ML20073J548

Vols 1-3 to Arkansas Nuclear One Units 1 & 2 Response to Suppl 1 to NUREG-0737 Requirements for Emergency Response Capability,Generic Ltr 82-33

ML20073J548
Person / Time
Site:	Arkansas Nuclear
Issue date:	04/15/1983
From:	ARKANSAS POWER & LIGHT CO.
To:
Shared Package
ML20073J530	List: 0CAN048312, Forwards Vols 1-3 to Arkansas Nuclear One Units 1 & 2 Response to Suppl 1 to NUREG-0737 Requirements for Emergency Response Capability,Generic Ltr 82-33, Per 10CFR50.54(f). Task Force Formed & Organizational Structure Established ML20073J548
References
RTR-NUREG-0737, RTR-NUREG-737 GL-82-33, NUDOCS 8304190325
Download: ML20073J548 (601)

Text

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l ARKANSAS POWER & LIGHT COMPANY ARKANSAS NUCLEAR ONE UNITS 1 & 2 RESPONSE TO SUPPLEMENT 1 TO NUREG 0737 REQUIREMENTS FOR EMERGENCY RESPONSE CAPABILITY g GENERIC LETTER NO. 82-33 l

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RESPONSE TO NUREG 0737 SUPPLEMENT 1 i

(GENERIC LETTER 82-33) ,

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' RESPONSE TO NUREG 0737 SUPPLEMENT 1 4

(Generic Letter 82-33)

1.0 INTRODUCTION

2.0 INTEGRATE 0 IMPLEMENTATION PLAN Figure 2 Supplement 1: Organizational Structure

-Fipure 2 Supplement 1 Integrated Implementation Plan Table 2 Supplement 1 Summary Completion Dates 3.0 SAFETY PARAMETER DISPLAY SYSTEM (SPDS)

Figure 3-l'- SPDS. Abnormal Transient Operating Guidelines Display-Figure 3 SPDS Hardware Configuration l 4.0 CONTROL ROOM DESIGN REVIEW (CRDR) -

Figure 4 CRDR Team Organization  ;

5.0 REGULATORY GUIDE 1.97 (R.G. 1.97) 6.0 UPGRADE EMERGENCY OPERATING PROCEDURES (E0Ps)-

Appendix 6A - A Technical Paper " Abnormal Transient Operating Procedures" Appendix 6B - ANO-1 Plant Specific Technical Guidelines-

+-

(contained in Volumes 2 and 3)

-Appendix 6C - E0P Writing Guidance Appendix 6D - E0P Validation Program

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Appendix 6E - E0P Training Program

7. 0 EMERGENCY RESPONSE FACILITIES (ERF) 7.1 TECHNICAL SUPPORT CENTER (TSC) 7.2- OPERATIONAL SUPPORT CENTER-(OSC) 7.3 EMERGENCY OPERATIONS FACILITY (EOF) 1 7. 4 GENERAL

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Figure 7 Tech'nical Support Center

!- Figure 7 Technical and Operational Support Center Evacuation Decision Flow Chart l Figure 7 Exclusion Area

. Figure 7 ECC Second Floor West End 4

Figure 7-5 " ECC First Floor West End Figure 7 ECC Second Floor East End Figure 7 ECC First Floor East End Figure 7 Minimum Staffing Requirements l'

Appendix 7A - AP&L Nuclear Contingency Plan Procedure 15 " Emergency Control Center Evacuation" .

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1.0 INTRODUCTION

On December 17, 1982, the NRC issued Generic Letter 82-33, which transmitted

" Supplement 1 to NUREG 0737, Requirements for Emergency Response Capability." Supplement 1 to NUREG 0737 was issued to distill the fundamental requirements for nuclear utility Emergency Response Capability from the broad range of guidance documents previously issued by the NRC.

The Supplement specifies that utilities develop an integrated approach to produce a plan for the implementation of the following requirements: Safety Parameter Display System (SPDS), Control Room Design Review (CRDR),

Regulatory Guide 1.97 (R.G.1.97), Upgrade Emergency Operating Procedures (E0Ps), and Emergency Response Facilities (ERFs). This document presents AP&L's integrated approach to meet this recommendation. Specifically section 3.0 of this document addresses Supplement 1 to NUREG-0737 item 4, Safety Parameter Display System; section 4.0 addresses Supplement 1 to NUREG-0737 item 5, Detailed Control Room Design Review; section 5.0 addresses Supplement 1 to NUREG-0737 item 6, Regulatory Guide 1.97 -

Application to Emergency Response Facilities; section 6.0 addresses Supplement 1 to NUREG-0737 item 7, Upgraded Emergency Operating Procedures; and section 7.0 address Supplement 1 to NUREG-0737 item 8, Emergency Response Facilities. ,

Since the summer of 1979 when NUREG 0578 was first published, AP&L has expended a considerable amount of resources in designing and constructing facilities and equipment to meet NRC's recommendations. In the aftermath of TMI-2 as information became available pertaining to the March 28, 1979 accident, it became apparent AP&L needed to reevaluate the Company's existing Emergency Plan and associated procedures and make use of the TMI-2 experience to enhance plant safety at ANO. -To accomplish this, a task force was formed in the spring of 1979 by AP&L, to evaluate the TMI-2 experience and report back to management their recommendations to improve Aff&L's emergency response capability. This task force evaluated nine different topical areas in an integrated fashion, with the overall objective of improving AP&L's emergency response capability. Two topical areas specifically addressed by the task force were logistical support and safety assessment. Efforts by the task force in these areas layed the foundation '

for the planning and construction of AP&L's new 72,000 square foot Emergency Control Center and the ANO Emergency Operating Procedures development program. As a result of our efforts, significant progress has been achieved i to satisfy the Supplement 1 requirements for the SPDS, the Upgraded E0Ps,

and the ERFs. Although ,esch program has been developed by different groups within AP&L, relationships with activities in other programs were considered and included in each program's development. AP&L has recently implemented an orgnization to address the NUREG 0737 Supplement 1 requirements. As a result of this effort, strides are now being made to address Regulatory l Guide 1.97 and control room design review.

