loop 1 Cold Leg Temp.          RC-TI-9410                                    X RC Loop 1 Cold Leg Temp.          RC-TI-413B                              X RC Loop 4 Cold Leg Temp.          RC-TI-9411                                                    X RC Loop 2 Cold Leg Temp.          RC-TI-423B                              X SG A Atmos. Relief Valve          MS-PV-3001        CP-108A/Distr. Panel 113B/CP-915A SG B Atmos. Relief Valve          MS-PV-3002      CP-108B/Distr. Panel 113A/CP-915B SG C Atmos. Relief Valve          MS-PV-3003        CP-108A/Distr.Panel 113B/CP-915A SG D Atmos. Relief Valve          MS-PV-3004      CP-108B/Distr.Panel 113A/CP-915B EFW Pump Suction Pressure (for CST FW-PI-4208                                                            X Level)
FW-PI-4209                                                            X
 
SEABROOK INSTRUMENTATION AND CONTROLS                          Revision:        15 STATION TABLE 7.4-1                              Sheet:      3 of 13 UFSAR Instrumentation Location Description        Device        RSS Control Location MCB CP108A          CP108B    Local CST Level                FW-LI-4252                                  X FW-LI-4257                                  X CST Inventory            CO-LIS-4052                                                              X MS Isol. Valves          MS-V-86, 88, 90, 92  CP-108A MS Isol. Valves          MS-V-86, 88, 90, 92  CP-108B SG A Wide-Range Level    FW-LI-4310                                        X FW-LI-501                                  X SG B Wide-Range Level    FW-LI-4320                                                        X FW-LI-502                                  X SG C Wide-Range Level    FW-LI-4330                                        X FW-LI-503                                  X SG D Wide-Range Level    FW-LI-4340                                                        X FW-LI-504                                  X SG A Pressure            MS-PI-3173                                        X FW-PI-514A                                  X SG B Pressure            MS-PI-3174                                                        X FW-PI-525A                                  X SG C Pressure            MS-PI-3178                                        X FW-PI-534A                                  X SG D Pressure            MS-PI-3179                                                        X FW-PI-545A                                  X
 
SEABROOK INSTRUMENTATION AND CONTROLS                        Revision:        15 STATION TABLE 7.4-1                              Sheet:      4 of 13 UFSAR Instrumentation Location Description                        Device      RSS Control Location MCB CP108A          CP108B    Local SG Blowdown Isol. Valves                SB-V-9, 10, 11, 12 Distr. Panels 112A and B
Spent Fuel Pool Pump                    SF-P-10A (7)        MCC-E512 (7)
Spent Fuel Pool Pump                    SF-P-10B            MCC-E612 Spent Fuel Pool Pump                    SF-P-10C (7)        MCC-E512 or MCC-E612
: b. Reactor Coolant (RC) Inventory and Pressure Control:
Charging Pump                            CS-P-2A            Bus E5 Charging Pump                            CS-P-2B            Bus E6 (8)
Charging Flow Isol. Valve                CS-V-142            CP-108A (8)
Charging Flow Isol. Valve                CS-V-143            CP-108B Charging Pump Suction from RWST          CS-LCV-112D        CP-108A Charging Pump Suction from RWST          CS-LCV-112E        CP-108B Charging Pump Discharge Valve            CS-V-210            Local Charging Pump Discharge Valve            CS-V-220            Local Charging Pump Bypass Valve              CS-V-219            Local Charging Pump Bypass Valve              CS-V-221            Local Pressurizer Relief Valves (PORV)        RC-PCV-456A        CP-108A and CP-450A Pressurizer Relief Valves (PORV)        RC-PCV-456B        CP-108B and CP-450B PORV Block Valve                        RC-V-122            CP-108A PORV Block Valve                        RC-V-124          CP-108B
 
SEABROOK INSTRUMENTATION AND CONTROLS                        Revision:        15 STATION TABLE 7.4-1                              Sheet:      5 of 13 UFSAR Instrumentation Location Description        Device    RSS Control Location MCB CP108A          CP108B    Local Pressurizer Pressure      RC-PI-7336                                    X RCS Pressure              RC-PI-405-1, 2                          X Pressurizer Pressure      RC-PI-7335                                                    X RCS Pressure              RC-PI-403-1, 2                          X Pressurizer Level          RC-LI-7334                                    X RC-LI-459A                              X Pressurizer Level          RC-LI-7333                                                    X RC-LI-460A                              X Boric Acid Tank Level      CS-LI-7446                                    X (TK-4A)
CS-LI-102                                X Boric Acid Tank Level      CS-LI-7464                                                    X (TK-4B)
CS-LI-106                                X High Pressure Injection    SI-V-138        CP-108A and CP-915A High Pressure Injection    SI-V-139        CP-108B and CP-915B VCT Disch. Isol. Valve    CS-LCV-112B      CP-108A VCT Disch. Isol. Valve    CS-LCV-112C      CP-108B RC Normal Letdown Isol. RC-LCV-459      Distr. Panel PP-122B RC Normal Letdown Isol. RC-LCV-460      Distr. Panel PP-122B (1)
RC Excess Letdown Isol. CS-V-175          Distr. Panel PP-1111B (1)
RC Excess Letdown Isol. CS-V-176          Distr. Panel PP-1111B SI Accum. TK-9A Isol. Vlv. SI-V-3          CP-108A
 
SEABROOK INSTRUMENTATION AND CONTROLS                        Revision:        15 STATION TABLE 7.4-1                              Sheet:      6 of 13 UFSAR Instrumentation Location Description                          Device    RSS Control Location MCB CP108A          CP108B    Local SI Accum. TK-9B Isol. Vlv.                SI-V-17            CP-108B SI Accum. TK-9C Isol. Vlv.                SI-V-32            CP-108A SI Accum. TK-9D Isol. Vlv.                SI-V-47          CP-108B SI Accum. TK-9A Vent Vlvs.                SI-FV-2475, 2476  CP-108B SI Accum. TK-9B Vent Vlvs.                SI-FV-2482, 2483  CP-108A SI Accum. TK-9C Vent Vlvs.                SI-FV-2477, 2486  CP-108B SI Accum. TK-9D Vent Vlvs.                SI-FV-2495, 2496  CP-108A Bus E52 Feeder Breaker to MCC E522        AW9                CP-108A Bus E62 Feeder Breaker to MCC E622        AW0                CP-108B
: c. Reactivity Monitoring and Control:
Neutron Flux Indicators/ Monitors (Excore)
Intermediate Range Flux                    NI-NI-6690-2                              X Intermediate Range Flux                    NI-NI-6690-3                                    X Source Range Flux                          NI-NI-6690-4                                    X Intermediate Range Flux                    NI-NI-6691-2                              X Intermediate Range Flux                    NI-NI-6691-3                                                    X Source Range Flux                          NI-NI-6691-4                                                    X Shutdown Monitor                          NI-NM-6690-1                              X Shutdown Monitor                          NI-NM-6691-1                              X Boric Acid Trans. Pump                    CS-P-3A          MCC E512
 
SEABROOK INSTRUMENTATION AND CONTROLS                        Revision:        15 STATION TABLE 7.4-1                              Sheet:      7 of 13 UFSAR Instrumentation Location Description              Device    RSS Control Location MCB CP108A          CP108B    Local Boric Acid Trans. Pump          CS-P-3B          MCC E612 BA to Chg. Pump Isol. Valve    CS-V-426        MCC E612 Gravity Feed Boration Vlv.      CS-V-423        Local Gravity Feed Boration Vlv.      CS-V-431        Local Gravity Feed Boration Vlv.      CS-V-437        Local Gravity Feed Boration Vlv.      CS-V-439        Local Gravity Feed Boration Vlv.      CS-V-442        Local Gravity Feed Boration Vlv.      CS-V-410        Local Gravity Feed Boration Vlv.      CS-V-416        Local Gravity Feed Boration Vlv.      CS-V-1207        Local Reactor Trip Breakers          CP-CP-111        Local
: d. Service Water (SW):
Service Water Pump              SW-P-41A        Bus E5 Service Water Pump              SW-P-41B          Bus E6 Service Water Pump              SW-P-41C          Bus E5 Service Water Pump              SW-P-41D        Bus E6 DG Hx Discharge                SW-V-16          Distr. Panel PP-113A DG Hx Discharge                SW-V-18          Distr. Panel PP-113B SCCW Heat Exchanger Inlet Valve SW-V-4            CP-108A SCCW Heat Exchanger Inlet Valve SW-V-5          CP-108B
 
SEABROOK INSTRUMENTATION AND CONTROLS                        Revision:        15 STATION TABLE 7.4-1                              Sheet:      8 of 13 UFSAR Instrumentation Location Description                            Device    RSS Control Location MCB CP108A          CP108B    Local SW Pump Disch. Valve (see note below)    SW-V-2            N/A SW Pump Disch. Valve (see note below)    SW-V-22            N/A SW Pump Disch. Valve (see note below)    SW-V-29            N/A SW Pump Disch. Valve (see note below)    SW-V-31            N/A Cooling Tower Pump                        SW-P-110A          Bus E5 Cooling Tower Pump                        SW-P-110B          Bus E6 CT Pump Disch Valve                      SW-V54              CP-108A CT Pump Disch Valve                      SW-V25              CP-108B CT FAN                                    SW-FN-51A          Bus E5 CT FAN                                    SW-FN-51B          CP-108B CT Spray Bypass Recirc Valve              SW-V139            Local CT Spray Bypass Recirc Valve              SW-V140            Local Note: Automatic control from pump start circuitry only.
: e. Primary Component Cooling (PCCW):
PCCW Pump                                CC-P-11A          Bus E5 PCCW Pump                                CC-P-11B          Bus E6 PCCW Pump                                CC-P-11C          Bus E5 PCCW Pump                                CC-P-11D          Bus E6 PCCW Loop A Temp. CV                      CC-TV-2171-1        CP-108A CC-TV-2171-2
 
SEABROOK INSTRUMENTATION AND CONTROLS                        Revision:        15 STATION TABLE 7.4-1                              Sheet:      9 of 13 UFSAR Instrumentation Location Description                  Device    RSS Control Location MCB CP108A          CP108B    Local Thermal Barrier Cooling Pump      CC-P-322A (2)    CP-108A (2)
Thermal Barrier Cooling Pump      CC-P-322B        CP-108B PCCW Loop B Temp. CV              CC-TV-2271-1      CP-108B CC-TV-2271-2 PCCW Loop A Temp.                  CC-TI-2171-1                            X CC-TI-2197                                    X PCCW Loop B Temp.                  CC-TI-2271-1                            X CC-TI-2297                                                    X RHR Hx E-9A Outlet Valve          CC-V-145        Local RHR Hx E-9B Outlet Valve          CC-V-272        Local
: f. HVAC:
Emerg. Switchgear Area Supply Fans CBA-FN-19, 32    MCC E515,621 Emerg. Switchgear Area Return Fans CBA-FN-20, 33    MCC E521,621 Battery Room Exhaust Fan A        CBA-FN-21A      MCC E521 CBA-DP-21A      MCC E521 Battery Room Exhaust Fan B        CBA-FN-21B      MCC E621 CBA-DP-21B      MCC E621 Train A Mech. Rm. Intake Damper    CBA-DP-24A      Local Train A Mech. Rm. Recirc. Damper  CBA-DP-24B        Local Train A Mech. Rm. Exhaust Damper  CBA-DP-24C      Local
 
SEABROOK INSTRUMENTATION AND CONTROLS                        Revision:        15 STATION TABLE 7.4-1                              Sheet:    10 of 13 UFSAR Instrumentation Location Description                  Device    RSS Control Location MCB CP108A          CP108B    Local Train B Mech. Rm. Intake Damper      CBA-DP-24D      Local Train B Mech. Rm. Recirc. Damper    CBA-DP-24E      Local Train B Mech. Rm. Exhaust Damper    CBA-DP-24F      Local DG Room Supply Fans                  DAH-FN-25A, B  MCC E521,621 DG Room Exhaust Fans                DAH-FN-26A, B    MCC E521,621 DG Room Exhaust Dampers              DAH-DP-16A, B  MCC E521,621 Contn. Encl. Fans                    EAH-FN-5A, B    CP-108A,B Contn. Encl. Fans                    EAH-FN-31A, B    MCC E512,612 Emerg. Feed Pumphouse Fans          EPA-FN-47A, B  MCC E512,612 Emerg. Feed Pumphouse Dampers        EPA-DP-373, 374 MCC E512,612 PAB PCC Pump Area Supply Fans        PAH-FN-42A, B    MCC E512,612 PAB PCC Pump Area Supply Dampers    PAH-DP-43A, B    MCC E512,612 PAB PCC Pump Area Exhaust Dampers    PAH-DP-357, 358 MCC E512,612 SW Pumphouse Area Supply Fans        SWA-FN-40A, B    CP-108A,B H2 Analyzer and Electrical Room Fans EAH-FN-174A, B  MCC E515,615
: g. Residual Heat Removal (RHR):
RHR Pump                            RH-P-8A        Bus E5 RHR Pump                            RH-P-8B        Bus E6 RHR System Valve                    RC-V-88        CP-108A RHR System Valve                    RC-V-23        CP-108A
 
SEABROOK INSTRUMENTATION AND CONTROLS                          Revision:        15 STATION TABLE 7.4-1                              Sheet:    11 of 13 UFSAR Instrumentation Location Description              Device      RSS Control Location MCB CP108A          CP108B    Local RHR System Valve              RC-V-22            CP-108B RHR System Valve              RC-V-87            CP-108B (3)
RHR Hx Bypass Valve            RH-FCV-618        Distr. Panel PP-112A (3)
RHR Hx Bypass Valve            RH-FCV-619        Distr. Panel PP-112B (3)
RHR Hx Valve                  RH-HCV-606        Distr. Panel PP-112A RHR Hx Valve                  RH-HCV-607 (3)    Distr. Panel PP-112B (9)
RHR Pump Recirculation        RH-FCV-610          Local (9)
RHR Pump Recirculation        RH-FCV-611          Local RHR Suction From RWST(Loop A)  CBS-V-2 (10)        Local (10)
RHR Suction From RWST (Loop B) CBS-V-5            Local
: h. Sampling:
RCS Sampling (Loop #1)        RC-FV-2832          CP-108A RC-FV-2894          CP-108A RCS Sampling (Loop #3)        RC-FV-2833        CP-108B RC-FV-2896        CP-108B (4)
RHR Local Sample Valves        RH-V-8            Local
 
SEABROOK INSTRUMENTATION AND CONTROLS                                                    Revision:                  15 STATION TABLE 7.4-1                                                  Sheet:            12 of 13 UFSAR Instrumentation Location Description                          Device              RSS Control Location        MCB          CP108A          CP108B            Local RH-V-44 (4)                  Local
: i. Solid State Protection System (SSPS):
SSPS Output Train A                        MM-CP-12                      Distr. Panel PP-1A SSPS Output Train B                        MM-CP-13                      Distr. Panel PP-1B
: j. Electrical Power Supply:
Diesel Generator A                          DG-1A                        Local(6)
Diesel Generator B                          DG-1B                        Local(6)
Electrical Distribution Equipment A        EDE (5)                      Local Electrical Distribution Equipment B        EDE (5)                      Local Notes (1)      Normally closed (passive) valves.
(2)      These pumps provide a desired function, but not a required function, for safe shutdown.
(3)      Modulation of these valves is not required, but repositioning is required based on desired minimization of system transients.
(4)      These Manual sample valves are not considered active. Station abnormal procedures provide guidance to obtain grab samples via operation of these valves as a backup to using RH-V-16 and RH-V-17 for this purpose.
(5)      To simplify Table 7.4.1, specific equipment/tag numbers for electrical distribution equipment (EDE) will only be listed where an operator action is required to make the equipment perform its safe shutdown function. The only EDE equipment in this category are the feeder breakers for MCC E522 &
E622 (see Item b, Reactor Coolant (RC) Inventory and Pressure Control). These MCCs are normally de-energized while the plant is at 100% power but must be energized during safe shutdown to provide power to various valves. All of the other EDE equipment is normally in its safe shutdown position or any required actions are automatically initiated. The circuit breaker or motor starter required to operate individual loads is considered part of the line item for the load itself.
 