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. 1 2.0 INTEGRATED IMPLEMENTATION PLAN-Upon receipt of Generic Letter 82-33, AP&L proceeded to formalize an integrated approach'to produce a plan for the implementation of the various requirements of the Generic Letter. Figure 2-1 illustrates AP&L's organizational structure for addressing Supplement 1. The Steering Committee shown in Figure 2-1 consists of the Licensing Manager, Nuclear Services Manager, AN0 Operations Manager, ANO-1 Operations Superintendent, and the ANO-2 Operations Superintendent. Their function is to provide oversight and continuity to the integrated implementation plan. In addition, the Steering Committee, which reports directly to the Vice President - Nuclear Operations, provides a focal point to AP&L management to ensure that the integrated plan receives proper management attention. The Program Coordinator is responsible.for_ assuring the individual working groups efforts are carried out in an integrated fashion and that schedules are coordinated and met. The individual working groups shown in Figure 2-1 were established to develop plans for the various activities of each topic.

These groups consist of individuals from I&C Engineering, General Office Nuclear Services, AND Operations, Training, Licensing, Emergency Planning, and other disciplines. As previously mentioned, working groups were already established for some of the topics. The plans of the various groups were.

combined to produce an integrated implementation plan which defines the interrelationships among the different topics. Furthermore, the integrated implementation plan provides a tiasis for estimating completion dates for the major milestones.

An overview of the integrated implementation plan, including estimated completion dates for those identifiable major milestones, is provided in Figure 2-2. This overview -is a condensed version of the detailed integrated implementation plan. The detailed plan is represented by a computerized

" Project-2" schedule which is being utilized by AP&L for monitoring the progress of the Supplement 1 program. AP&L is unable to provide at this time final dates for those milestones whose completion is dependent upon identifying the scope of work resulting from previous milestones. The final dates for these milestunes will be provided as their scope of work is identified. -

This plan is a result of AP&L's best efforts to define the interrelationships among the different topics and to determine manpower needs to perform the various activities. A summary of the milestone dates in the integrated plan i,s'provided in Table 2-1. It must be recognized that although AP&L has confidence in adhering to the dates identified in the table, future modifications may be required to the plan which could impact the scheduled completion dates. Hence, in order to keep NRC abreast of the current status of the integrated plan and schedule evolution, Figure 2-2 will be updated and provided to NRC on October 15, 1983 and each six months thereafter until the program is complete.

The ensuing sections provide descriptions of the current status and future plans for the various topics for Emergency Response Capability. Although, not specifically identified as a section in this document AP&L is making

i. every effort to integrate training into the planning and implementation of 2-1

each ofLthe Supplement I requirements. A system _will not be hastily

- declared operational by AP&L until, personnel are familiar with it and adequately trained on its use. The .overall ~ goal of- AP&L's training program is to develop operators and emergency response personnel ability to evaluate

' plant conditions and cope with. emergencies effectively.

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NUREG 0737 SUPPLEMENT I ORGANIZATIONAL STRUCTURE

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• I SPCS JU NE IS,ltes FOR ADD'N COMP W PARiME TERS M00sFICATIONS PAR A M ETERS PARAME TE RS S N TM EMENT ANO-2 PERFORN ANO-2 CONDUCT ANO-2 SPDS FOR A 8t -

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TABLE 2-1 SUPPLEMENT 1

SUMMARY

COMPLETION DATES ANO-1 Completion Date SPDS Safety Analysis June 29, 1984 SPDS Operational With Existing January 10, 1984 Parameters SPDS Complete- June 15, 1986 CRDR Program Plan- November 25, 1983 CRDR Summary Report Date to be Provided with Program Plan R.G. 1.97 Position Document June 29, 1984 R.G. 1.97 Modifications Schedule to be Provided with Position Document E0P Procedure Generation Package April 15, 1983 (See Attachment)

E0P Implementation Complete ANO,2 Completion Date SPDS Safety Analysis April-15, 1984-SPDS Operational with Existing June 1, 1984 Parameters-SPDS Complete December 15, 1985 CRDR Program Plan November 25, 1983 CRDR Summary Report Date to be Provided with Prcgram Plan R.G. 1.97 Position Document April 15, 1984 R.G. 1.97 Modifications Schedule to be Provided with Position Document Generic Technical Guidelines Not Applicable E0P Procedure Generation Package 3 Mos. Prior to Fourth Refueling Outage g E0P Implementation During the Fourth Refueling Outage (Begins September 15, 1985) .

2-5

TABLE 2-1 (CONT'D)

SUPPLEMENT:1

SUMMARY

COMPLETION DATES ANO-1&2 Completion Date Emergency Response Facilities Complete Operational without Data Display Systems -

Emergency Response-Facilities June 1, 1984 SPDS Operational with Existing Parameters Emergency Response Facilities June 15, 1986 SPDS Complete Emergency Response Facilities June 30, 1984 GERMS Operational 2-6

3. 0 SAFETY PARAMETER DISPLAY-SYSTEM (SPDS)

AP&L began the development of a Safety Parameter Display System (SPDS) early in 1980 in response to NUREG 0578 Items 2.2.2.b and 2.2.2.c, issued in October of 1979, and NUREG 0585 Appendix A Item 7.2,- issued in August of 1979. In June of 1980, AP&L ordered a computer system to provide the

' capability to perform the functions referenced in these NUREGs. In October of 1980, the NRC issued NUREG 0737 (Clarification of the TMI Action Plan Requirements). Item I.D.2 of NUREG 0737 required each licensee to install an'SPDS that will display to operating personnel.a' minimum set of parameters which are used to assess the safety status of the plant. Item III.A.1.2 of NUREG 0737 required licensees to provide data to the Technical Support Center (TSC) and Emergency Operations Facility (E0F) for those parameters essential to the TSC and EOF functions. NUREG 0737 referenced NUREG 0696 (Functional Criteria for Emergency Response Facilities) for'use as the criteria for design of the SPDS and TSC/E0F instrumentation systems. ~

NUREG 0696 was not issued until March of 1981. Several modifications were required to the original computer system design as a result of this new criteria.