SEABROOK INSTRUMENTATION AND CONTROLS                                                  Revision:                15 STATION TABLE 7.4-1                                                Sheet:              13 of 13 UFSAR (6)  To simplify Table 7.4.1, specific equipment/tag numbers for the diesel generators (DG) will only be listed where an operator action is required to make the equipment perform its safe shutdown function. The only DG equipment in this category is the manual action required to close the DG circuit breakers to energize the emergency buses if control has been transferred to the RSS locations. The DG-1A & -1B entry is considered to represent the DG circuit breakers. All of the other DG equipment is normally in its safe shutdown position or any required actions are automatically initiated.
(7)  These pumps provide a heat removal safety function, but not a required safe shutdown function.
(8)  These valves provide an ECCS isolation function, but not a required safe shutdown function, for isolation of the normal CS path.
(9)  These valves provide a pump protection function, but not a required safe shutdown function.
(10)  These valves provide an ECCS and long term cooling (beyond RSS shutdown) desired isolation function, but not a required safe shutdown function.
 
SEABROOK                                                                                                                              Revision:                    17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                              Sheet:                  1 of 37 TABLE 7.5-1 UFSAR TABLE 7.5-1          ACCIDENT MONITORING INSTRUMENTATION LIST DISPLAY MCR R.G. 1.97            R.G. 1.97 RECOMMENDED              DESIGN        ACTUAL                    POWER                                                  TSC, EOF ITEM NUMBER        VARIABLE/SENSOR                  RANGE              CATEGORY        RANGE        REDUNDANCY SUPPLY        VARIABLE          TREND INDICATION    COMPUTER PLANT-SPECIFIC TYPE A VARIABLES A1              Degrees of Subcooling        200°F subcooling to 35°F        1      +300°F                Yes    Vital UPS RC-TI-9424A          RC-XX-7315-1,2&3(4)  Available RC-PT-403,                    superheat(from B10) Link              subcooling to                          RC-TI-9424B          RC-XX-7315-4(4)      Through Data RC-PT-405                                                            50°F superheat                                                                    Link IC-TE-1 through 58***
A2              Steam Generator Pressure      From atmospheric                1      0-1300 psig*          Yes    Vital UPS pressure to 20% above the lowest safety valve setting (1425 psig) (from D18)
FW-PT-514      SG-A                                                                                        PI-514A              XR-501                A0730 FW-PT-515                                                                                                    PI-515A                                    A0733 FW-PT-524      SG-B                                                                                        PI-524A                                    A0740 FW-PT-525                                                                                                    PI-525A              XR-502                A0743 FW-PT-534      SG-C                                                                                        PI-534A              XR-503                A0723 FW-PT-535                                                                                                    PI-535A                                    A0750 FW-PT-544      SG-D                                                                                        PI-544A                                    A0753 FW-PT-545                                                                                                    PI-545A              XR-504                A0720 A3              Core Exit Temperature        200°F to 2300°F                1      0-2300°F*              Yes    Vital UPS RC-TI-9423A          RC-XX-7315-1,2&3(4)** Available IC-TE-1 through 58***        (from B8)                                                                      RC-TI-9423B          RC-XX-7315-4(4)      Through Data RC-XX-7315-1,2&3(4)                        Link RC-XX-7315-4(4)
A4              Steam Generator Level        From tube sheet to              1      Taps 453.25" and      Yes    Vital UPS separators (from D17)                  581" above FW-LT-519      (NR)    SG-A                                        bottom reference                        LI-519  (NR)        LR-519(5)            A0734 FW-LT-501      (WR)                                                for narrow range                        LI-501  (WR)        XR-501                A0737 FW-LT-529      (NR)    SG-B                                        Taps 22" and 581"                      LI-529  (NR)        LR-529(5)            A0744 FW-LT-502      (WR)                                                above bottom                            LI-502  (WR)        XR-502                A0747 FW-LT-537      (NR)    SG-C                                        reference for wide                      LI-537  (NR)        LR-539(5)(3)          A0756 FW-LT-503      (WR)                                                range.                                  LI-503  (WR)        XR-503                A0757 FW-LT-548      (NR)    SG-D                                                                                LI-548  (NR)        LR-549(5)(3)          A0725 FW-LT-504      (WR)                                                                                        LI-504  (WR)        XR-504                A0727
 
SEABROOK                                                                                                                                        Revision:                            17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                                        Sheet:                      2 of 37 TABLE 7.5-1 UFSAR DISPLAY MCR R.G. 1.97            R.G. 1.97 RECOMMENDED                DESIGN        ACTUAL                      POWER                                                                        TSC, EOF ITEM NUMBER            VARIABLE/SENSOR            RANGE              CATEGORY          RANGE          REDUNDANCY  SUPPLY            VARIABLE                TREND INDICATION                COMPUTER PLANT-SPECIFIC TYPE A VARIABLES A5                  Pressurizer Level        Bottom to top (from D12)        1      Taps 6" from the          Yes    Vital UPS      LI-459A                    LR-459**(2)                      A0332 RC-LT-459                                                        top and bottom of                              LI-460A                    LR-460                            A0333 RC-LT-460                                                        the straight shell portion of the pressurizer*
SB DESIGN            ENVIRONMENTAL      SEISMIC ITEM NUMBER                                  CATEGORY              QUALIFICATION      QUAL.            QA  TRENDING REMARKS/NOTES PLANT-SPECIFIC TYPE A VARIABLES A1                  Degrees of Subcooling        1                    Yes              Yes          Yes      N/A  ***  Operation with less than the design number of core-exit thermocouples is permitted provided that the minimum functionality requirements are met. See Subsections 4.4.6.1 and 7.7.1.9.
A2                  Steam Generator Pressure      1                    Yes              Yes          Yes    Yes**
* See Deviation No. 1 in Appendix 7A.
                                                                                                                      **    Trending required based on use as a Type D variable.
A3                  Core Exit Temperature        1                    Yes              Yes          Yes      N/A
* Sensors are type K thermocouples that are calibrated to 1650°F.
                                                                                                                      **    Individual sensor temperatures and spatial displays are provided on RC-XX-7315-1,2&3(4) and RC-XX-7315-4(4).
                                                                                                                      ***  Operation with less than the design number of core-exit thermocouples is permitted provided that the minimum functionality requirements are met. See Subsections 4.4.6.1 and 7.7.1.9.
A4                  Steam Generator Level        1                    Yes              Yes          Yes      N/A  The WR steam generator level measurement taps cover the range from near the tube sheet to above the separators.
A5                  Pressurizer Level            1                    Yes              Yes          Yes      Yes
* See Deviation No. 2 in Appendix 7A.
                                                                                                                      **    The input signal to LR-459 is selectable to any one of the pressurizer level channels.
 
SEABROOK                                                                                                                              Revision:              17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                              Sheet:            3 of 37 TABLE 7.5-1 UFSAR DISPLAY MCR R.G. 1.97        R.G. 1.97 RECOMMENDED          DESIGN        ACTUAL                  POWER                                            TSC, EOF ITEM NUMBER            VARIABLE/SENSOR                    RANGE          CATEGORY        RANGE      REDUNDANCY SUPPLY          VARIABLE      TREND INDICATION  COMPUTER A6                RWST Level                      Top to bottom (from D9)      1      22,000 to
* Yes    Vital UPS Storage Tank Level                                                  485,500 gal CBS-LT-2380                                                                                                LI-2380            LR-2384          A0912 CBS-LT-2383                                                                                                LI-2383            LR-2385          A0913 A7                RCS Pressure                    0 to 3000 psig              1      0-3000 psig          Yes    Vital UPS (from B11 and B7)
RC-PT-403                                                                                                  PI-403-1&2          PR-403            A0350 RC-PT-405                                                                                                  PI-405-1&2          PR-405(2)        A0349 A8                DELETED A9                Control Room Temperature*
A10                Containment Sump Isolation Valve (Plant Specific)                    Open - Not Open      Yes*  Vital UPS ZL-2306**
Position                                                                                                    ZL-2307 CBS-ZS-2306-2 CBS-ZS-2307-1 REACTIVITY CONTROL B1                Neutron Flux                    10-6% to 100% full power    1      10-8 -200%            Yes    Vital UPS Full Power NI-NE-6690                                                          -1 to +7 DPM                          NI-6690-2                            A1019 NI-NE-6691                                                          (Rate)                                NI-6691-2                            A1022 NI-6690-1        A1018 NI-6691-1        A1021 B2                Control Rod Position            Full in or not full in      3      0-228 Steps          N/A      N/A    UI-7338                              I0036 through CP-U-7338                                                            (Full in to fully                                                            I0092 withdrawn)
B3                RCS Soluble Boron Concentration  0 to 6000 ppm                3      0-6000 ppm            N/A      N/A (Grab Sample)
B4                RCS Cold Leg Water Temperature  50°F to 400°F                3      See B6
 
SEABROOK                                                                                                                Revision:                              17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                Sheet:                        4 of 37 TABLE 7.5-1 UFSAR SB DESIGN  ENVIRONMENTAL      SEISMIC ITEM NUMBER                VARIABLE          CATEGORY    QUALIFICATION      QUAL. QA  TRENDING REMARKS/NOTES A6                RWST Level Tank Level      1          Yes              Yes        Yes N/A
* See Deviation No. 3 in Appendix 7A.
A7                RCS Pressure              1          Yes              Yes        Yes Yes A8                DELETED A9                Control Room Temperature
* See Deviation No. 30 in Appendix 7A A10                Containment Sump Isolation 1          Yes              Yes        Yes N/A
* The redundancy provision is met on a systems basis.
Valve Position
                                                                                                  ** The key indications of containment sump isolation valve position are the status lamp arrays arranged on a functional basis. A tile is provided for each containment sump isolation valve.
REACTIVITY CONTROL B1                Neutron Flux              1          Yes              Yes        Yes Yes B2                Control Rod Position      3          N/A              N/A        N/A N/A
* Control rod position inputs to the computer are available but are not listed here B3                RCS Soluble Boron          3          N/A              N/A        Yes N/A
* See Deviation No. 5 in Appendix 7A.
Concentration B4                RCS Cold Leg Water        See B6 Temperature
 
SEABROOK                                                                                                                                  Revision:                17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                                    Sheet:            5 of 37 TABLE 7.5-1 UFSAR DISPLAY MCR R.G. 1.97            R.G. 1.97 RECOMMENDED              DESIGN        ACTUAL                      POWER                                              TSC, EOF ITEM NUMBER        VARIABLE/SENSOR                    RANGE              CATEGORY        RANGE      REDUNDANCY        SUPPLY    VARIABLE            TREND INDICATION    COMPUTER B5            RCS Hot Leg Water Temperature          50°F to 700°F            1          32-700°F          NO*      Vital UPS RC-TE-413A                                                                                                          TI-413A            TR-413A            A0339 RC-TE-423A                                                                                                          TI-423A            TR-413A            A0340 RC-TE-433A                                                                                                          TI-433A(1)          TR-433A(2)          A0341 RC-TE-443A                                                                                                          TI-443A(1)          TR-433A(2)          A0342 B6            RCS Cold Leg Water Temperature          50°F to 700°F            1          32-700°F          NO*      Vital UPS RC-TE-413B                                                                                                          TI-413B            TR-413B            A0343 RC-TE-423B                                                                                                          TI-423B            TR-413B            A0344 RC-TE-433B                                                                                                          TI-433B(1)          TR-433B(2)**        A0345 RC-TE-443B                                                                                                          TI-443B(1)          TR-433B(2)**        A0346 B7            RCS Pressure                            0-3000 psig              1            See A7 B8            Core Exit Temperature                  200°F to 2300°F            3            See A3 B9            Reactor Coolant Inv. -Reactor    Bottom of hot leg to top of    1            0-120%    Yes(Full range;  Vital UPS Vessel Full Range Level (RCPs not    vessel; Void trending                              bottom to top of running)                                                                                vessel)
RC-LT-1311                                                                                                          RC-LI-1311          RC-XX-7315-1,2&3(4) Available RC-LT-1321                                                                                                          RC-LI-1321          RC-XX-7315-4(4)    Through Data Link
              -Reactor Vessel Dynamic Head                                            0-120% (dynamic (RCPs running)                                                          head range; RC-LT-1312                                                              indicates                                  RC-LI-1312          RC-XX-7315-1,2&3(4) Available RC-LT-1322                                                              normalized                                  RC-LI-1322          RC-XX-7315-4(4)    Through Data core dp)                                                                            Link B10            Degrees of Subcooling            200°F subcooling to 35°F        2            See A1 superheat RCS INTEGRITY B11            RCS Pressure                            0 to 3000 psig            1            See A7 B12            Containment Drainage Sump Water  Top to Bottom                  2 Level, Narrow Range*              (Sump)
 
SEABROOK                                                                                                          Revision:                            17 INSTRUMENTATION AND CONTROLS STATION                                                                                                            Sheet:                      6 of 37 TABLE 7.5-1 UFSAR SB DESIGN  ENVIRONMENTAL      SEISMIC ITEM NUMBER    VARIABLE CATEGORY        CATEGORY    QUALIFICATION      QUAL. QA TRENDING REMARKS/NOTES CORE COOLING B5            RCS Hot Leg Water              1    Yes              Yes        Yes Yes
* All Channels powered from UPS-I-A.
Temperature                                                                        See Deviation No. 6 in Appendix 7A.
B6            RCS Cold Leg Water            1    Yes              Yes        Yes Yes
* All channels powered from UPS-I-B Temperature                                                                        See Deviation No. 7 in Appendix 7A.
B7            RCS Pressure                See A7
* RC-TR-433B procured to Class 1E requirements due to circuit interaction considerations B8            Core Exit Temperature        See A3 B9            Reactor Coolant                1    Yes              Yes        Yes N/A      100% equals top of vessel or normal core dP Inventory with four reactor coolant pumps running.
B10          Degrees of Subcooling        See A1 RCS INTEGRITY B11          RCS Pressure                See A7 B12A          Containment Drainage Sump
* See Deviation No. 23 in Appendix 7A.
Water Level, Narrow Range*
 
SEABROOK                                                                                                                                                        Revision:              17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                                                        Sheet:            7 of 37 TABLE 7.5-1 UFSAR DISPLAY MCR R.G. 1.97                R.G. 1.97 RECOMMENDED                    DESIGN            ACTUAL                    POWER                                            TSC, EOF ITEM NUMBER                  VARIABLE/SENSOR                            RANGE                  CATEGORY          RANGE        REDUNDANCY  SUPPLY    VARIABLE            TREND INDICATION  COMPUTER B12B                    Containment Building Level, Wide              (plant-specific)                          4" to 8'4" above      Yes    Vital UPS Range                                                                                  base elevation                    &
CBS-LIT-2384                                                                    1                                    EMERG    LI-2384            LR-2384          A0930 CBS-LIT-2385                                                                                                            MCC    LI-2385            LR-2385          A0931 CONTAINMENT INTEGRITY B13                    Containment Pressure                      0 to design pressure                1      0-60 psig              Yes    Vital UPS (52 psig)
SI-PT-934,                                                                                                                      PI-934              PR-934            A0500 SI-PT-935                                                                                                                        PI-935              PR-935            A0501 B14                    Containment Isolation                      Closed-not closed                  1      Closed- not closed    Yes*  Vital** DC Valve Position See UFSAR Subsection 6.2.4 and Table 6.2-83 for complete information on the design of the Containment Isolation System and the listing of individual containment isolation valves.
B15                    Containment Pressure                    -5 psig to design pressure              1      See C11 (52 psig)
SI-PT-2576 SI-PT-2577 B16                    Containment Enclosure Negative                                                          0-1.0 in WCNEG        Yes    Vital UPS  PDI-5782                              A3778 Pressure                                                                                                                        PDI-5789 EAH-PDT-5782 EAH-PDT-5789 LITs powered from emergency MCCs. Remainder of loops powered from vital UPS.
 