The present SPDS computer system is designed to meet the objectives of the NRC documents referenced above. The function of the SPDS is to continuously

' provide concise displays of critical plant parameters to the control room operators.to aid them in rapidly and reliably determining the safety status of the plant. The system will be especially useful during abnormal and emergency conditions to assess whether the conditions warrant corrective action by the operators to avoid a degraded core.

The SPDS displays have been integrated with the development of the Upgraded ANO-1 Emergency Operating Procedures (E0Ps) to ensure compatibility. This is exemplified by Figure 3-1.which depicts a color graphic display developed 4

specifically to support the ANO-1 E0Ps and which is currently available on the SPDS. However, the ANO-1 E0Ps are developed to achieve timely and accurate safety status assessment either with or without the SPDS. In addition, the operators will be trained for response to accident conditions with and without the availability of the SPDS. A similar approach is being used for the integration of the SPDS with the ANO-2 EUPs.

A hardware configuration of the SPDS is provided in Figure 3-2. The computer system is an integrated network which is designed to perform the functions required for the ANO-1 SPDS, the ANO-2 SPDS, the Technical Support Center data display system, and the Emergency Operations Facility data display system. To achieve these functions, the SPDS computer accesses necessary input parameters from sensors in ANO-1 and ANO-2, processes these signals, and provides displays to each control room as well as to the TSC and the secondary TSC portion of the E0F. Suitable isolation is provided between the SPDS data acquisition system and class IE sensors. In each control room, two color graphic CRTs are provided for the operators. Two color graphic CRTs are also provided in the TSC as well as the E0F. " Touch screen" controls are utilized on the color graphic CRTs to allow for rapid access of the information necessary to determine safety status of the plant.

The computer system selected by AP&L was chosen primarily because of its flexibility, reliability, and maintainability. Flexibility is needed to i

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permit the incorporation of future modifications without unwarranted

'di f ficul ty.' The computer hardware selected is similar'to existing hardware already in use at ANO. This hardware has been proven to be reliable.

Furthermore, AP&L personnel have considerable experience in maintaining this equipment which should improve the overall reliability of the' system.

Several features have been incorporated into the SPDS design (see Figure 3-2) in order to approach the availability goals specified in the NRC guidance and to allow for incorporation of future modifications while the system.is operating. These features include redundant CPUs, redundant data acquisition hardware, redundant color graphic display generators, and redundant color graphic- CRTs in each control room. Except for the STSC -

console, which is powered from a diesel generator backed panel, the SPDS power is supplied from an uninterruptable power supply (UPS). The SPDS computer room is provided with a computer grade air conditioning system which will be energized from a diesel generator backed power supply.

Due to AP&L's early commitment to the development of the SPDS, essentially.

all of the computer hardware has been procured, installed and is operating for testing purposes. The computer's data acquisition system is functional

.and a point by point verification of the database is in progress. At this time, the only inputs to the computer are those accessed from instrument loops which currently feed the existing plant computers in ANO-1 and ANO-2.

This constitutes a total of approximately 200 inputs for ANO-1 and 270 inputs for ANO-2. The database will be completed after completion of the AN0-1 and ANO-2 R.G. 1.97 evaluation. The fact that the SPDS is installed

.and operating in the control rooms allows the operators to become familiar with the system and how it operates without relying upon it. .

Considerable effort has been expended during the initial design of the SPDS to incorporate human factors principles. In addition, the ANO operations staff has played a vital role in the SPDS design and implementation, to ensure that the system will be responsive to the needs of the operators during normal and emergency conditions. A formal evaluation of the SPDS design will be conducted as a part of the Control Room Design Review (CRDR) program to determine if human factor principles have been properly incorporated. The evaluation will focus on equipment location, display

[ formats, operator interfaces, and compatibility with the E0Ps.

1 The development of the SPDS validation program and training program is currently underway. These programs will be implemented prior to making the SPDS operational. The projected dates for the operation of the SPDS with j existing available inputs is January 10, 1984 for ANO-1 and June 1, 1984 for AND-2.

i The Safety Analysis for the SPDS will identify the critical safety functions, the parameters required to monitor these critical safety i functions, and a basis on which the selected parameters are sufficient to assess the safety status of each identified function over a wide range of events. The SPDS Safety Analysis is expected to be complete by June 29, 1984 for ANO-1 and April 15, 1984 for ANO-2.

For the SPDS to be completed may require the incorporation of some .

parameters identified in the R.G. 1.97 evaluation. Since the number of 3-2

4 modifications that may' result from the R.G. 1.97-review is unknown, the dates for. declaring the SPDS complete can only.be estimated. It is expected the SPDS will be complete for.ANO-1 by the end of the seventh refueling 4

outage (or-approximately June 15, 1986) and in ANO-2 by the end of the fourth refueling outage (or approximately December 15, 1985). Further clarification on these dates will tue provided with the submittal of the SPDS:

- Safety Analysis for each unit. As previously mentioned, updates on the status of the SPDS will be provided to NRC every six months.

" Figure 3-2 illustrates the fact that the TSC and EOF data display systems

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are-extensions of the SPDS network. Hence, the operational ~ dates for the TSC'and EOF data display systems ~will be:in time frames consistent with the operational dates for the AN3-1&2 SPDS (See Figure 2-2).

The integrated schedule for the SPDS implementation for ANO-1&2.is incorporated in the Integrated Implementation Plan, a simplified version of

which is shown in Figure 2-2. The integrated schedule demonstrates the

relationship of thc SPDS implementation with other Supplement 1 issues (i.e. -

CRDR, EOPs, R.G. 1.97 and ERFs).

l Due to the-advanced state of AP&L's SPDS design and implementation we do not feel a request for a preimplementation review by the NRC is appropriate.