SEABROOK                                                                                                                Revision:                              17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                  Sheet:                        8 of 37 TABLE 7.5-1 UFSAR SB DESIGN ENVIRONMENTAL    SEISMIC ITEM NUMBER            VARIABLE CATEGORY        CATEGORY  QUALIFICATION    QUAL. QA  TRENDING REMARKS/NOTES B12B                  Containment Building Level,    1          Yes          Yes  Yes N/A Wide Range CONTAINMENT INTEGRITY B13                  Containment Pressure            1          Yes          Yes  Yes Yes B14                  Containment Isolation Valve    1          Yes          Yes  Yes N/A
* The redundancy provision for containment isolation valves is met on a systems basis.
Position
                                                                                                    ** The primary indications of containment isolation valve position are status lamp arrays arranged on a functional basis. A tile is provided for each valve closed on either a Phase A or Phase B containment isolation signal. Valve position indicating lights are also provided with each valve control switch.
B15                  Containment Pressure        See C11 B16                  Containment Enclosure          1          Yes          Yes  Yes N/A Negative Pressure
 
SEABROOK                                                                                                                          Revision:              17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                            Sheet:            9 of 37 TABLE 7.5-1 UFSAR DISPLAY MCR R.G. 1.97          R.G. 1.97 RECOMMENDED            DESIGN      ACTUAL                  POWER                                            TSC, EOF ITEM NUMBER        VARIABLE/SENSOR                    RANGE            CATEGORY      RANGE      REDUNDANCY  SUPPLY    VARIABLE            TREND INDICATION  COMPUTER FUEL CLADDING C1            Core Exit Temperature            200°F to 2300°F                1          See A3 C2            Radioactive Concentration or    1/2 Tech Spec limit to 100      1 Radiation Level in Circulating  times Tech Spec limit Primary Coolant*                (50 to 104Ci/gm)
C3            Analysis of Primary Coolant      10 Ci/m1 to 10 Ci/m1 or      3          See E18 (Gamma Spectrum)                TID-14844 source term in coolant volume RCS BOUNDARY C4            RCS Pressure                    0 to 3000 psig                1          See A7 C5            Containment Pressure            -5 psig to design pressure    1          See C11 (52 psig)
C6A            Containment Drainage Sump Water  Top to bottom of sump          2        See B12A Level, Narrow-Range C6B            Containment Recirculation Sump  Wide-Range                    1        See B12B Water Level, Wide-Range          (plant-specific)
C7            Containment Area Radiation      1 R/hr to 104 R/hr            3          See E1
                                                  -6 C8            Effluent Radioactivity Noble Gas 10 Ci/cc to                  3          See E7 Effluent from Condenser Air      10-2 Ci/cc Removal System Exhaust CONTAINMENT C9            RCS Pressure                    0-3000 psig                    1          See A7 C10            Containment Hydrogen            0 to 10% volume (capable      1      0-10% H2-5 psig    Yes    Vital UPS&
Concentration                    of operating from -5 psig                to 60 psig              EMERG to maximum design                        operating                  MCC pressure 52 psig)                        capability (from C10)
CGC-AIT-5828A                                                                                                AI-5828A*          AR-5828A          A1445 CGC-AIT-5828B                                                                                                AI-5828B*                            A1446
 
SEABROOK                                                                                                              Revision:                17 INSTRUMENTATION AND CONTROLS STATION                                                                                                              Sheet:              10 of 37 TABLE 7.5-1 UFSAR SB DESIGN  ENVIRONMENTAL      SEISMIC ITEM NUMBER    VARIABLE CATEGORY            CATEGORY    QUALIFICATION      QUAL. QA  TRENDING REMARKS/NOTES FUEL CLADDING C1            Core Exit Temperature          See A3 C2            Radioactive Concentration or
* See Deviation No. 8 in Appendix 7A.
Radiation Level in Circulating Primary Coolant*
C3            Analysis of Primary Coolant    See E18 (gamma spectrum)
RCS BOUNDARY C4            RCS Pressure                  See A7 C5            Containment Pressure          See C11 C6A          Containment Drainage Sump      See B12A Water Level, Narrow-Range C6B          Containment Recirculation      See B12B Sump Water level, Wide Range C7            Containment Area Radiation    See E1 C8            Effluent Radioactivity Noble  See E7 Gas Effluent from Condenser Air Removal System Exhaust CONTAINMENT C9            RCS Pressure                  See B7 C10          Containment Hydrogen          3*        Yes              Yes        Yes N/A
* See Deviation No. 4 in Appendix 7A.
Concentration
 
SEABROOK                                                                                                                                        Revision:              17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                                          Sheet:          11 of 37 TABLE 7.5-1 UFSAR DISPLAY MCR R.G. 1.97          R.G. 1.97 RECOMMENDED              DESIGN        ACTUAL                    POWER                                            TSC, EOF ITEM NUMBER              VARIABLE/SENSOR                        RANGE            CATEGORY        RANGE        REDUNDANCY  SUPPLY  VARIABLE              TREND INDICATION  COMPUTER C11                Containment Pressure                  -5 psig pressure to 3 times    1      (-)5-0-160 psig        Yes    Vital UPS design pressure for concrete(-5 to 156 psig)
SI-PT-2576                                                                                                          PI-2576              PR-934            A0516 SI-PT-2577                                                                                                          PI-2577              PR-935            A0517 C12                Containment Effluent                  10-6 Ci/cc to                  2      See E7 Radioactivity-Noble Gases from        10-2 Ci/cc Identified Release Points C13                Effluent Radioactivity activity Noble 10-6 Ci/cc to                  2      101-106 cpm*          N/A    Emerg.
Gases (inside buildings or areas      103 Ci/cc                            (corresponds                  MCC where penetrations or hatches are                                            to6x10-4 Ci/cc to located)                                                                    10 Ci/cc)
RM-6566                                                                                                              1-MM-CP-295                            Available Through Data Link TYPE D VARIABLES, SYSTEM OPERATION RHR D1                  RHR System Flow                      0 to 110% design flow          2      0-5000 gpm            N/A    Vital UPS (4950 gpm)
RH-FT-618                                                                                                            FI-618                                A0950 RH-FT-619                                                                                                            FI-619                                A0952 D2                  RHR Heat Exchanger Outlet            40°F to 350°F                  2      50-400°F*              N/A    Vital UPS Temperature RH-TE-604                                                                                                                                TR-612            A0954 RH-TE-605                                                                                                                                TR-613            A0955 SAFETY INJECTION D3                  Accumulator Tank Level                10% to 90% volume              2 D4                  Accumulator Tank Pressure            0 to 750 psig                  2      0-700 psig*            N/A    Non-Vital PI-960 SI-PT-960                                                                                                  UPS      PI-962 SI-PT-962                                                                                                            PI-964 SI-PT-964                                                                                                            PI-966 SI-PT-966
 
SEABROOK                                                                                                                      Revision:                  17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                      Sheet:              12 of 37 TABLE 7.5-1 UFSAR SB DESIGN  ENVIRONMENTAL    SEISMIC ITEM NUMBER              VARIABLE CATEGORY            CATEGORY    QUALIFICATION    QUAL. QA  TRENDING REMARKS/NOTES C11                    Containment Pressure                1            Yes          Yes  Yes    N/A C12                    Containment Effluent              See E7 Radioactivity-Noble Gases from Identified Release Points C13                    Effluent Radioactivity Noble        3*          N/A          N/A  Yes    N/A
* See Deviation No. 9 in Appendix 7A.
Gases (inside buildings or areas where penetrations or hatches are located)
TYPE D VARIABLES, SYSTEM OPERATION RHR D1                    RHR System Flow                      2            Yes          N/A  Yes    N/A D2                    RHR Heat Exchanger Outlet            2            Yes          N/A  Yes    N/A
* See Deviation No. 22 in Appendix 7A.
Temperature SAFETY INJECTION D3                    Accumulator Tank Level*
* See Deviation No. 10 in Appendix 7A.
D4                    Accumulator Tank Pressure 2          2            Yes          N/A  Yes    N/A
* See Deviation No. 11 in Appendix 7A.
 
SEABROOK                                                                                                                  Revision:              17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                    Sheet:          13 of 37 TABLE 7.5-1 UFSAR DISPLAY MCR R.G. 1.97  R.G. 1.97 RECOMMENDED    DESIGN        ACTUAL                POWER                                            TSC, EOF ITEM NUMBER        VARIABLE/SENSOR                      RANGE    CATEGORY      RANGE      REDUNDANCY SUPPLY    VARIABLE            TREND INDICATION  COMPUTER D4A            Accumulator Vent Valve Position                                    Open/Closed    N/A    Vital DC SI-ZS-2475                                                                                          CS-2475-1                            D7361 SI-ZS-2476                                                                                          CS-2476                              D7362 SI-ZS-2482                                                                                          CS-2482-1                            D7364 SI-ZS-2483                                                                                          CS-2483                              D7365 SI-ZS-2477                                                                                          CS-2477-1                            D7366 SI-ZS-2486                                                                                          CS-2486                              D7367 SI-ZS-2495                                                                                          CS-2495-1                            D7368 SI-ZS-2496                                                                                          CS-2496                              D7369 D5            Accumulator Isolation Valve        Closed or open        2      Open/Closed        N/A    Vital UPS Position                                                        Open/Closed SI-ZS-2403-1                                                    Open/Closed                        ZL-2403-1 SI-ZS-2413-1                                                    Open/Closed                        ZL-2413-1 SI-ZS-2423-1                                                                                        ZL-2423-1 SI-ZS-2433-1                                                                                        ZL-2433-1 D6            Boric Acid Charging Flow          0 to 110% design      2      0-150 gpm          N/A    Vital UPS (0 to 85 gpm)
CS-FT-183                                                                                            FI-183A (Emergency Boration Flow)
D7            Flow in HPI System                0 to 110% design      2      0-800 gpm          N/A    Vital UPS (0 to 605 gpm)
SI-FT-918                          (0 to 715 gpm)                0-1000 gpm                          FI-918                                A0512 SI-FT-922                                                                                            FI-922                                A0514 SI-FT-917 (CS pump)                                                                                  FI-917                                A0510 D8            Flow in LPI System                0 to 110% design      2      See D1 D9            Refueling Water Storage Tank Level Top to bottom          2      See A6 RCS D10            Reactor Coolant Pump Status        Motor current          3      0-400 amps        N/A      N/A RC-AM-7300                        (330 FLA)                                                        AM-7300 RC-AM-7304                                                                                          AM-7304 RC-AM-7306                                                                                          AM-7306 RC-AM-7308                                                                                          AM-7308
 
SEABROOK                                                                                                        Revision:            17 INSTRUMENTATION AND CONTROLS STATION                                                                                                        Sheet:        14 of 37 TABLE 7.5-1 UFSAR SB DESIGN  ENVIRONMENTAL    SEISMIC ITEM NUMBER  VARIABLE CATEGORY          CATEGORY    QUALIFICATION    QUAL. QA  TRENDING REMARKS/NOTES D4A        Accumulator Vent Valve            2            Yes          N/A  Yes    N/A Position D5          Accumulator Isolation Valve      2            Yes          N/A  Yes    N/A Position D6          Boric Acid Charging Flow          3            N/A          N/A  Yes    N/A
* See Dev. No. 27 in Appendix 7A.
D7          Flow in HPI System                2            Yes          N/A  Yes    N/A D8          Flow in LPI System            See D1 D9          Refueling Water Storage Tank  See A6 Level D10        Reactor Coolant Pump Status      3            N/A          N/A  Yes    N/A
 
SEABROOK                                                                                                                              Revision:              17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                              Sheet:          15 of 37 TABLE 7.5-1 UFSAR DISPLAY MCR R.G. 1.97          R.G. 1.97 RECOMMENDED              DESIGN        ACTUAL                  POWER                                            TSC, EOF ITEM NUMBER        VARIABLE/SENSOR                      RANGE            CATEGORY        RANGE        REDUNDANCY SUPPLY  VARIABLE            TREND INDICATION  COMPUTER D11          Primary System Safety Relief Valve Closed-not closed                2      Closed-not closed    N/A Positions (including PORV and code safety valves)
RC-PCV-456A                                                                                            Vital DC CS-456-A1                            D4495 RC-PCV-456B                                                                                                      CS-456-B1                            D4496 VB-YE-6832-1                                                                                            Emerg  YM-6832-1                            D5791 VB-YE-6832-2                                                                                            MCC    YM-6832-2 D12          Pressurizer Level                  Top to bottom                    1      See A5 D13          Pressurizer Heater Status, Power  Electrical current              2      0-480 kW              N/A
* A0386 Monitor                                                                                                                                                A0387 A0388 A0389 D14          Pressurizer Relief Tank (Quench    Top to bottom                    3      0-100" W.C            N/A      N/A Tank) Level RC-LT-470                                                                                                        LI-470                                A0347 D15          Pressurizer Relief Tank (Quench    50°F to 750°F                    3      50-350°F*            N/A      N/A    TI-468                                A0376 Tank) Temperature RC-TE-468 D16          Pressurizer Relief Tank (Quench    0 to design pressure 3      0-100 psig N/A                  N/A            PI-469                                A0348 Tank) Pressure                    (0-100 psig)
RC-PT-469 SECONDARY D17          Steam Generator Level              From tube sheet to              1      See A4 separators D18          Steam Generator Pressure          From atmospheric                2      See A2 pressure to 20% above the lowest safety valve setting (1425 psig)
 
SEABROOK                                                                                                          Revision:                            17 INSTRUMENTATION AND CONTROLS STATION                                                                                                          Sheet:                    16 of 37 TABLE 7.5-1 UFSAR SB DESIGN  ENVIRONMENTAL    SEISMIC ITEM NUMBER  VARIABLE CATEGORY          CATEGORY    QUALIFICATION    QUAL. QA  TRENDING REMARKS/NOTES D11        Primary System Safety Relief    2            Yes          Yes  Yes    N/A  Stem-mounted limit switches provide position indication for the PORVs. Acoustic Valve Positions(including                                                      Monitoring System Monitors status of both the PORVs and the safeties.
PORV and code safety valves)
D12        Pressurizer Level              See A5 D13        Pressurizer Heater Status,      2            Yes          N/A  Yes    N/A
* Watts transducer powered by sensing circuit Power Monitor D14        Pressurizer Relief              3            N/A          N/A  Yes    N/A Tank(Quench Tank) Level D15        Pressurizer Relief              3            N/A          N/A  Yes    N/A
* See Deviation No. 12 in Appendix 7A.
Tank(Quench Tank)
Temperature D16        Pressurizer Relief              3            N/A          N/A  Yes    N/A Tank(Quench Tank) Pressure SECONDARY D17        Steam Generator Level          See A4 D18        Steam Generator Pressure      See A2
 
SEABROOK                                                                                                                          Revision:              17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                            Sheet:          17 of 37 TABLE 7.5-1 UFSAR DISPLAY MCR R.G. 1.97    R.G. 1.97 RECOMMENDED        DESIGN        ACTUAL                  POWER                                              TSC, EOF ITEM NUMBER            VARIABLE/SENSOR                    RANGE        CATEGORY        RANGE        REDUNDANCY SUPPLY    VARIABLE              TREND INDICATION  COMPUTER D19              Safety-Relief Valve Position or  Closed-not closed        2      Closed-not closed    N/A    Emerg Main Steam Flow                                                                                  MCC VB-YE-6820 (SG #4)                                                                                      YM-6820                                D5788 VB-YE-6821 (SG #3)                                                                                      YM-6821 VB-YE-6822 (SG #2)                                                                                      YM-6822 VB-YE-6823 (SG #1)                                                                                      YM-6823 D20              Main Feedwater Flow              0 to 110% design flow    3      0-5x106 Lb/hr per    N/A      N/A (0-4.2x106 lb/hr)                SG FW-FT-510 (SG #1)                                                                                        FI-510A              FR-510            A0728 FW-FT-520 (SG #2)                                                                                        FI-520A              FR-520            A0738 FW-FT-530 (SG #3)                                                                                        FI-530A              FR-530            A0748 FW-FT-540 (SG #4)                                                                                        FI-540A              FR-540            A0718 EMERGENCY FEEDWATER D21              Auxiliary or Emergency Feedwater 0 to 110% design flow    2      0-600 gpm            N/A    Vital UPS Flow                            (0 to 390 gpm)
FW-FT-4214-2 (SG #1)                                                                                    FI-4214-2            FR-4214          A0795 FW-FT-4224-2 (SG #2)                                                                                    FI-4224-2            FR-4224          A0796 FW-FT-4234-2 (SG #3)                                                                                    FI-4234-2            FR-4214          A0797 FW-FT-4244-2 (SG #4)                                                                                    FI-4244-2            FR-4224          A0798 D22              Condensate Storage Tank Water    Plant specific Level FW-LT-4252                                                1      (10.36-408.7)        Yes    Vital UPS LI-4252                                A0704 FW-LT-4257                                                        x103 gallons                          LI-4257                                A0706 CONTAINMENT COOLING D23              Containment Spray Flow          0 to 110% design flow    2 (3400 gpm)
Containment Spray Pump Suction Pressure CBS-PT-2312                                                      0-60 psig*            N/A    Non-Vital CBS-PT-2314                                                                                      UPS Containment Spray Pump Discharge                                                                        PI-2312                                A0922 Pressure                                                                                                PI-2314                                A0924 CBS-PT-2313                                                      0-500 psig*          N/A    Non-Vital PI-2313                                A0923 CBS-PT-2315                                                                                      UPS    PI-2315                                A0925 D24              Heat Removal by the Containment  Plant-specific            2 Fan Heat Removal System*
 
SEABROOK                                                                                                                    Revision:                            17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                    Sheet:                    18 of 37 TABLE 7.5-1 UFSAR SB DESIGN  ENVIRONMENTAL    SEISMIC ITEM NUMBER          VARIABLE CATEGORY            CATEGORY    QUALIFICATION    QUAL. QA  TRENDING REMARKS/NOTES D19                Safety-Relief Valve Position or    2            Yes          N/A  Yes    N/A  Acoustic Monitoring System Monitors position of the SG safeties.
Main Steam Flow D20                Main Feedwater Flow                3            N/A          N/A  Yes    N/A EMERGENCY FEEDWATER D21                Auxiliary or Emergency              2            Yes          N/A  Yes    N/A Feedwater Flow D22                Condensate Storage Tank            1            Yes          Yes  Yes    N/A
* CST Level is sensed at the EFW pump suction.
Water Level CONTAINMENT COOLING D23                Containment Spray Flow              2            Yes          N/A  Yes    N/A
* See Deviation No. 13 in Appendix 7A.
Containment Spray Pump Suction Pressure Containment Spray Pump              2            Yes          N/A  Yes    N/A Discharge Pressure D24                Heat Removal by the
* See Deviation No. 25 in Appendix 7A.
Containment Fan Heat Removal System*
 
SEABROOK                                                                                                                    Revision:                17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                      Sheet:            19 of 37 TABLE 7.5-1 UFSAR DISPLAY MCR R.G. 1.97      R.G. 1.97 RECOMMENDED        DESIGN      ACTUAL                POWER                                                TSC, EOF ITEM NUMBER          VARIABLE/SENSOR                    RANGE        CATEGORY      RANGE    REDUNDANCY SUPPLY    VARIABLE                TREND INDICATION  COMPUTER D25              Containment Atmosphere          40°F to 400°F            2        50-420°F*      N/A    Vital UPS RC-XX-7315-1,2&3(4)                      Available Temperature RC-TE-1313                                                                                                                      Through Data Link D26              Containment Sump Water          50°F to 250°F            2        32-1599°F      N/A    Non-Vital                                          A0091 Temperature*                                                                              UPS                                              A0092 CBS-TE-2378 & 2379 CHEMICAL AND VOLUME CONTROL D27              Makeup Flow-in                  0 to 110% design flow    2        0-200 gpm      N/A      N/A CS-FT-121                      (150 gpm)                                                          FI-121A                                  A0622 D28              Letdown Flow-out                0 to 110% design flow    2        0-200 gpm      N/A      N/A CS-FT-132                      (135 gpm)                                                          FI-132                                  A0620 D29              Volume Control Tank Level      Top to bottom (141")      2          0-80"*      N/A      N/A CS-LT-185                                                                                          LI-185                LR-185 CS-LT-112                                                                                          LI-112                                  A0624 COOLING WATER D30              Component Cooling Water        40°F to 200°F            2        0-175°F*      N/A    Vital UPS Temperature to ESF CC-TE-2171                                                                                        TI-2171-1                                A0271 CC-TE-2271                                                                                        TI-2271-1                                A0269 D31              Component Cooling Water Flow to 0 to 110% design flow    2      0-13,000 gpm    N/A    Non-Vital ESF System                      (11,500 gpm)                                              UPS CC-FT-2103                                                                                        FI-2103                                  A0273 CC-FT-2203                                                                                        FI-2203                                  A0272 D31a              RHR and CBS Heat Exchanger PCCW Outlet Valves CC-V266                                                          Closed/Open    N/A    Emerg. CS-2245                                  D7823 CC-V272                                                                                    MCC    CS-2244                                  D7824 CC-V137                                                                                            CS-2145                                  D7821 CC-V145                                                                                            CS-2144                                  D7822 D32              Cooling Tower Sump Level                                            0-50 FT      N/A    Vital UPS SW-LT-6129                                                                                        LI-6129                LR-6129          A1537 SW-LT-6139                                                                                        LI-6139
 
SEABROOK                                                                                                              Revision:                  17 INSTRUMENTATION AND CONTROLS STATION                                                                                                              Sheet:              20 of 37 TABLE 7.5-1 UFSAR SB DESIGN  ENVIRONMENTAL    SEISMIC ITEM NUMBER            VARIABLE CATEGORY        CATEGORY    QUALIFICATION    QUAL. QA  TRENDING REMARKS/NOTES D25                  Containment Atmosphere        2            Yes          N/A  Yes    N/A
* See Deviation No. 14 in Appendix 7A.
Temperature D26                  Containment Sump Water        2            Yes          N/A  Yes    N/A
* See Deviation No. 15 in Appendix 7A.
Temperature*
CHEMICAL AND VOLUME CONTROL D27                  Makeup Flow-In                3*          N/A          N/A  Yes    N/A
* See Deviation No. 16 in Appendix 7A.
D28                  Letdown Flow-Out              3*          N/A          N/A  Yes    N/A
* See Deviation No. 17 in Appendix 7A.
D29                  Volume Control Tank Level      3*          N/A          N/A  Yes    N/A
* See Deviation No. 18 in Appendix 7A.
COOLING WATER D30                  Component Cooling Water        2            Yes          N/A  Yes    N/A
* See Deviation No. 19 in Appendix 7A.
Temperature to ESF D31                  Component Cooling Water        2            Yes          N/A  Yes    N/A Flow to ESF System D31a                RHR and CBS Heat Exchanger    2            Yes          N/A  Yes    N/A PCCW Outlet Valves D32                  Cooling Tower Sump Level      2            Yes          N/A  Yes    N/A
 
SEABROOK                                                                                                                        Revision:              17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                          Sheet:          21 of 37 TABLE 7.5-1 UFSAR DISPLAY MCR R.G. 1.97          R.G. 1.97 RECOMMENDED            DESIGN        ACTUAL                    POWER                                              TSC, EOF ITEM NUMBER        VARIABLE/SENSOR                RANGE            CATEGORY        RANGE        REDUNDANCY SUPPLY    VARIABLE              TREND INDICATION  COMPUTER D32a          Service Water Flow to DG Heat                                      0-3500 gpm            N/A    Non- Vital FI-6181 Exchanger                                                                                          UPS SW-FT-6181                                                                                      Vital UPS  FI-6191 SW-FT-6191 D32b          Cooling Tower Pump Discharge                                      0-150°F              N/A    Non-Vital Temperature                                                                                        UPS SW-TE-6184                                                                                                TI-6184                                A1503 SW-TE-6194                                                                                                TI-6194                                A1505 RADWASTE D33          High-Level Radioactive Liquid Top to bottom (18 feet)      3      0-14 FT*              N/A      N/A (Floor Drain) Tank Level WL-LT-1462 (TK-59A)                                                                                        LI-1462                                A1285 WL-LT-1466 (TK-59B)                                                                                        LI-1466 D34          Radioactive Gas Holdup Tank  0 to 150% design pressure    3 Pressure*
VENTILATION 2      Closed-not closed N/A        Vital UPS D35          Emergency Ventilation        Open-closed status                                                  Emerg.
Damper Position                                                                                    MCC PAH-DP-35A                                                                                                ZL-5370-3 PAH-DP-35B                                                                                                ZL-5371-3 PAH-DP-36A                                                                                                ZL-5370-4 PAH-DP-36B                                                                                                ZL-5371-4 EAH-DP-30A                                                                                                ZL-5780-2 EAH-DP-30B                                                                                                ZL-5784-2 CAH-DP-34A                                                                                                ZL-5630-2 CAH-DP-34B                                                                                                ZL-5631-2 CAH-DP-34C                                                                                                ZL-5634 CAH-DP-34D                                                                                                ZL-5635 CBA-DP-53A                                                                                                CS-5331 CBA-DP-53B                                                                                                CS-5329 CBA-DP-27A                                                                                                CS-5318                                D5142 CBA-DP-27B                                                                                                CS-5320                                D5147 CBA-DP-28                                                                                                  ZL-5332                                D5148 CBA-DP-1058                                                                                                ZL-1058                                D5149
 
SEABROOK                                                                                                                                  Revision:                    17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                                  Sheet:                  22 of 37 TABLE 7.5-1 UFSAR DISPLAY MCR R.G. 1.97            R.G. 1.97 RECOMMENDED              DESIGN          ACTUAL                    POWER                                                      TSC, EOF ITEM NUMBER        VARIABLE/SENSOR                RANGE              CATEGORY          RANGE      REDUNDANCY    SUPPLY      VARIABLE                    TREND INDICATION  COMPUTER D35a          Fan Status: Control Room Makeup                                        Running/        N/A            Emerg.
Air Fans                                                                not Running                      MCC CBA-FN-27A                                                                                                          CS-5328                                      D7034 CBA-FN-27B                                                                                                          CS-5330                                      D7035 CBA-FN-16A                                                                                                          ZL-5365                                      D7017 CBA-FN-16B                                                                                                          ZL-5320-2                                    D7006 CBA-FN-15                                                                                                          ZL-5310                                      D7036 SB DESIGN        ENVIRONMENTAL        SEISMIC ITEM NUMBER        VARIABLE CATEGORY          CATEGORY          QUALIFICATION        QUAL.        QA      TRENDING REMARKS/NOTES D32a          Service Water Flow to DG Heat      2                  Yes              N/A        Yes        N/A Exchanger D32b          Cooling Tower Pump Discharge        2                  Yes              N/A        Yes        N/A Temperature RADWASTE D33            High-Level Radioactive Liquid      3                  N/A              N/A        Yes        N/A
* See Deviation No. 20 in Appendix 7A.
(floor drain) Tank Level D34            Tank Pressure*
* See Deviation No. 26 in Appendix 7A.
VENTILATION D35            Emergency Ventilation Damper        2                  Yes              N/A        Yes        N/A Position D35a          Fan Status: Control Room Makeup    2                  Yes              N/A        Yes        N/A Air Fans
 
SEABROOK                                                                                                      Revision:                17 INSTRUMENTATION AND CONTROLS STATION                                                                                                        Sheet:              23 of 37 TABLE 7.5-1 UFSAR DISPLAY MCR R.G. 1.97  R.G. 1.97 RECOMMENDED  DESIGN        ACTUAL            POWER                                                TSC, EOF ITEM NUMBER        VARIABLE/SENSOR              RANGE    CATEGORY        RANGE REDUNDANCY SUPPLY    VARIABLE                TREND INDICATION  COMPUTER D35b          Containment Enclosure Temperature                        30-220°F      N/A    Vital UPS MM-TE-1002A                                                                              RC-XX-7315-1,2&3(4)                      Available MM-TE-1002B                                                                              RC-XX-7315-4(4)                          Through Data Link D35c          Primary Auxiliary Building                                30-220°F      N/A    Vital UPS Temperature MM-TE-1003A                                                                              RC-XX-7315-1,2&3(4)                      Available MM-TE-1003B                                                                              RC-XX-7315-4(4)                          Through Data Link D35d          Diesel Generator Building                                0-200°F        N/A    Non-Vital Temperature                                                                      UPS DAH-TE-5688                                                                              TI-5688                                  D6975 DAH-TE-5689                                                                              TI-5689                                  D6977 D6979 D35e          Service Water Pumphouse                                  0-140°F*      N/A      N/A Temperature SWA-TSHL 5612 SWA-TSHL 5608 SWA-TSHL 5609 D35f          Cooling Tower Switchgear Area                            0-140°F*      N/A      N/A Temperature SWA-TSHL 5699                                                                                                                      D6993 SWA-TSHL 5693                                                                                                                      D6989 SWA-TSHL 5696                                                                                                                      D6991 D35g          Emergency Feedwater Pumphouse                            0-140°F*      N/A      N/A Temperature EPA-TSH-5434                                                                                                                      D7980 D35h          Control Building Temperature                              30°-110°F*    N/A      N/A CBA-TSHL-5180                                                                                                                      D7022 CBA-TSHL-5181                                                                                                                      D7023 CBA-TSHL-5182                                                                                                                      D7026 CBA-TSHL-5580                                                                                                                      D7027 CBA-TSHL-5581                                                                                                                      D7028
 