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w FIGURE 3-1 SPDS AENORMAL TRAN5IENT OPERATING GUIDELINES DISPLAY 3-J

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FIGURE 3-2 3-5

1. 1 4 >

4 E4.01 CONTROL ROOM DESIGN REVIEW (CRDR)

The Control ' Room Design Review (CRDR) for: Arkansas' Nuclear,0ne' Units 1 and 2 e

.is very early in'the project's planning phase. . AP&L management acknowledges

~

-the importance of the CRDR as'welluas recognizing that:the review is a major

. undertaking' Thus, AP&L management will make every. effort during the planning phase to ensure'that the~CRDR meets theLobjectives of the NRC's

' guidelines. Also, in view.of.the guidelines,-AP&L is giving'special

~

attention to integrating this effort with the Emergency Operating.

Procedures, Regulatory Guide 1.97 and the Safety Parameter Display-System.

tin this early planning phase, an ~ organizational structure has been

y 1 implemented to develop AP&L's approach to perform .the CRDR for JAN0-1&2 =(see Figure 4-1).

This organizational structure evidences the multidisciplined i approach AP&L is utilizing to accomplish this review.. Because of the nature of the CRDR, AP&L believes the multidisciplined organizational concept is needed to provide a meaningful CRDR. .AP&L management ~ anticipates that this ~

organizational ~ structure ~will-completely meet the needs of the CRDR.

< However, as the project progresses, AP&L will make necessary changes as the situation or circumstances warrant.

'l Within this organizational structure, a CRDR-Team Leader is coordinating AP&L's efforts. In addition, a nucleus of individuals representing the various organizations are assigned-to plan, organize, and integrate the initial CRDR activities.

This CRDR Team, which is composed of experienced engineers and licensed i

operators, is in the process of evaluating the NRC's Guidelines for Control 3 Room Design Review (NUREG 0700) with the express purpose of developing the F program plan. The importance of this review is being emphasized in order to adapt the six-review processes identified in the! guidelines specifically to Arkansas Nuclear One. Also, this review is being emphasized to obtain the 4

positive benefits resulting from effective program planning.

In addition to just beginning a detailed review of the_ guidelines, the CRDR Team recognizes the special contribution a qualified human' factors consultant can make to a meaningful CRDR. Thus, the CRDR Team is planning to select a human factors consultant who will then become an active member t

of the CRDR Team. The consultant will actively participate as a team member as well as utilize their human engineering knowledge and experience in performing essential CRDR activities.

i Progress is being made on the selection of a human factors consultant. The ,

l- CRDR Team has conducted pre-bid conferences with potential consultants for

' the purpose of carefully evaluating their qualifications. The CRDR Team will proceed through normal AP&L procedures until the successful human

' factors consultant is selected.

While proceeding through the consultant selection process, the CRDR Team is also concentrating on the development of the program plan. However, because of the significant role of the human factors consultant, the program plan c will not be submitted to the NRC until the consultant's experience and resources have been appropriately considered. -

4-1

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-I m

Our-current projections are to submit the program plan for ANO-1 and ANO-2 to the'NRC by November 25, 1983. It must be emphasized that this is a proje'cted date and is subject to change as project progress dictates.

The submittal.of the program. plan will formally outline'AN0's CRDR. At this very early stage of the CRDR and without input from the human factors consultant, a date for the submittal of the CRDR Summary Reports is undefined. .However, along with the submittal of the program plan, AP&L will

-submit projected dates for submittal of the ANO-1 and ANO-2 Summary Reports.

p The projected completion dates.for those modifications which may be proposed in the Summary Report will be provided with the Summary Report.

i 4

4 e

1 4-2

CONTROL ROOM DESIGN REVIEW TEAM ORGANIZATION l

NUREG 0737

, SUPPLEMENT I PROGRAM CO ORDIN ATO R I

4 CRDR TEAM LEADER

! u L

CROR CO N SU LTA N T t

G.O. NUCLEAR ANO - l SERVICES I&C ANO - 2 ANO ENGINEERING PLANT PLANT OPERATIONS (SYSTEMS ENGR.) O P E R ATIO N S O PER ATION S ASSESSMENT

, FIGURE 4-1

5.0 REGULATORY GUIDE 1.97 (R.G. 1.97)

' AP&L has not as of yet ceveloped a formal position on Regulatory Guide 1.97;.

however, we have embarked upon a program which will ultimately result in a logical integration of the Supplement 1 requirements pertaining to R.G.

1. 97.~ The tasks identified for developing AP&L's position on R.G. 1.97 for ANO-1 and 2 includes:

-(1) Definition of Type A variables using Emergency Operating Procedures; (2) Identification of existing instrumentation for each R.G.1.97 variable; (3) Preparation and documentation of existing compliance status for Type A through E variables including range, environmental qualification, seismic qualification, quality assurance, redundancy, power source, control room display, availability in the Technical Support Center / Emergency Operations Facility.

(4) Identification of all items of non compliance with the Regulatory Guide, development of a position regarding the need to achieve compliance, and justification for deviations.

(5) Development of an implementation schedule for any required modifications; and (6) Preparation of a R.G.1.97 Position Document for submittal to the NRC.

A B&W Owners Group Task Force has been established to formulate and fully justify a generic position on R.G. 1.97 for B&W NSSS plants. AP&L will utilize this effort for accomplishing steps 1 and 4.

Our current projections for the submittal of the R.G. 1.97 Position Documents are June'29, 1984 for ANO-1 and April 15, 1984 for ANO-2. Each unit's Position Document will identify those instruments requiring modifications and provide schedules for these upgrades. Additionally, the Position Document will provide justification for deviations from R.G. 1.97 where modifications are not deemed necessary.