SEABROOK                                                                                                                                Revision:                    17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                                  Sheet:                24 of 37 TABLE 7.5-1 UFSAR DISPLAY MCR R.G. 1.97            R.G. 1.97 RECOMMENDED              DESIGN          ACTUAL                  POWER                                                      TSC, EOF ITEM NUMBER        VARIABLE/SENSOR                  RANGE              CATEGORY          RANGE      REDUNDANCY  SUPPLY      VARIABLE                    TREND INDICATION  COMPUTER D35i          Containment Enclosure Emergency                                          0-4000 ACFM        N/A    Non-Vital Exhaust Fan Discharge Flow                                                                              UPS EAH-FIT-5791                                                                                                      FR-5791                    FR-5791          A3777 D35j          Control Building Temperature CBA-TE-8630                                                              30°-110°F          N/A        N/A      A0176 (B6543)
CBA-TE-8631                                                                                  N/A        N/A      A0177 (B6686)
SB DESIGN      ENVIRONMENTAL        SEISMIC ITEM NUMBER        VARIABLE CATEGORY            CATEGORY        QUALIFICATION        QUAL.        QA    TRENDING REMARKS/NOTES D35b          Containment Enclosure Temperature    2                Yes              N/A        Yes      N/A D35c          Primary Auxiliary Building            2                Yes              N/A        Yes      N/A Temperature D35d          Diesel Generator Building            2                Yes              N/A        Yes      N/A Temperature D35e          Service Water Pumphouse              2                Yes              N/A        Yes      N/A
* High Temperature alarm provided Temperature D35f          Cooling Tower Switchgear Area        2                Yes              N/A        Yes      N/A
* High Temperature alarm provided Temperature D35g          Emergency Feedwater Pumphouse        2                Yes              N/A        Yes      N/A
* High Temperature alarm provided Temperature D35h          Control Building Temperature          2                Yes              N/A        Yes      N/A
* High Temperature alarm provided D35i          Containment Enclosure Emergency      2                Yes              N/A        Yes      N/A Exhaust Fan Discharge Flow D35j          Control Building Temperature          3                No              N/A        Yes      N/A
* High Temperature alarm provided
 
SEABROOK                                                                                                              Revision:              17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                Sheet:          25 of 37 TABLE 7.5-1 UFSAR DISPLAY MCR R.G. 1.97  R.G. 1.97 RECOMMENDED      DESIGN        ACTUAL                POWER                                            TSC, EOF ITEM NUMBER        VARIABLE/SENSOR                  RANGE    CATEGORY      RANGE    REDUNDANCY  SUPPLY    VARIABLE            TREND INDICATION  COMPUTER POWER SUPPLIES D36            Status of Standby Power 4160 Emergency Bus Availability Plant-specific        2      0-5000V          N/A        N/A EDE-VTR-9708                                                                                      VM-9708                              A2306 EDE-VTR-9718                                                                                      VM-9718                              A2309 480 Emergency Bus Availability  Plant-specific        2      0-600V            N/A        N/A EDE-VTR-9784-1,-2,-3                                                                              VM-9784 EDE-VTR-9785-1,-2,-3,-4                                                                          VM-9785 125V DC                        Plant-specific        2      0-150V DC        N/A    Vital UPS EDE-VTR-9750                                                                                      VM-9750                              A2052 EDE-VTR-9752                                                                                      VM-9752                              A2055 EDE-VTR-9754                                                                                      VM-9754                              A2058 EDE-VTR-9756                                                                                      VM-9756                              A2061 120V AC Vital Bus Voltage      Plant-specific        2      0-150V            N/A        N/A Vital Bus 1A                                                                                                                          A1816 Vital Bus 1B                                                                                                                          A1817 Vital Bus 1C                                                                                                                          A1818 Vital Bus 1D                                                                                                                          A1819 Vital Bus 1E                                                                                                                          A4851 Vital Bus 1F                                                                                                                          A4852 Emergency Diesel Generator      Plant-specific        2      VM 0-5000V    N/A        Emerg.
EDE-VTR-9700-1 (DG A)                                        FM 55-65 Hz              MCC        VM-9700-1          XR-9700A          A2712 EDE-FTR-9700-3                                                AM 0-2000 amp                      FM-9700-3          XR-9700B          A2713 EDE-ATR-9700-1                                                WM 0-9000 KW                        AM-9700-1          XR-9700A          A2714 EDE-WTR-9700-3                                                                                    WM-9700-3          XR-9700B          A2715 EDE-VTR-9710-1 (DG B)                                                                            VM-9710-1          XR-9710A          A2732 EDE-FTR-9710-3                                                                                    FM-9710-3          XR-9710B          A2733 EDE-ATR-9710-1                                                                                    AM-9710-1          XR-9710A          A2734 EDE-WTR-9710-3                                                                                    WM-9710-3          XR-9710B          A2735
 
SEABROOK                                                                                              Revision:      17 INSTRUMENTATION AND CONTROLS STATION                                                                                              Sheet:    26 of 37 TABLE 7.5-1 UFSAR SB DESIGN ENVIRONMENTAL    SEISMIC ITEM NUMBER  VARIABLE CATEGORY        CATEGORY  QUALIFICATION    QUAL. QA  TRENDING REMARKS/NOTES D36        Status of Standby Power 4160 Emergency Bus            2          Yes          N/A  Yes    N/A Availability 480 Emergency Bus              2          Yes          N/A  Yes    N/A Availability 125V DC                        2          Yes          N/A  Yes    N/A 120V AC                        2          Yes          N/A  Yes    N/A Emergency Diesel Generator    2          Yes          N/A  Yes    N/A
 
SEABROOK                                                                                                                              Revision:              17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                                Sheet:          27 of 37 TABLE 7.5-1 UFSAR DISPLAY MCR R.G. 1.97        R.G. 1.97 RECOMMENDED          DESIGN        ACTUAL                POWER                                            TSC, EOF ITEM NUMBER            VARIABLE/SENSOR                      RANGE          CATEGORY        RANGE    REDUNDANCY SUPPLY    VARIABLE            TREND INDICATION  COMPUTER COMBUSTIBLE GAS CONTROL D37                Hydrogen Recombiner:                                                  0-100 KW            N/A    Emerg. Wattmeter on Heater Power                                                                                        MCC    MCB-G(rear)
TYPE E VARIABLES, RELEASE ASSESSMENT CONTAINMENT RADIATION E1                  Containment Area Radiation        1 R/hr to 107 R/hr          1      1 to 108 R/hr      Yes    Vital UPS RM-RE-6576 A                                                                                                RK-6576A            RR-6576A          Available RM-RE-6576 B                                                                                                RI-6576A            RR-6576B          Through Data RK-6576B                              Link RI-6576B AREA RADIATION E2                  Radiation Exposure Rate (inside    10-1 R/hr to 104 R/hr        3      10-2 to104 R/hr    N/A      N/A    1-MM-CP-295        1-MM-CP-295      Available buildings or areas where access is                                                                                                                Through Data required to service equipment                                                                                                                    Link important to safety)
RM-RE-6508-1, -2 (PAB High Range)
RM-RE-6563-1, -2 (PAB High Range)
RM-RE-6517-1, -2 (RHR Pump vault 1&2 High Range)
RM-RE-6518 (Spent Fuel High Range)
NOBLE GASES E3                  Containment or Purge Effluent      10-6 Ci/cc to105 Ci/cc    2      See E7 (not needed if effluent discharges through common plant vent) 0 to 110% flow E4                  Reactor Shield Building Annulus    10-6 Ci/cc to104 Ci/cc    2      See E7 (not needed if effluent discharges through common plant vent) 0 to 110% flow
 
SEABROOK                                                                                                                            Revision:                          17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                            Sheet:                    28 of 37 TABLE 7.5-1 UFSAR SB DESIGN  ENVIRONMENTAL    SEISMIC ITEM NUMBER              VARIABLE CATEGORY            CATEGORY    QUALIFICATION    QUAL. QA  TRENDING REMARKS/NOTES COMBUSTIBLE GAS CONTROL D37                    Hydrogen Recombiner: Heater          2            Yes          N/A  Yes    N/A Power TYPE E VARIABLES, RELEASE ASSESSMENT CONTAINMENT RADIATION E1                    Containment Area Radiation          1            Yes          Yes  Yes    N/A AREA RADIATION E2                    Radiation Exposure Rate              3            N/A          N/A  Yes    N/A  The high-range monitors have been installed to monitor the entrances to the PAB and RHR (inside buildings or areas where                                                  pump vault. The spent fuel pool area is also monitored with a high- range detector.
access is required to service                                                      Individual cubicles are not monitored. Portable instruments will be used for entry into high equipment important to safety)                                                    radiation areas (real or suspected).
NOBLE GASES E3                    Containment or Purge Effluent      See E7                                          Discharge through plant vent stack.
E4                    Reactor Shield Building            See E7                                          Discharges through plant vent stack.
Annulus
 
SEABROOK                                                                                                                          Revision:              17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                            Sheet:          29 of 37 TABLE 7.5-1 UFSAR DISPLAY MCR R.G. 1.97        R.G. 1.97 RECOMMENDED            DESIGN        ACTUAL                  POWER                                          TSC, EOF ITEM NUMBER        VARIABLE/SENSOR                      RANGE          CATEGORY        RANGE        REDUNDANCY SUPPLY  VARIABLE            TREND INDICATION  COMPUTER E5            Auxiliary Building (including any  10-6 Ci/cc to 103 Ci/cc    2            See E7 building containing primary system (not needed if effluent gases, e.g., waste gas decay tank) discharges through common plant vent) 0 to 110% flow E6            Condenser Air Removal System      10-6 Ci/cc to 105 Ci/cc    2            See E7 Exhaust                            (not needed if effluent discharges through common plant vent) 0 to 110% flow E7            Common Plant Vent or              10-6 Ci/cc to 104 Ci/cc    2      10-7 to 105 Ci/cc    N/A    Emerg.
Multipurpose Vent Discharging Any                                                                      MCC                      RR-6528-1        Available of Above Releases (if containment  0 to 110% flow                2      0 to 3.5x                            RK-6528            RR-6528-2        Through Data purge is included)                (0 to 2x105 scfm)                    105 scfm                              1-MM-CP-295                          Link RM-RE-6528-1, -2, -3 RM-FT-6577-1, -2 E8            Vent From Steam Generator Safety  10-1 Ci/cc to 103 Ci/cc    2      1 to 105 mr/hr*        N/A    Emerg.
Relief Valves or Atmospheric Dump  (Duration of releases in                                            MCC Valves                            seconds and mass of steam RM-RE-6481-1,2;                    per unit time)                                                            1-MM-CP-295        1-MM-CP-295      Available 6482-1, 2                                                                                                                                          Through Data Link Safety/Relief Valve                See D19 Position YE-6820 YE-6821 YE-6822 YE-6823 E9            All Other Identified Plant Release Points*
 
SEABROOK                                                                                                                Revision:                            17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                Sheet:                    30 of 37 TABLE 7.5-1 UFSAR SB DESIGN  ENVIRONMENTAL    SEISMIC ITEM NUMBER  VARIABLE CATEGORY            CATEGORY    QUALIFICATION    QUAL. QA  TRENDING REMARKS/NOTES E5          Auxiliary Building(including      See E7                                          Discharges through plant vent stack.
any building containing primary system gases, e.g., waste gas decay tank)
E6          Condenser Air Removal            See E7                                          Discharges through plant vent stack.
System Exhaust E7          Common Plant Vent or                2            Yes          N/A  Yes    Yes  Flow element provides a signal to the radiation monitors to permit the radiation monitors to Multipurpose Vent Discharging                                                    calculate the microcuries per cubic centimeter flowing in the duct and microcuries per Any of Above Releases (if                                                        second released through the plant vent stack.
containment purge is included)
E8          Vent from Steam Generator          2            Yes          N/A  Yes    Yes
* Correlation from mr/hr to Ci/cc is included in the procedure for offsite dose Safety Relief Valves or                                                                  assessment. Direct readout in Ci/cc is not required to support this procedure. The Atmospheric Dump Valves                                                                  safety/relief valve position monitors can be used to determine the existence of flow through these valves.
E9          All Other Identified Plant
* None Identified.
Release Points*
 
SEABROOK                                                                                                                                  Revision:              17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                                  Sheet:          31 of 37 TABLE 7.5-1 UFSAR DISPLAY MCR R.G. 1.97          R.G. 1.97 RECOMMENDED            DESIGN          ACTUAL                  POWER                                        TSC, EOF ITEM NUMBER            VARIABLE/SENSOR                          RANGE            CATEGORY          RANGE      REDUNDANCY  SUPPLY VARIABLE          TREND INDICATION  COMPUTER PARTICULATES AND HALOGENS E10                All Identified Plant Release Points  10-3 Ci/cc to 102 Ci/cc      3      10-3 Ci/cc to 1    N/A      N/A  N/A              N/A              N/A (except steam generator safety relief                                        02 Ci/cc valves or atmospheric steam dump valves and condenser air removal system exhaust). Sampling with        0 to 110% flow                          0 to 3.5x            N/A      N/A  1-MM-CP-295      1-MM-CP-295      Available Onsite Analysis Capability.          (0 to 2x105 scfm)                      105 scfm                                                                Through Data RM-SKD-53-2                                                                                                                                          Link E12                Airborne Radiohalogens and            10-9 Ci/cc to 10-3 Ci/cc      3      10-9 Ci/cc          N/A      N/A  N/A Particulates (portable sampling with                                          to 10-3Ci/cc onsite analysis capability) Air Samplers: Low Volume High Volume Personnel Continuous air Monitor E13                Plant and Environs                    10-3 R/Hr to                    3      0-1 R/Hr        N/A        N/A    N/A              N/A              N/A Radiation (portable                  104 R/Hr photons                        beta/gamma instrumentation)                      10-3 rads/hr to                        0-1.000 R/Hr                N/A    N/A              N/A              N/A Ion Chamber                          104 rads/hr, beta                      gamma (Low Range)                          radiations and low-        Up to 10,000                  N/A        N/A    N/A              N/A Ion Chamber                          energy photons                          R/Hr gamma (Mid Range)                                                                  0-50,000 CPM                N/A    N/A              N/A              N/A Ion Chamber                                                                  beta/gamma (High Range)                                                                  0-200 MR/Hr                N/A    N/A              N/A              N/A Geiger Mueller                                                                beta/gamma Detector                                                                      0-500,000 CPM              N/A    N/A              N/A              N/A Geiger Mueller                                                                alpha Detector                                                                      0.001-10 R/Hr              N/A    N/A              N/A              N/A Alpha Scintillation                                                          neutron Tele-detector Rate Detector E14                Plant and Environs                    (Isotopic analysis)            3      Multichannel    N/A        N/A    N/A              N/A              N/A Radioactivity(portable                                                        gamma-ray instrumentation)                                                              spectrometer
 
SEABROOK                                                                                                                            Revision:                        17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                              Sheet:                32 of 37 TABLE 7.5-1 UFSAR SB DESIGN  ENVIRONMENTAL      SEISMIC ITEM NUMBER            VARIABLE CATEGORY              CATEGORY    QUALIFICATION      QUAL. QA  TRENDING REMARKS/NOTES PARTICULATES AND HALOGENS E10                  All Identified Plant Release      3        N/A              N/A        Yes N/A Points (except steam generator safety relief valves or atmospheric steam dump valves and condenser air removal system exhaust). Sampling with Onsite analysis Capability.
E12                  Airborne Radiohalogens and        3        N/A              N/A        Yes N/A Particulates (portable sampling with on-site analysis capability)
E13                  Plant and Environs Radiation      3        N/A              N/A        Yes N/A (portable instrumentation)
E14                  Plant and Environs activity      3        N/A              N/A        Yes N/A      Function provided by gamma spectroscopy system located in the Counting Room. Portable (portable instrumentation)                                                            air sampler used to obtain the air samples.
 
SEABROOK                                                                                                                          Revision:              17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                          Sheet:          33 of 37 TABLE 7.5-1 UFSAR DISPLAY MCR R.G. 1.97          R.G. 1.97 RECOMMENDED              DESIGN    ACTUAL                      POWER                                        TSC, EOF ITEM NUMBER              VARIABLE/SENSOR                  RANGE            CATEGORY  RANGE            REDUNDANCY SUPPLY VARIABLE            TREND INDICATION  COMPUTER PARTICULATES AND HALOGENS METEOROLOGY E15                Wind Direction43 feet above    0 to 360° (+/-5° accuracy        3      0-540°              N/A      N/A  Computer          Computer          A1630 grade209 feet above grade      with a deflection of                  Accuracy: +/-5°                                                          A1627 10°).Starting speed less              Threshold:
than 0.4 mps (1.0 mph)                < 1 mph Damping Damping ratio greater than            Ratio:  0.4*
or equal to 0.4,delay                  Delay Distance:
distance less than or equal            2 meters*
to 2 meters.
E16                Wind Speed 43 feet above grade 0 to 22 mps (50 mph).          3      0-100 mph            N/A      N/A  Computer          Computer          A1628 209 feet above grade          +/-0.2 mps (0.5 mph)                    Accuracy:                                                              A1626 accuracy for speeds less                +/- .5 mph @
than 2 mps (5 mph),                    < 5 mph  10%
10% for speeds in excess              @ > 5 mph of 2 mps (5 mph), with a              Threshold:
starting threshold of less              1 mph Distance than 0.4 mps (1.0 mph)                Constant:
and a distance constant not            < 2 meters*
to exceed 2 meters.
E17                Estimation of Atmospheric      Based on vertical              3      -10&deg;F to 18&deg;F        N/A      N/A  Computer          Computer          A1632 Stability150-43 feet (delta-T) Temperature difference                Accuracy:                                                              A1631 209-43 feet (delta-T)          from primary                            +/-0.2&deg;F meteorological system,
                                                  -5&deg;C to 10&deg;C (-9&deg;F to 18&deg;F) and +/-0.15&deg;C accuracy per 50-meter intervals (+/-0.3&deg;F accuracy per 164-foot intervals) or analogous range for alternative stability estimate.
 
SEABROOK                                                                                                      Revision:                            17 INSTRUMENTATION AND CONTROLS STATION                                                                                                      Sheet:                    34 of 37 TABLE 7.5-1 UFSAR SB DESIGN  ENVIRONMENTAL    SEISMIC ITEM NUMBER  VARIABLE CATEGORY      CATEGORY    QUALIFICATION    QUAL. QA  TRENDING REMARKS/NOTES E15        Wind Direction                3            N/A          N/A  Yes    Yes  Communication with the National Weather Service is available by telephone.
* See Deviation No. 28 in Appendix 7A.
E16        Wind Speed                    3            N/A          N/A  Yes    Yes  Communication with the National Weather Service is available by telephone.
* See Deviation No. 29 in Appendix 7A E17        Estimation of Atmospheric    3            N/A          N/A  Yes    Yes  Communication with the National Weather Service is available by telephone.
Stability
 
SEABROOK                                                                                                                                        Revision:                      17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                                        Sheet:                  35 of 37 TABLE 7.5-1 UFSAR DISPLAY MCR R.G. 1.97            R.G. 1.97 RECOMMENDED                DESIGN        ACTUAL                            POWER                                                      TSC, EOF ITEM NUMBER            VARIABLE/SENSOR            RANGE                CATEGORY        RANGE              REDUNDANCY    SUPPLY      VARIABLE                    TREND INDICATION  COMPUTER ACCIDENT SAMPLING CAPABILITY E18                Primary Coolant and Sump Grab sample                      3                                    N/A        N/A        N/A                        N/A              N/A Gross Activity          1 Ci/ml to                                  1 Ci/ml to 10 Ci/ml                                      10 Ci/ml Gamma Spectrum          (Isotopic Analysis)                          Isotopic Analysis Boron Content            0 to 6000 ppm                                0 to 6000 ppm Chloride Content        0 to 20 ppm                                  0 to 20 ppm Dissolved Hydrogen      0 to 2000cc (STP)/KG                          0 to 2000cc (STP)/KG Dissolved Oxygen        0 to 20 ppm
* pH                      1 to 13                                      1 to 13 E19                Containment Air          Grab sample                      3                                    N/A        N/A        N/A                        N/A              N/A Hydrogen Content        0 to 10%                                      0 to 10%
Oxygen Content          0 to 30%                                      0 to 30%
Gamma Spectrum          (Isotopic analysis)                          (Isotopic analysis)
SB DESIGN          ENVIRONMENTAL          SEISMIC ITEM NUMBER            VARIABLE CATEGORY    CATEGORY            QUALIFICATION          QUAL.            QA    TRENDING REMARKS/NOTES ACCIDENT SAMPLING CAPABILITY E18                Primary Coolant and Sump 3                N/A                    N/A                Yes    N/A
* See Deviation No. 21 in Appendix 7A.
E19                Containment Air          3                N/A                    N/A                Yes    N/A
 
SEABROOK                                                                                                                                                                              Revision:                            17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                                                                                Sheet:                    36 of 37 TABLE 7.5-1 UFSAR LIST DATA TABLE LEGEND AND NOTES Abbreviations:                                                                                                            G. Under the "Seismic Qualification" column:
EOF                      Emergency Operations Facility                                                                      "Yes" means that the instrumentation has been seismically qualified in accordance with the criteria stated in MCC                      Motor Control Center                                                                              Subsection 7.5.6.
MCR                      Main Control Room                                                                                  For Design Category 2 and 3 instruments, "N/A" is entered since there are no specific provisions for seismic TSC                      Technical Support Center                                                                          qualification.
UPS                      Uninterruptible Power Supply Explanatory Notes:                                                                                                        H. Under the "QA" column:
A. Under the "Actual Range" column:                                                                                      Yes" means the instrumentation meets the QA requirements detailed in the Design Criteria section for the The calibrated range of the sensor is listed unless otherwise noted.                                                  applicable design Category.
B. Under the "Redundancy" column:                                                                                      I. Under the "Trending" column:
      "Yes" means redundant fully qualified displays are available in the MCR. For Design Category 2 and 3                  Yes" means that trend or transient information is required for operator information or action based on our review instrumentation, this column is marked "N/A" since there are no redundancy requirements for this instrumentation.      of the plant-specific emergency response procedures and is available. "N/A" means that trend or transient information is not required for operator information or action based on our review of the plant-specific emergency response procedures.
C. Under the "Power Supply" column:                                                                                    J. Under the "Remarks/Notes" column:
The type of power supply for the instrumentation channels is listed. Since there are no specific provisions for the    For each item number, any column entry with an asterisk is explained in the "Remarks/Notes" column.
power supply for Design Category 3 instrumentation, "N/A" is marked in this column.
D. Under the "Display" column:
The tag number of the available MCR display instrumentation is listed. For the TSC/EOF, display will be via CRTs video displays driven by the Main Plant Computer System (MPCS). Where an analog input to the MPCS is provided, its corresponding analog input number is specified. Where a digital input is provided, its corresponding digital input number is specified.
E. Under the "SB Category" column:
The plant-specific design category for this instrumentation as determined from the review described in Subsection 7.5.4, is listed.
F. Under the "Environmental Qualification" column:
      "Yes" means the instrumentation is included in the environmental qualification program. The appropriate requirements for each instrument are determined as part of this program. For Design Category 3 instrumentation, "N/A" is entered since there are no specific provisions for environmental qualifications.
 
SEABROOK                                                                                                                                                                              Revision:                    17 INSTRUMENTATION AND CONTROLS STATION                                                                                                                                                                              Sheet:              37 of 37 TABLE 7.5-1 UFSAR FOOTNOTES (1)    MCB indicator provides non redundant backup indication; MCB indicator is non Class 1E.
(2)    MCB recorder provides second trend display channel. MCB recorder is non Class 1E.
(3)    MCB recorders LR-539 and LR-549 receive signals from transmittersLT-539 and LT-549, respectively.
(4)    Train A Plasma Display (RC-XX-7315-1,2&3) is installed fully qualified; Train B Plasma Display (RC-XX-7315-4) is essentially similar to seismically qualified display. Each ICCM cabinet (MM-CP-486A & 486B) has a local one-line display that is the fully qualified alternate display for ICCM variables.
(5)    MCB recorder provides backup historical recording. (Immediate trend or transient information not required for these channels.) MCB recorder is non Class 1E.
 
SEABROOK INSTRUMENTATION AND CONTROLS                                              Revision:                      10 STATION                                                                        TABLE 7.5-2                                            Sheet:                    1 of 6 UFSAR TABLE 7.5-2              CONTROL ROOM INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATOR TO MONITOR SIGNIFICANT PLANT PARAMETERS DURING NORMAL OPERATION INCLUDING OPERATIONAL OCCURENCES No. of Channels                              Indicated Parameter                Available          Range            Accuracy (1)          Indication            Location                  Notes Nuclear Instrumentation
: 1. Source Range
: a. Count rate                        2        1 to 106 counts/sec  +/-7% of the        Both channels          Control Board One eight-input recorder is provided for linear full scale  indicated and                        the two SR channels, two IR channels analog voltage    recorded                              and four PR channels.
: b. Startup rate                      2        -1.5 to +5.0        +/-7% of the        Both channels          Control Board decades/ min        linear full scale  indicated analog voltage
: 2. Intermediate Range
: a. Current                            2        10-11 to 10-3        +/-7% of the        Both channels          Control Board linear full scale  indicated and analog voltage    recorded and +/-3% of the linear full scale voltage in the range of 10-4 to 10-3 amps
: b. Startup rate                      2        -1.5 to +5.0        +/-7% of the        Both channels          Control Board decades/ min        linear full scale  indicated analog voltage (1)
These values are typical accuracies. Specific accuracies are accounted for in EOPs and supporting calculations.
 
SEABROOK INSTRUMENTATION AND CONTROLS                                        Revision:                      10 STATION                                                                TABLE 7.5-2                                          Sheet:                    2 of 6 UFSAR No. of Channels                        Indicated Parameter              Available      Range          Accuracy (1)        Indication          Location                  Notes
: 3. Power Range
: a. Uncalibrated ion chamber            4    0 to 120% of full +/-1% of full      All 8 current signals  NIS racks in current(top and bottom                    power current    power current    indicated.            control room uncompensated ion chambers)
: b. Average flux of the top and          4    0 to 120% of full +/-3% of full      All 4 channels        Control Board bottom ion chamber (% full                power            power for        indicated and power)                                                      indication      recorded.
                                                                  +/-2% for recording
: c. Flux difference of the top          4    -30 to 30%        +/-4%              All 4 channels        Control Board and bottom ion chambers                                                      indicated.
Reactor Coolant System
: 1. Taverage (measured)                1/loop  530&deg;-630&deg;F        +/-4.4&deg;F          All channels          Control Board Accuracy for one channel indication.
indicated                            Higher accuracy (to 2.22&deg;F) is obtained by averaging multiple Tavg indicators
: 2. T(measured)                        1/loop  0 to 150% of full +/-4% of full      All channels          Control Board power T          power T        indicated One channel is selected for recording
: a. Tcold or Thot(measured,      1-Thot'    0 to 700&deg;F        +/-2.7%            4 Thot channels are    Control Board wide range)                  1-Tcold per                                    recorded on 2 - two loop                                          pen recorders.
4 Tcold channels are recorded on 2 - two pen recorders.
 
SEABROOK INSTRUMENTATION AND CONTROLS                                            Revision:                  10 STATION                                                                      TABLE 7.5-2                                          Sheet:                  3 of 6 UFSAR No. of Channels                              Indicated Parameter              Available          Range            Accuracy (1)        Indication          Location                    Notes
: 3. Overpower T Setpoint            1/loop      0 to 150% of full    +/-4% of full      All channels          Control Board power T            power T          indicated One channel is selected for recording.
: 4. Overtemperature T Setpoint      1/loop      0 to 150% of full    +/-4% of full      All channels          Control Board power T            power T          indicated One channel is selected for recording.
: 5. Pressurizer Pressure                4        1600 to 2500 psig    +/-26 psi          All channels          Control Board indicated. One channel is selected for recording/control.
: 6. Pressurizer Level                    3        Entire distance      +/-5.0 of span      All channels          Control Board Two pen recorder used, second pen between taps                          indicated                            records reference level signal One channel dedicated recorder One channel is selected for recording/control.
: 7. Primary Coolant Flow              3/loop      0 to 120% of        2.1% (2)          All channels          Control Board nominal flow                          indicated
: 8. Reactor Coolant Pump Motor        1/loop      0 to 400 AC amps    +/-1.6%            All channels          Control Board One channel for each pump Current                                                                            indicated (2)
Flow measurement uncertainty from calorimetric and flow normalization.
 
SEABROOK INSTRUMENTATION AND CONTROLS                                          Revision:                    10 STATION                                                                  TABLE 7.5-2                                          Sheet:                    4 of 6 UFSAR No. of Channels                          Indicated Parameter              Available        Range          Accuracy (1)        Indication        Location                    Notes
: 9. System Pressure Wide Range              2    0 to 3000 psig    +/-2.8%            All channels        Control Board indicated and recorded.
Reactor Control System
: 1. Rod Speed                              1      5 to 75 steps/min. +/-2%              The one channel is  Control Board indicated
: 2. Average Tavg                            1    530&deg; to 630&deg;F      +/-4&deg;F            The one channel is  Control Board Any one of the Tavg channels into the indicated                          summer may be bypassed
: 3. Treference                              1    530&deg; to 630&deg;F      +/-4&deg;F            The one channel is  Control Board indicated
: 4. Control Rod Position                                                                                                If system not available, borate and sample accordingly.
: a. Number of steps of              1/group  0 to 230 steps    +/-1 step          Each group is        Control Board These signals are used in conjunction demanded rod withdrawal                                                        indicated during rod              with the measured position signals (4b) motion                            to detect deviation of any individual rod from the demanded position. A deviation will actuate an alarm and annunciator.
: b. Full length rod measured        1 for each 0 to 228 steps    +/-4 steps        Each rod position    Control Board position                                                                      indicated.
 