5-1 m m, y,---,e , , 4,_, ep - e--,. e --<- --y--

6.0 UPGRADE EMERGENCY OPERATING PROCEDURES (EOPs)

Plans for the upgrade of the ANO-1 and 2' emergency operating procedures began.in the summer of 1979 following an evaluation'by AP&L of the TMI-2 accident. The upgraded ettergency operating procedure for ANO-1 was implemented-during the last refueling outage. ANO-2's upgraded emergency operating procedures are currently scheduled for implementation during the fourth ANO-2 refueling outage. A description of the ANO-1 procedure development process is provided in Appendix 6A. This description is a reprint of a technical paper entitled " Abnormal Transient Operating Procedures", prepared by Mr. Daniel H. Williams for an American Nuclear Society Topical Meeting this fall and is being provided here for your infrmation so that we can provide you a better understanding ofJour progress to date. The AND-1 E0Ps were developed with human factors in mind and are function oriented to improve human reliability and the ability to mitigate tha consequences of a broad range of initiating events and subsequent multiple failures or operator errors, without the need to diagnose specific events. .ANO-1 operations personnel were trained on the procedure during the recent refueling outage to assure their readiness when the unit came back on line in April 1983.

The development of the ANO-1 E0Ps was also coordinated with the NRC through numerous meetings and correspondence between AP&L, the B&W Owners Group and the NRC.

-The Procedure Generation Package for the ANO-1 E0P is provided in Appendices 68, 6C, 60 and 6E to this section. Appendix 6B is the ANO-1 plant specific technical guideline and is provided in Volumes 2 and 3 to this submittal. Appendix 6C is the ANO Emergency Operating Procedure Writing Guidance. Appendix 6D is the description of the program used for validation of the E0Ps. Appendix 6E is a brief description of the training '

program for the operator.

In addition to the verification and validation program described, the B&W simulator in Lynchburg, Virginia was used in June 1980 to aid in preparing the technical guidelines, in October 1982 for a preliminary exercise as an informal checkout before entering the verification and validation program and again in February 1983 after the implementation of the E0Ps as a final

check of the procedure dynamics. Results of the February 1983 simulator l exercise and comments from the operators during training have been used to generate revision No. 1 to the E0Ps. This revision was generated under a modified procedure revision control designed to maintain the high quality of the E0Ps now in place. The revised control makes use of the writing guidance, the bases document called for in the writing guidance and evaluation of appropriate levels of verification and validation for future i changes. The plant specific technical guidelines have not yet been modified l to incorporate display modifications and some procedural modifications now in place but it will be as part of a routine update process.

l l In an effort to maintain consistency between the emergency procedure approaches taken on ANO-1 and ANO-2, emergency procedures for ANO-2 will be written with a similar procedural structure and approach as those for ANO-1.

The ANO-2 procedures will, of course, be based on technical data applicable 3

6-1

. . , _ - _ _ ~ . _ _ , , . . _

to ANO-2. The applicable documents are, therefore,_CEN-128, " Response of Combustion Engineering Nuclear Steam Supply Systems to' Transients and-Accidents",1and the ANO Abnormal Transient' Operator Guidelines (ATOG). The ANO-2 upgraded emergency operat.1g procedure is currently planned for implementation by the end of fourth ANO-2 refueling outage. Based on the current refueling schedule, which calls .for the fourth refueling to begin on September 15, 1985, the submittal of the final portion'of the requested Procedures Generation Package for ANO-2 will be submitted by June 15, 1985, (three months prior to implementation). The attached writing guidance (Appendix 6C), validation program description (Appendix 6D) and training program description (Appendix 6D) are. applicable to ANO-2 as well. Details of the validation program and training program may vary somewhat for application to ANO-2, (e.g., validation scenario list). Only signi#icant departures, if any, from these two program descriptions will be submitted for ANO-2. Otherwise, the Procedures Generation Package will consist only

'of the plant specific technical guidelines.

i i

l j

i

[

6-2 s

--s

J i

APPENDIX 6A 1

i ABNORMAL TRANSIENT OPERATING PROCEDURES By Daniel H. Williams, P.E.

March 1983 l

l 5

6A-1

ABNORMAL TRANSIENT OPERATING PROCEDURES Within 2 months following the Three Mile Island Unit-2 incident, both Arkansas Power & Light Company and-Babcock & Wilcox Company had identified the advisability of a new approach to emergency. operating procedures.

The existing procedures at that time were based on safety analysis codes and

" limiting" or " worst case" events rather than realistic analyses and event sequences. The-procedures needed to be based on efforts designed for procedure development, not efforts designed to meet conservative safety analysis requirements.

On June 13, 1979, at a B&W Owners Group meeting in Atlanta, an emergency -

operating procedure development program called Abnormal Transient Operating Guidelines (ATOG) was initiated. An early decision was made to proceed on a plant specific basis with the program because of a general concensus that past efforts to be effective in this area with " generic" products had failed because of significant relevant plant differences. This required the use of enormous volumes of plant specific design information in the ATOG efforts.

i By the time that the Nuclear Regulatory Commission had issued NUREG-0578 for implementation (September 13, 1979) requiring new emergency operating procedure efforts, the B&W Owners Group had met with them three times to announce and subsequently describe the ATOG program and, significantly, to introduce to them the concept of symptom oriented procedures which had groan from AT0G program efforts to date.

The traditional approach to transient and accident control had been to develop many " emergency" procedures, each based on a postulated event such as loss of main feedwater. The operator was then required to study this event and memorize its symptoms and immediate actions. If a loss of feedwater occurred, he was expected to recognize it, perform the appropriate immediate actions, and then use the event oriented loss-of-feedwater procedure for determining follow-up actions. This approach was largely.

built on safety analysis concepts from regulatory requirements and, in fact, was believed to be a regulatory requirement itself by many, though such belief was technically inaccurate.1 This approach had several inherent drawbacks:2 l

1. At time zero, the operator had to correctly diagnose the intiating

event. He did this mentally, based on training or prior experience.

! Experiments show that the diagnosis is done based on a grouping of

( symptoms, their sequence, and their change independent of the use a l procedure and that there is a significant frequency of different diagnoses by different highly qualified individuals under these l

conditions of instant evaluation.3 After takirig several actions, j_ depending on this instant evaluation, the operator then had to refer to

! the event oriented procedure that fits his diagnosis. If he were to l treat a small steamline break inside the reactor building, but actually i had a small loss of coolant accident (LOCA) inside the building, he

[ would be tracking through the wrong procedure. He would eventually recognize this misinterpretation; however, by then he might be well into the transient and possibly confused. -

6A-2 n-g , , - --

F w

. ABNORMAL TRANSIENT:0PERATING PROCEDURES

~Within'2 months following the Three Mile Island Unit-2: incident, both Arkansas Power & Light Company and Babcock & Wilcox-Company had -identified the. advisability of a new approach to emergency operating. procedures. 'Too-much of the existing emergency operating procedures were-based on regulatory 1

Ldriven considerations-instead of sound ones. -This had resulted in procedures based 7n. safety analysis codes and " limiting" or " worst case".'

events;rather than realistic analyses and event sequences. .The procedures needed to be based on efforts.. designed.for procedure-development, not

!  ; efforts' designed-to meet regulatory safety analysis requirements.

~

'On June-13, 1979,' at a B&W Owner's' Group meeting in_ Atlanta, an emergency-l; ' operating' procedure development program called Abnormal Transient Operating

. Guidelines (AT0G) was initiated. An early' decision'was made to.' proceed on a F plant specific basis with the program because of a general; concensus that past efforts to'be effective in this area with;" generic". products:had. failed.

l because of significant relevant' plant differences. 'This required the use of enormous. volumes of plant specific design information in the ATOG efforts.

I Bylthe time that the Nuclear Regulatory Commission had issued NUREG-0578 for 1

implementation (September 13,1979) req'uiring new emergency operating procedure efforts, the B&W'0wners Group had met.with them three times to

.announce and subsequently describe the ATOG program and, significantly, to l introduce to them the concept'of symptom oriented proceduresLwhich had grown ll from AT0G program efforts to date.

- The traditional approach to transient and' accident ~ control had been to 1- develop many " emergency" procedures, each based on a postulated' event such as loss of main feedwater. The' operator'was then raquired to study this event and memorize'its symptoms and immediate actions. If a loss of

! :. feedwater. occurred, he was expected to ' recognize it, perform the appropriate

.e - immediate actions,' and then use the' event oriented loss-of-feedwater ,

procedure for determining ~ follow-up actions. This approach was-largely

, built on safety analysis concepts from regulatory requirements and, in fact,-

was believed to be a regulatory requirement ~ itself by many, though such b belief was technically inaccurate.1 This approach had several inherent

[

sdrawbacks:2

1. At time zero, the operator had to correctly diagnose the intiating event. He did this mentally, based on training or prior experience.

Experiments show.that the diagnosis is done based on a grouping of symptom's, their sequence, and their change independent of the use a procedure and that there is a significant frequency of different diagnoses by different highly qualified individuals under these conditions of instant evaluation.3 After taking several actions, depending on this instant evaluation, the operator then had to refer to the event oriented procedure that fits his diagnosis. If-he were to c treat c small steamline break inside the reactor building, but actually had a small loss of coolant accident (LOCA) inside the building, he would be tracking through the wrong procedure. He would eventually h recognize this misinterpretation; however, by then he might be well o .into the transient and possibly confused.

i b-6A-2

_,..~...__d- _ _ - . ~ _ , _ - - . _ . - _ _ -

2. Procedures had to be written to cover every conceivable initiating event. If the operator correctly diagnosed a loss of nonnuclear instrumentation power and no written procedure covered that event, his actions would be based only on experience which, for an abnormal transient may be quite limited. Simply stated, he used an unwritten procedure consisting of what he thought he should do to mitigate the event.4

3. If more than one event contributes to the transient, the operator found himself working two or more procedures at the same time. For instance, if a main steam safety valve failed to reset following the loss of main feedwater, the operator had to use the loss of feedwater procedure and small stream-line-break procedures (if available). These procedures may conflict end he would have to decide on a priority between them -

with no convenient method of shifting between the two procedures.

Writing a procedure to combine these two events is possible; however, if just a few more failures are considered (e.g., the power-operated relief valve or spray valve remains open), the number of combinations of failures, along with possible initiating events, quickly increases.

Even if writing the appropriate procedures was attempted, the operator's ability to pick the correct procedure would certainly diminish.

4. Because of these limitations, most operators were likely to use no specific procedure. They would use training, experience, intuition, etc., to bring the plant under control. They would then choose what they think is the closest procedure to what is happening and confirm their actions or see if they overlooked anything.a To correct these deficiencies, it is necessary to step back from the traditional approach and examine what the operator's role is. His role can be defined as three roles 4 which are to:

1. keep the plant set up so that it will respond properly to disturbances,

2. operate the plant so as to minimize the likelihood and severity of event initiators and disturbances, and

3. assist in accomplishing safety functions during the event.

l Since the emergency operating procedures are for use during the event (whether performed only as a result of training or as a result of training and direct use) it is the safety functions on which we must focus. Ten safety functions have been defined into four classes.5 Figure 1 shows these ten in their four classes. While all four classes are important, one clearly stands out during a transient. The indirect Radioactive Release Control class is not directly transient related. The Maintenance of Vital Auxiliaries is an equipment troubleshooting function during a transient. As

a. result it can, in general, be handled separately on a detailed basis from plant control instructions and incorporated on a cognizance level in plant control instructions. The Containment Integrity class is unnecessary if the Anti-Core Melt class is accomplished and is, in general, a more time lenient class of functions than the Anti-Core Melt class. The Anti-Core Melt class of functions stands out as the front-line set of vital and closely 6A-3

interrelated time critical functions to which the other classes are either backups or auxiliaries. To accomplish this class of functions, the operator must ensure the continuous removal of decay heat (or fission heat in the absence of reactivity control) from the fission products to the ultimate heat sink. By adjusting the priorities and concentrating efforts on maintaining proper heat transfer along this path, he can protect the core and minimize radioactive release. To give the operator this capability, a concept of symptom-oriented (as opposed to event-oriented) procedures was utilized in the ATOG program. The symptoms are based on upsets in heat transfer from the core to the coolant and from the coolant to the steam generators and can be roughly. correlated to the Anti-Core Melt class of safety functions. The symptom-oriented procedures thus focus on core cooling first and on event identification second.