SEABROOK INSTRUMENTATION AND CONTROLS                                        Revision:                    10 STATION                                                            TABLE 7.5-2                                            Sheet:                  5 of 6 UFSAR No. of Channels                      Indicated Parameter            Available          Range      Accuracy (1)        Indication          Location                    Notes
: 5. Control Rod Bank Demanded          4      0 to 230 steps  +/-2.5% of total  All 4 control rod    Control Board 1. One channel for each control bank Position                                                                    bank positions are                  2. An alarm and annunciator is actuated recorded along with                when the last rod control bank to be the low-low limit                  withdrawn reaches the withdrawal limit, alarm for each bank.                when any rod control bank reaches the low insertion limit, and when any rod control bank reaches the low-low insertion limit.
Containment System
: 1. Containment Pressure                1      12 to 18 psia  +/-0.21 psia      All 7 channels        Control Board Narrow range (12 to 18 psia) indication 4      0 to 60 psig    +/-2.8%            indicated and 4 are                is used for compliance with Tech Spec 2      -5 to 160 psig  +/-3.45%          recorded.                          limits.
Feedwater And Steam Systems
: 1. Emergency Feedwater Flow      1/feed line 0 to 600 gpm    +/-22.5 gpm        All channels          Control Board One channel to measure the flow to each indicated and                      steam generator.
recorded.
: 2. Steam Generator Level          4/steam    0 to 100%      +/-3.5% of  P    All channels          Control Board (narrow range)                generator                  level (hot)      indicated One channel has dedicated recorder. The channels used for control are recorded.
: 3. Steam Generator Level (wide    1/steam    0 to 100%      +/-3.7% of        All channels recorded Control Board range)                        generator                  level(hot)
 
SEABROOK INSTRUMENTATION AND CONTROLS                                        Revision:                      10 STATION                                                          TABLE 7.5-2                                          Sheet:                    6 of 6 UFSAR No. of Channels                        Indicated Parameter          Available      Range        Accuracy (1)        Indication          Location                    Notes
: 4. Steam Generator Level                +7 to -5 feet    +/-4%              The one channel is Signal                                                                      indicated.
: 5. Main Feedwater Flow          2/steam  0 to 5x106 lbs/hr +/-5%              All channels          Control Board generator                                    indicated The channels used for control are recorded.
: 6. Magnitude of Signal          1/main  0 to 100% of      +/-1.5%            All channels          Control Board 1. One channel for each main and Controlling Main and Bypass 1/bypass  valve opening                      indicated                          bypass feedwater control valve Feedwater Control Valves                                                                                    2. OPEN/CLOSED indication is provided in the control room for each main and bypass feed water control valve
: 7. Steam Flow                  2/steam  0 to 5x106 lbs/hr +/-5.5%            All channels          Control Board Accuracy is equipment capability; generator                                    indicated The                      however, absolute accuracy depends on channels used for                  applicant calibration against feedwater control are recorded.              flow.
: 8. Steam Line Pressure          3/loop  0 to 1300 psig    +/-3.4%            All channels          Control Board indicated and 1 is recorded.
: 9. Steam Dump Demand                1    0-100% of steam  +/-1.5%            The one channel is    Control Board OPEN/CLOSED indication is provided dump valves open                  indicated                          in the control room for each steam dump valve
: 10. Turbine Impulse Chamber        2    0 to 860 psig    +/-3.5%            Both channels        Control Board OPEN/CLOSED indication is provided Pressure                                                              indicated.                          in the control room for each turbine stop valve
 
SEABROOK INSTRUMENTATION AND CONTROLS                            Revision:                  12 STATION                              TABLE 7.7-1                          Sheet:                  1 of 1 UFSAR TABLE 7.7-1    PLANT CONTROL SYSTEM Designation                  Derivation                                    Function C-1      1/2 Neutron flux (intermediate range)    Blocks automatic and manual control rod above setpoint                            withdrawal C-2      1/4 Neutron flux (power range) above      Blocks automatic and manual control rod setpoint                                  withdrawal C-5      1/1 Turbine impulse chamber pressure      Blocks automatic control rod withdrawal below setpoint Prevents automatic control (rod-out) when turbine load is below 15 percent C-7A      1/1 Time derivative (absolute value) of  Makes steam dump valves available for either turbine impulse chamber pressure          tripping or modulation (decrease only) above setpoint C-9      Any condenser pressure above setpoint, or Blocks steam dump to condenser All circulation water pump breakers open C-11    1/1 Bank D control rod position above    Blocks automatic rod withdrawal setpoint C-16    Reduce limit in coolant temperature above Stops automatic turbine loading until condition normal setpoint                          clears P-4    Reactor trip                              Blocks steam dump control via load rejection Tavg controller Makes steam dump valves available for either tripping or modulation Limits main feedwater pump speed to a predetermined value.
Absence of P-4                            Blocks steam dump control via plant trip Tavg controller
 
SEABROOK STATION UPDATED FINAL SAFETY ANALYSIS REPORT CHAPTER 7 INSTRUMENTATION AND CONTROLS FIGURES 7.1-1      Protection System Block Diagram 7.1-2      Reactor Trip/Engineered Safety Features Actuation Mechanical Linkage 7.2-1      Index and Symbols with Functional Diagrams 7.2-2      Reactor Trip Signals with Functional Diagrams 7.2-3      Nuclear Instrumentation and Manual Trip Signals with Functional Diagrams 7.2-4      Nuclear Instrumentation Permissives and Blocks with Functional Diagrams 7.2-5      Reactor Coolant Trip Signals with Functional Diagrams 7.2-6      Reactor Coolant Pressurizer Signals with Functional Diagrams 7.2-7      Feedwater Steam Generator Trip Signals with Functional Diagrams 7.2-8      Safeguards Actuation Signals with Functional Diagrams 7.2-9      Rod Control and Blocks with Functional Diagrams 7.2-10    Main Steam Dump Control with Functional Diagrams 7.2-11    Reactor Coolant Pressurizer Pressure and Level Control with Functional Diagrams 7.2-12    Reactor Coolant Pressurizer Heater Control with Functional Diagrams 7.2-13    Feedwater Control and Isolation with Functional Diagrams 7.2-14    Emergency Feedwater Pumps Startup with Functional Diagrams 7.2-15    Feedwater Turbine Trip/Runback with Functional Diagrams 7.2-16    Setpoint Reduction Function for Overpower and Overtemperature DeltaT Trips 7.3-1      Typical Engineered Safety Features Test Circuits
 
7.3-2  Engineered Safeguards Test Cabinet (Index, Notes and Legend) 7.6-1  Logic Diagram for Outer RHRS Isolation Valve (RC-V23 and V88) 7.6-2  Logic Diagram for Inner RHRS Isolation Valve (RC-V22 and V87) 7.6-3  Functional Block Diagram of Accumulator Isolation Valve 7.6-4  Safety Injection System Recirculation Sump and RHR Suction Isolation Valves 7.6-5  Refueling Water Storage Tank (RWSD level Sensor Installation 7.6-6  Diagram Showing Generating Plant Variable Processing for low Temperature Interlocks for RCS Pressure Control 7.6-7  ATWS Mitigation System Actuation Logic 7.7-1  Simplified Block Diagram of Reactor Control System 7.7-2  Control Rod Bank Insertion Monitor 7.7-3  Rod Deviation Comparator 7.7-4  Block Diagram of Pressurizer Pressure Control System 7.7-5  Block Diagram of Pressurizer level. Control System 7.7-6  Block Diagram of Steam Generator Water level Control System 7.7-7  Block Diagram of Main Feedwater Pump Speed Control System 7.7-8  Block Diagram of Steam Dump Control System 7.7-9  Incore Guide Tube Configuration 7.7-14 Simplified Block Diagram- Rod Control System 7.7-15 Control Bank D- Partial Simplified Schematic Diagram of Power Cabinets 1BD and 2BD
 
SEABROOK STATION Master                                    Actuate Control Board                Output  and                                      Train B Switches                            Slave                        Isolation    Safeguards Train B                            Relays                                                                  To Rod Drive UPDATED FINAL SAFETY                            Radiation Monitoring System                                                                                                                        Mechanisims Nuclear Instrumentation System Process Instrumentation System                      Protection  Logic                                                Computer Solid State Logic System                                                            Demux Train B Rod Containment Wall              Signal Control Processing Input                                                                                  System ANALYSIS REPORT Process                                                                    I        II        III          IV Sensors                          Channel Trip Computer IV                                                                                                  Bkr B                Bypass IV                                                                                                          Monitoring Brk B Channel "OR" Cable                    UV            UV III                    III STA    SHTR Channel                                                                                    Input II                                                                                                            Relays II Control I                  Channel                                                                                  Board Monitoring            STA    SHTR I                                                                                                                UV              UV I        II        III          IV Input Bistables                                                                                        Trip              Bypass Bkr A            Brk A Protection Control Board System      Logic            Solid State Logic                Demux Cabinet Train A Rod Protection System Block Diagram Control Board                          Master                                                                    Control Switches                              and                          Isolation  Actuate                          M-G Sets Train A                    Output  Slave                                    Train A Relays                                  Safeguards Figure G:\Word\Images_P\UFSAR\711.ds4 7.1-1
 
SEABROOK STATION Mechanical                                          Mechanical                                        Mechanical Link and                                            Link and                                          Link and UPDATED FINAL SAFETY                                                  Barrier                                            Barrier                                            Barrier Main Control                            Main Control                                      Main Control                                        Main Control Board                                  Board                                              Board                                              Board ANALYSIS REPORT                                                            Trip (A)          Trip (B)      Reset (A)                  Reset (B)                            Trip (A)                        Trip (B)
Momentary            Momentary        Momentary                  Momentary                          Momentary                      Momentary Reset Reactor              Reset Reactor Trip (A)                  Trip (B)
Reactor Trip/Engineered Safety Features Actuation Reactor Trip (A)      Reactor Trip (A)                                                    Reactor Trip (B)              Reactor Trip (B) and Shunt Coil        and Undervoltage                                                    and Shunt Coil                and Undervoltage To (A) Reactor        Coil to (A) Logic                                                  To (B) Reactor                Coil to (B) Logic Trip SWGR            Cabinet SSPS                                                        Trip SWGR                      Cabinet SSPS Figure G:\Images_P\UFSAR\712.ds4 Mechanical Linkage 7.1-2
 
See 1-NHY-509041 SEABROOK STATION    Index and Symbols with Functional Diagrams UPDATED FINAL SAFETY ANALYSIS REPORT                                        Figure 7.2-1
 
See 1-NHY-509042 SEABROOK STATION    Reactor Trip Signals with Functional Diagrams UPDATED FINAL SAFETY ANALYSIS REPORT                                          Figure 7.2-2
 
See 1-NHY-509043 SEABROOK STATION    Nuclear Instrumentation and Manual Trip Signals with Functional Diagrams UPDATED FINAL SAFETY ANALYSIS REPORT                                        Figure 7.2-3
 
See 1-NHY-509044 SEABROOK STATION    Nuclear Instrumentation Permissives and Blocks with Functional Diagrams UPDATED FINAL SAFETY ANALYSIS REPORT                                          Figure 7.2-4
 
See 1-NHY-509045 Sh.1 SEABROOK STATION      Reactor Coolant Trip Signals with Functional Diagrams
[2 Sheets]
UPDATED FINAL SAFETY ANALYSIS REPORT              Rev. 12              Figure 7.2-5  Sh. 1 of 2
 
See 1-NHY-509045 Sh.2 SEABROOK STATION      Reactor Coolant Trip Signals with Functional Diagrams
[2 Sheets]
UPDATED FINAL SAFETY ANALYSIS REPORT              Rev. 12              Figure 7.2-5  Sh. 2 of 2
 
See 1-NHY-509046 SEABROOK STATION    Reactor Coolant Pressurizer Signals with Functional Diagrams UPDATED FINAL SAFETY ANALYSIS REPORT                                          Figure 7.2-6
 
See 1-NHY-509047 Sh.1 SEABROOK STATION      Feedwater Steam Generator Trip Signals with Functional Diagrams [2 Sheets]
UPDATED FINAL SAFETY ANALYSIS REPORT                                    Figure 7.2-7  Sh. 1 of 2
 
See 1-NHY-509047 Sh.2 SEABROOK STATION      Feedwater Steam Generator Trip Signals with Functional Diagrams [2 Sheets]
UPDATED FINAL SAFETY ANALYSIS REPORT                                    Figure 7.2-7  Sh. 2 of 2
 
See 1-NHY-509048 SEABROOK STATION    Safeguards Actuation Signals with Functional Diagrams UPDATED FINAL SAFETY ANALYSIS REPORT                                          Figure 7.2-8
 
See 1-NHY-509049 SEABROOK STATION    Rod Control and Blocks with Functional Diagrams UPDATED FINAL SAFETY ANALYSIS REPORT                                        Figure 7.2-9
 
See 1-NHY-509050 SEABROOK STATION    Main Steam Dump Control with Functional Diagrams UPDATED FINAL SAFETY ANALYSIS REPORT                                      Figure 7.2-10
 
See 1-NHY-509051 SEABROOK STATION    Reactor Coolant Pressurizer Pressure and Level Control with Functional Diagrams UPDATED FINAL SAFETY ANALYSIS REPORT                                          Figure 7.2-11
 
See 1-NHY-509052 SEABROOK STATION    Reactor Coolant Pressurizer Heater Control with Functional Diagrams UPDATED FINAL SAFETY ANALYSIS REPORT                                          Figure 7.2-12
 
See 1-NHY-509053 SEABROOK STATION    Feedwater Control and Isolation with Functional Diagrams
[2 Sheets]
UPDATED FINAL SAFETY ANALYSIS REPORT                                    Figure 7.2-13 Sh. 1 of 2
 
See 1-NHY-509054 SEABROOK STATION    Feedwater Control and Isolation with Functional Diagrams
[2 Sheets]
UPDATED FINAL SAFETY ANALYSIS REPORT                                    Figure 7.2-13 Sh. 2 of 2
 
See 1-NHY-509055 SEABROOK STATION    Emergency Feedwater Pumps Startup with Functional Diagrams UPDATED FINAL SAFETY ANALYSIS REPORT                                      Figure 7.2-14
 
See 1-NHY-509056 SEABROOK STATION    Feedwater Turbine Trip/Runback with Functional Diagrams UPDATED FINAL SAFETY ANALYSIS REPORT            Rev. 12                    Figure 7.2-15
 
f( I)
C B2                                        B1 A2            A1 I    - Neutron Flux Difference Between Upper and Lower Long Ion Chambers A1, A2 - Limit of F ( I) Deadband B1, B2 - Slope of Ramp: Determines Rate at Which Function-Reaches its Maximum Value Once Deadband is Exceeded C      - Magnitude of Maximum Value The Function May Attain G:\Word\Images_P\UFSAR\7216.ds4 SEABROOK STATION              Setpoint Reduction Function for Overpower and Overtemperature T Trips UPDATED FINAL SAFETY ANALYSIS REPORT                                                  Figure            7.2-16
 
Channel Calibration SEABROOK STATION Channel Check Master Relay Testing Indication Logic Testing                        Final Device or Actuator Testing Operational Testing UPDATED FINAL SAFETY Signal                        Input        Logic          Master            Slave                          Solenoid Sensor                                Bistable Processing                      Relay        Circuit        Relay            Relay                          Valves ANALYSIS REPORT Process Instrumentation System                                    SSPS                                  Motor        Motor Oper Starters        Valves Redundant SSPS Train Slave                          Solenoid Relay                          Valves Motor        Motor Oper Starters        Valves Slave                          Pump Breaker Relay                          Motors Slave Relay                                      Actuators Figure Slave Actuators Relay Typical Engineered Safety Features Test Circuits G:\Images_P\UFSAR\731.ds4 7.3-1
 
General Notes:*
Test Light DS*
SEABROOK STATION                                                                                                            Dev 3                                                                                          1. Circuitry and Hardware for Redundant Protection Trains "A" and "B" Test Cabinets Are Duplicate Except As Noted 4                W              1 A - Train "A" Only 5                                                                                              B - Train "B" Only
: 2. In Details A & B the Symbol
* Reprensents the Suffix Numbers of the Device Referenced.
UPDATED FINAL SAFETY 3                                2 Example:
Illuminated Pushbutton Switch                                                                                      K*          SPS Relay, K601, K602, etc.
with 28V Lamp No. 327                                                                                              K (0)      Operating Coil (Except as Noted)                                                                                                  K (R)      Reset Coil S*          STC Test Switch S802, S834, etc.
ANALYSIS REPORT K8*        STC Relay, K811, K817, etc.
Rear of Panel                                                                                        DS*        STC Light, DS8009, DS8077, etc.
1                                                                                                        3. Detail A" & B" Type Circuits Are Detailed on the 2                                                                      Schematics, "Detail B" circuits will be Substituted For "Detail A" Circuits Where Required.
5 Location Legend 3                                                                  SPS Solid State Protection System 4
STC Safeguards Test Cabinet Key                                                                            X      Swgr, MCC, Auxiliary Relay Rack, etc.
Contact Location Scheme                                                                                    ASC Auxiliary Safeguards Cabinet (x)
Typ. Terminal Typ. Terminal                                                                                    Numbers SPS Numbers                                                                X X                                          X                                                                                                          (9)
STC                                        STC                                                                                    SPS STC                                                    (1)                                    (5)                                                                                        STC J802 K*                K8*
J801 Engineered Safeguards Test Cabinet (Index, Notes and SPS L21                                                    K8* 1      2                              K8* 1      2                    L21                                                    3      2        3          2 S*                                                                                                                                      S*                          STC W DS                                      W      DS                                                                              W DS              G    DS Reset            S821
* Rest      S821 L22                                          STC                  *                          (6)                                  L22                                  (11)                      1*                  1 *
(2)      3                      STC                    3                                  K8*
K8*                                                                                          V                                                                                    V 120 VAC  SPS                                        SPS                    All Varistors                                                                                    V STC                                                    K*                    125 VDC              K*          Are STC J802 120 VAC (SPS)
SPS                                                                GEV130LA20A J801          J802                                                                SPS                                              J801 125 VDC STC        (3)        (4)                            (7)        (8)                                                            STC    (12)          (10)
STC                                              SPS SPS X
Figure                                                                                                                          X                                        X All Varistors K*            K*                                                                                                                    K*          K*                                                Are X1                                        X2                                                                                    Y2 (0)            (R)                                                                                                                  (0)          (R)                                                GEV130LA20A (N)
Detail A    Typical Protection Actuation Circuit Blocking Schemes                                                                    Detail B Typical Protection Actuation Circuit Blocking Schemes (Contact Closure For Actuations)                                                                                                  (Contact Opening For Actuation) 7.3-2                                                                                          *Details A And B Of This Figure Are Not To Be Confused With Alpha Designation Of Logic Trains A and B Legend)
G:\Images_P\UFSAR\732.ds4
 