Two other basic precepts significantly affected the ATOG effort and its ultimate product. One was that a basic part of the plant operating structure in which the emergency operating procedures will function is an-intelligent, capable operator. As a result, a philosophy of trying to optimize the operator's effectiveness instead of minimizing his impact pervaded the ATOG effort. One outcome of this philosophy is the use of a companion document for training and study that explains many of the why's and how's that form the basis for the procedures. This eliminates blindly following the procedures as a choice for the operator for it supplements his qualification training with material directly related to the basis for the-instructions he has been given, a basis that has not always been communicated in the past. This approach communicates more than a prescriptive set of directions for operating the plant. The designer's understanding of plant behavior during the event, achieved primarily through analysis, is imparted as thoroughly as possible so that the plant operator will understand the basis for the procedure and can deal with variations which might confront him in an actual transient.8 The second basic precept was that the attention paid to how or how likely the plant would get into a certain situation would be minimized. The philosophy was to, within practical limitations, answer the question, "If the operator finds the plant in this situation, how does he get out of it?"

The practical limitations became the following. '

1. Initial conditions would be in the power range.

2. Where core physics was relevant, equilibrium core conditions would be used.

3. No subsequent passive failures would be considered after the initiating event.

4. The operator was given the opportunity to act correctly, incorrectly or not at all when called on to act by a procedure. No random operator errors were considered and operator actions were assumed to be complete within a system.

5. ATWS would not be explicitly treated.

No single failure or probability criteria were applied.

6A-4

Six classes of initiating events were selected to build on. These were selected with the intent of addressing all types of events without explicitly considering all individual events. It was expected that the individual events not explicitly considered would be covered because they would be of a type addressed 'and their variations would only go to timing and quantities not critical in the symptom oriented procedures. Results indicate that the expectations were well founded though proof is inherently impossible for it involves proving a negative, i.e. showing that there are no events for which the resulting procedures are inappropriate *. The six event classes are:

1. LOCA

2. Loss of Feedwater

3. Small Steam Line Breaks

4. Loss of Off-Site Power

5. Excessive Addition of Feedwater

6. Steam Generator Tube Rupture Two diagrams were prepared for each plant for each of the five** events. A functional event tree in block format was prepared. The branches were terminated by reference to a duplicative branch or when:

1. A stable plant condition was reached

2. Another of the six events was created (e.g., some sequences lead to consequential LOCA's) or

3. Inadequate core cooling conditions were created When decision points were based on flow rates three branches were made:

1. No flow up to but not including adequate flow

2. Adequate flow

3. Too much flow.

After the first plant's event trees were completed the effort and time needed for the subsequent plants was optimized by the use of safety sequence diagrams 7 (SSD's) which organized the plant design data to show how the specific plant systems and subsystems are expected to function in various operating modes and in the event of failures. An SSD was prepared for each plant for each event ** and included relevant non-safety grade equipment.

Comparison of one plant's SSD's with another plant's SSD's aided in the identification of where the first plant's event trees needed to be modified l to be applicable to the second plant. In effect, the SSD's served as a l nutshell depiction of the plant design as it relates to the safety functions. The relationship of the event trees and SSD's to each other and to the entire AT0G program is depicted in Figure 2.

The first draft event tree was delivered to NRC on October 15, 1979 and its companion SSD on November 7, 1979. For the purpose of presentation, a portion of a loss of feedwater event tree is provided in Figure 3.

6A-5

Certain paths on these event trees were selected for quantitative analyses.

These analyses were primarily done with best estimate codes. The paths selected were the design success path and all single failure paths except those for which an exceptionally low probability, insignificant effect, etc. , can be shown or those for which no operator action is required for a successful conclusion. Any other path considered to be an important or likely outcome of the initiations transient was also selected. The extent of quantitative analyses for event trees prepared for plants other than the first plant was reduced to avoid waste of resources.

In addition to these two types of diagrams, another type was prepared for each plant. These diagrams, called System Auxiliary Diagrams (SAD's), show for each front line system, all supporting equipment which must function for the front line system to be operable. These diagrams identify the power supplies, room coolers, pump coolers, initiating signals, tanks, valves, etc., that support the front line system. For Arkansas Nuclear One Unit-1 (ANO-1), SAD's were prepared for the following systems:

1. High Pressure Injection

2. Emergency Feedwater

3. Chemical Addition

4. Low Pressure Injection

5. Reactor Building Emergency Cooling

6. Reactor Building Isolation

7. Reactor Coolant Pressure Control

8. Electro-Hydraulic Control

9. Turbine Bypass

10. Reactor Building Spray Results of the analyses were documented in a transient information document (TID) for each plant. The TID's:

1. Tie the analyses to the companion document for training and study

2. Tie the follow-on plant analysis back to the ANO-1 work, and

3. Provide a traceable list of references back to the AT0G input material.

A separate TID was produced for each initiating event for each plant. The types of information contained in the TID are:

1. Identification of the event, plant and event tree.

2. Discussion of systems used to control five functions and how these systems compare to the lead plant, ANO-1. The five functions are:

a. Reactivity

b. Primary Inventory

c. Primary Pressure

d. Secondary Inventory

e. Secondary Pressure 6A-6

The comparisons emphasized the differences which affect plant performance and include a discussion of the system's properties (i.e.,

flows, pressures, etc.).and the function (i.e., actuation setpoints'and what the system doeslafter actuation). j

3. Data from actual plant transients which provided information on plant response and confirmed the analytical predictions. Some of this data was included in the companion training and study document in the' form of plots of the data and a discussion of the event.

4. Discussion of how a plant will respond to a given event compared to ANO-1. This documents that the ANO-1 analytical work is applicable to the plant of interest or identifies the expected plant response if it

! is different. Specific information identifying changes or additions to the ANO-1 companion training and study document to make it applicable to the plant of interest is also provided.

5. Additional information which the analyst feels is important enough to be included.

< 6. References to materials used in preparing the TID's.