Main Control Board Spring Return To Norm From Open OPEN      NORM        CLOSE PT 405 RCS Pressure, HI**
LO To HI Head Crossover Valve Closed AND
          ** Prevent Open Setpoint Open Valves              Close Valves Closest To RHR            Closest To RHR NOTE:
Logic For Valves In Each Fluid System Train Is Identical PT - Pressure Transmitter Located Outside Containment G:\Images_P\USFAR\761.ds4 SEABROOK STATION                Logic Diagram for Outer RHRS Isolation Valve (RC-V23 and V88)
UPDATED FINAL SAFETY ANALYSIS REPORT                                                      Figure          7.6-1
 
Main Control Board Spring Return To Norm From Open OPEN      NORM          CLOSE PT 403 RCS Pressure, HI**
LO To HI Head Crossover Valve Closed AND
          ** Prevent Open Setpoint Open Valves                Close Valves Closest To RCS              Closest To RCS NOTE:
Logic For Valves In Each Fluid System Train Is Identical PT - Pressure Transmitter Located Outside Containment G:\Word\Images_P\USFAR\762.ds4 SEABROOK STATION                Logic Diagram for Inner RHRS Isolation Valve (RC-V22 and V87)
UPDATED FINAL SAFETY ANALYSIS REPORT                                                      Figure            7.6-2
 
Control Board Switch Maintain Close, Spring Return From Open To Auto Safety Injection System Unblock Pressure Signal (RCS Pressure)*
OPEN        AUTO        CLOSE Safety                                                        Safety Injection                                                      Injection Signal                                                        Signal AND
* This Interlock Indicates The Method Of Applying Automatic Opening Of The Valve, Whenever The RCS Pressure Exceeds A Limit. This Signal OR                                    Automatically Occurs At RCS AND          Pressures Above The SI Unblock Pressure Used To Derive P-11.
Open                    Close Accumulator Isolation Valve G:\Word\Images_P\USFAR\763.ds4 SEABROOK STATION          Functional Block Diagram of Accumulator Isolation Valve UPDATED FINAL SAFETY ANALYSIS REPORT                                                  Figure              7.6-3
 
LB-930E: RWST Tank Level LO-LO LB-931E 2/4 LB-932E LB-933E Initiate ECCS/CBS AND "S" Signal                                                      Recirc.
CS Reset                                                        Signal (Cont. On Fig 7.6-4 Sh.2)
RWST Level Channel Bistables
: 1) Normally De-Energized
: 2) De-Energized on Loss of Power
: 3) Trip Signal Provided When Energized
: 4) Energized on LO-LO Level Set Point G:\Word\Images_P\USFAR\764.ds4 SEABROOK STATION              Safety Injection System Recirculation Sump and RHR Suction Isolation Valves [2 Sheets]
UPDATED FINAL SAFETY ANALYSIS REPORT                                              Figure          7.6-4 Sh. 1 of 2
 
Prot System:
ECCS/CBS RHR Outer Iso.
Recirc.                                                                    Valve Closed Main Control Board Signal                    Spring Return To Auto From Close RHR Inner (From                                                                                      Iso. Valve CLOSE            AUTO        OPEN                            Closed Fig. 7.6-4 Sh.1)
OR AND AND OR OR Open Valve AND Applicable Valve Close Valve                                        Description Interlock Table Sump to RHR Pump P-8A                CBS-V8 Valve Inter                            CBS-V8      CBS-V14 Lock With                                                    Sump to RHR Pump P-8B                CBS-V14 RC-V22      RC-V87 RHR Inner ISO Valve RC-V23        RC-V88 RHR Outer ISO Valve A            B Train G:\Word\Images_P\UFSAR\7642.ds4 SEABROOK STATION                        Safety Injection System Recirculation Sump and RHR Suction Isolation Valves [2 Sheets]
UPDATED FINAL SAFETY ANALYSIS REPORT                                                                Figure            7.6-4 Sh. 2 of 2
 
SEABROOK STATION    Refueling Water Storage Tank (RWST) Level Sensor Installation UPDATED FINAL SAFETY ANALYSIS REPORT                                      Figure    7.6-5
 
        ~Q~                                        PROTECTION SET l        PROTECTION SET l              PAOTECT10N Sf T.U.                *PROTECTION SET lll
        ~ &sect;2 ~                                                              I                                                                I
        ><: >-1 ~                                                            I                                                              I CZl trl 0
        ..... t:1 0                              RCS WfOE AGE TEMP HOT    I ACS PRESS.                RCS WIOE AGE TEMP COLO              :  RCS PRESS.
        ~~~  S2CZl                                PROTECTION SET I
:    PROT.!                                                      I    PROT.m' I                        --~:.:.:::;.  ::.:,::_::.;...:s---..._ I 0>"0 ~ ....,      ~                                                I                                                                I
        ?=11./J-                                                            I                                                                I
        . . , ?;; ~              EXISTING lSOLATION I
I I
I tr:f              DEVICES                                  t                                                                l
              ~
t""'i\j 0      ......
                    ~~            CONTROL GROUP I                                            CONTROl GROUP                AUCTIONEER
                    ~8            PROCESS RACK                                                4 PROCESS
:;o            ~(/.)                                                                      RACK
  ~                (!)
1-1 1:1"'
0
  -...)            ~~s*
0(JQ
[0
(!)    (!)
FUNCTION GENERATOR ERROR FUNCTION GENERATOR ERROR g
1-1    :::;
1-'(l) 0      1-1                          StGNAl BtSTABL&#xa3;                                      SIGNAl BISTABLE
-                  n                                        OUTPUT                                                OUTPUT 11<;"
* Vl I::I'>(JQ 0
1-1
                          'i:::!
                    ~a "rj
(/.)<
~                  ~
(!)
                          ~.
II)
VALVE "A'*  '                                                        +
VALVE "8" g; g:                              ACTUATION Ei                                                                                                ACTUATION
(!)
                          'i:::!                                VALVE "A"                              VALVE "'8" nl-1
(!)
PERMISSIVE
  -...)
g                                    PERMISSIVE 0
I              s. ~
e.. s*
0\                                                        fAAIN A 1-1    Vl fAAINB (JQ S">
1-1
 
SEABROOK STATION    ATWS Mitigation System Actuation Logic UPDATED FINAL SAFETY ANALYSIS REPORT                                    Figure  7.6-7
 
THOT LEG TCOLD LEG              THOT LEG TCOLD LEG              THOT LEG TCOLD LEG              THOT LEG TCOLD LEG AVERAGE                          AVERAGE                          AVERAGE                          AVERAGE TEMPERATURE                      TEMPERATURE                      TEMPERATURE                    TEMPERATURE UNIT LOOP 1                      UNIT LOOP 2                      UNIT LOOP 3                      UNIT LOOP 4 TAVG = TH + TC                  TAVG = TH + TC                  TAVG = TH + TC                  TAVG = TH + TC 2                                2                                2                                2 TURBINE LOAD SUMMING UNIT                                                        SIGNAL AVERAGE TAVG NUCLEAR POWER SIGNAL AVERAGE TAVG TO STEAM                                                                TO PRESSURIZER DUMP SYSTEM        TURBINE LOAD SIGNAL                                  LEVEL PROGRAMMER LEAD-LAG                                            POWER AVERAGE              COMPENSATION                                        MISMATCH TEMPERATURE                  UNIT                                        COMPENSATION PROGRAMMER                                                                      UNIT ROD SPEED                      MANUAL UNIT                          ROD CONTROL ROD DRIVE SEQUENTIAL ROD                      POWER                REDUNDANT CONTROL UNIT                                            TRIP SIGNAL (AUTOMATIC CONTROL)
REACTOR TRIP BREAKER 1 PERMISSIVE CIRCUIT (ROD INTERLOCK)
NOTES: 1. TEMPERATURES ARE                                                          REACTOR TRIP MEASURED AT STEAM                                                      BREAKER 2 GENERATORS INLET AND OUTLET.
CONTROL ROD
: 2. PRESSURE IS                              ACTUATOR MEASURED AT THE PRESSURIZER.
: 3. THOT LEG IS THE AVERAGE OF THREE HOT LEG RTDs.
CONTROL ROD DRIVE MECHANISM G:\Work UFSAR_NATIVE\Drawings\771.vsd SEABROOK STATION Simplified Block Diagram of Reactor Control System UPDATED FINAL SAFETY ANALYSIS REPORT                                                                                    Figure        7.7-1
 
L O W      A L A R M L O W - L O W A L A R M A L  1 (T        )
A V G Z  L L    = A (      T ) A U C T +
A v e ra g e                                                                                                                      A L  2 C O M P A R A T O R
(    T )                                      B (T      A V G ) A v e ra g e + C A U C T C O M M O N F O R A L L F O U R C O N T R O L B A N K S Z
D E M A N D B A N K S IG N A L                      T Y P IC A L O F O N E C O N T R O L B A N K N O T E : 1 . A N A L O G C IR C U IT R Y IS U S E D F O R T H E C O M P A R A T O R N E T W O R K 2 . C O M P A R IS O N IS D O N E F O R A L L C O N T R O L B A N K S F I G U R E 7 .7 - 2 D S F SEABROOK STATION                                                    Control Rod Bank Insertion Monitor UPDATED FINAL SAFETY ANALYSIS REPORT                                                              Rev. 12                                      Figure                7.7-2
 
SEABROOK STATION    Rod Deviation Comparator UPDATED FINAL SAFETY ANALYSIS REPORT                              Figure 7.7-3
 
SEABROOK STATION    Block Diagram of Pressurizer Pressure Control System UPDATED FINAL SAFETY ANALYSIS REPORT                                      Figure      7.7-4
 
AVERAGE TAVG PRESSURIZER WATER LEVEL SIGNAL LEVEL PROGRAMMER HEATER CONTROL PID CONTROLLER CHARGING FLOW SIGNAL PI CONTROLLER REMOTE MANUAL CONTROL CHARGING FLOW CONTROL VALVE POSITION G:\WORK UFSAR_NATIVE\DRAWINGS\775 SEABROOK STATION                  Block Diagram of Pressurizer Level Control System UPDATED FINAL SAFETY ANALYSIS REPORT                                                    Figure      7.7-5
 
SEABROOK STATION    Block Diagram of Steam Generator Water Level Control System UPDATED FINAL SAFETY ANALYSIS REPORT                                      Figure    7.7-6
 
SEABROOK STATION    Block Diagram of Main Feedwater Pump Speed Control System UPDATED FINAL SAFETY ANALYSIS REPORT            Rev. 12                Figure    7.7-7
 
Steam Dump Control in Manual (Steam Pressure Control)                                                    Average TAvg Turbine Impulse                    TAvg                                  Reference Stage Pressure                  No-Load                                    TAvg Rate/Lag Compensation              P-4 Lead/Lag Reactor Compensation Trip Load Rejection Bistable
(-)            (+)  (+)            (-)
Defeat Load Rejection Steam Dump Control; Allow Plant Trip                    Bistables            Bistables Steam Dump Control Steam Header Pressure Set                    Plant Trip Pressure                  Controller Load Rejection
(-)                                Controller Load Rejection Control Or PI                                                                          Plant Trip Controller                                                                      Control Load Rejection Control Or Plant Trip Control                          Trip Open Steam Dump Valves Auto (TAvg              NOTE: For Blocking, Unblocking Manual                      Control                        Signal To Condenser (Steam                                                      Steam Dump Valves Pessure                                                    See Figure 7.2.10 Air Supply To          Control)
Dump Valves Modulate Condenser Dump Valves G:\Work UFSAR_NATIVE\drawings\778.ds4 SEABROOK STATION                          Block Diagram of Steam Dump Control System UPDATED FINAL SAFETY ANALYSIS REPORT                                                                      Figure            7.7-8
 
007_Figure 07-09.tiff
* Detector assemblies contain five fixed gamma and neutron flux detectors connected to the Fixed Incore Detector Data Acquisition System (FIDDAS) and one core exit thermocouple connected to the Inadequate Core Cooling (ICC) monitor.
SEABROOK STATION                    Incore Detector Guide Tube Configuration UPDATED FINAL SAFETY ANALYSIS REPORT                                Rev. 19                      Figure        7.7-9
 
SEABROOK STATION Slave              Power                Control Cycler            Cabinet              Bank D 1 BD                1 BD                Group 1 UPDATED FINAL SAFETY Reactor                                                                            Life Coil Master Control              Pulser                                                        Disconnect Cycler System                                                                            Switches ANALYSIS REPORT Slave              Power                Control Cycler            Cabinet              Bank D Manual                                            2 BD                2 BD                Group 2 Switch Bank              Bank Selector          Overlap Multiplex Circuits 1 NOTE: Only Cabinets 1BD And 2BD Shown. For t                                                                More Complete Lifting                      Diagram Including Power Cabinets 1AC, Group 1 2AC, And SCD.
t/2                                        Off                        See FP 54022 Lifting Group 2 Off Figure                                                                      Normal Sequencing of Groups Within Bank G:\Images_P\USFAR.7714.ds4 Simplified Block Diagram - Rod Control System 7.7-14
 
A        B      C            A    B      C                                    A      B        C SEABROOK STATION                                                                                                                        Control Bank D Group 1 Multiplex                Power Cabinet Thyristor                1BD UPDATED FINAL SAFETY                                                                                                                                                          Multiplex Thyristors 120 VAC ANALYSIS REPORT Life Coil Disconnect Switches X
1 Lift Coils Stationary                    Movable Gripper                      Gripper                                        A        B      C Coils                        Coils Control Bank D Group 2 Control Bank D - Partial Simplified Schematic Diagram of Power Cabinet 2 BD 120 VAC Figure Life Coil Disconnect Switches X
2 7.7-15 G:\Word\Images_P\UFSAR\7715.ds4
                                                                                                                          ~
                                                                                                                          ~
Power Cabinets 1BD and 2BD Lift Coils}}

Latest revision as of 01:53, 18 November 2024

1 to Updated Final Safety Analysis Report, Chapter 7, Instrumentation and Controls
ML22131A091
Person / Time
Site: Seabrook NextEra Energy icon.png
Issue date: 05/05/2022
From:
NextEra Energy Seabrook
To:
Office of Nuclear Reactor Regulation
Shared Package
ML22131A110 List:
References
SBK-L-22042
Download: ML22131A091 (318)
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