L A study of the results of work done for each initiating event was done to identify what symptoms needed to be used to base the procedures on. A minimum set of identifying symptoms was prepared for each event and the minimum sets for each event were compared. The consistent symptom of reactor trip was identified and designated as symptom for entry into the ATOG procedure (forced shutdown to avert a trip was included as a symptom for entry). All the events but one were then found to be correlatable to three symptoms.

~

The odd event was steam generator tube rupture which was I

determined to be unique enough to require specific treatment. The three

)

symptoms used were found to adequately reflect the " health" of the thermodynamic process around the reactor coolant system and its heat transfer coupling to the secondary plant.s These three symptoms are:

1. Inadequate Primary Inventory Subcooling - If the operator knows the primary fluid is in a liquid state, he is assured that it is available and capable of removing heat from the core and transferring it to the steam generators.

2. Inadequate Primary-to-Secondary Heat Transfer - This symptom addresses the primary method of removing heat from the reactor coolant system to the secondary plant. It indicates the thermal coupling between primary and secondary across the steam generators.

3. Excessive Primary-to-Secondary Heat Transfer - In this case, the symptom is indicative of a secondary side malfunction, e.g., loss of steam piassure control or steam generator overfill.

The identification of the symptoms led to the discovery of a tool to efficiently. monitor these symptoms. The tool was a pressure-temperature l (P-T) plot with a saturation curve as shown in Figure 4. Variations of this tool have been developed at each application location but its basic features

( are described below. The area above and to the left of the saturation curve 6A-7 l

~

y e

1

~

is tiie subcooled region. 'The are~a beloy and ~ to the right is the superheated region. Reactor coolant system hotzleg temperature-(T - and cold leg c

areplotted.asfunctionsofreactohbo)olantsystem-

pressure.

temperature The (T gjgu) ration _ temperature corresponding to the steam gen pressure is plotted'as a vertical-line.

Various limit and-margin lines can-also be overlaid, e.g. margin to saturation and a' box outlining the region -

in which Thot and Tcold are expected:to remain during a transient.

A typical' plant response tofa reactor trip is sho'wn in Figure 5. - T -is not' plotted but.should merge with T as-thedecayheatrapidlydr$1d BothtemperaturesshouldapproachtNOtsaturation' temperature of the-secondary side of the: steam generator for proper primary-to-secondary heat -

transfer.

~

~

Each of the basic' symptoms leave their unique signature on this tool as disp 1_ayed in Figures 6A, 6B, and 6C. .Use of this tool enables an _ operator's priority to be fixed on controlling the plotted parameters within, target-bounds. . If successful he will;always bring the plant to a safe condition or ,

head the plant in the right direction if-the parameter's move outside the target bounds.' This will be the case regardless of whether he has properly diagnosed:(or diagnosed at all) the event which has occurred or not.

However, use' of the tool does not discourage an operator._from diagnosing the cause of the transient for that must eventually be done and the information ,

available in the control room toTan intelligent trained operator will normally lead automatically.to a diagnosis. What the tool permits is proper-actions without diagnosis or with misdiagnosis. This tool's effectiveness has~been dramatically exhibited by the application of data'from the Three Mile Island Unit-2 incident 2 and by its.use in the Crystal River incident of February 26,-19809'10 even without formal procedures for its use. It-lends

-.itself well to a.CRT graphic display. Such a display was in the Crystal River control room on February 26, 1980 and has been in use.at the B&W simulator since the fall of'1979. A permanent color display has been in operation as the focal point of the Safety Parameter Display System (SPDC) at ANO-1 since March of 1981. This ANO-1 display has been described by Sandia Labs 11 as "an excellent diagnostic tool" and was' credited in their Interim Reliability Evaluation Program with eliminating the potential for an '

operator failing to monitor margin to saturation and increasing the probability of proper and timely recovery actions from failures and operator errors. A Honeywell study team 12 commented that the ANO-1 display was one of the best examples they had seen of providing an operator. with ivormation concerning the state of his plant instead of information restricted to  ;

parameter values. '

The P-T diagram tool and potential display were presented to NRC on February 22, 1980 at which time ANO-1 event trees for the remaining four events were delivered. On April 16, 1980, all the SAD's and SSD's for ANO-1

.were added to the previous documentation delivered to NRC as well as instructions for their use.

All of this effort established the general approach to take in managing an abnormal transient. The next step was to produce procedures implementing this approach. Part of this production involved trial use with ANO-1 operators. Involvement of the AN0-1 operations staff was a goal from the beginning of the program for two reasons:

6A-8

1. The completed product would be better understood and accepted if it was

. partially produced by the plant operations staff.

2. Because the highest-level of expertise in the area of operational methods and strategy lay.in the plant operations staff, the quality of the product would have suffered without their involvement.

Individuals from the plant operations staff had already participated in detailed review and comment on the various documents described above. In June of 1980 members of the plant operations staff were asked to try out preliminary procedures on the B&W Simulator in Lynchburg, Virginia. The results of this trial use are adequately described by the comments of one of the most experienced operators involved that the preliminary procedures instructed him to do things "the way he would have done it anyway".13 By August of 1980, draft versions of the companion training and study document and of the procedures were available. They were labelled Part II and Part I respectively. Part II contained the following sections:

Volume 1 Volume II Heat Transfer Excess Feedwater Subcooling Loss of Feedwater Natural Circulation Steam Generator Tube Leaks P-T Diagram Loss of Offsite Power Diagnostics & Mitigation Steam Line Break Backup Cooling. Loss of Coolant Accident Equipment Operation Stability A review of these draft Parts I and II by Kinton, Inc. provoked the following comments:14

"...AT0G Part I and Part II materials represent a very good effort to integrate observable events and theory. The theory in Part II is primarily job relevant, not a totally abstract discussion of heat theory in general terms. It is limited (with some exceptions) to heat transfer in the nuclear power plant systems with good references to observables... The shift from general theoretical information to job relevant, 6A-9

specific information is a shift from the laws of physics, heat transfer, fluid flow and neutron processes to what users perceive (see, hear, feel) and what they do about the perceptions. . . In our cpinion, the ATOG Part I and Part II materials represent the shift that is needed and that is probably the most appropriate amount of shift."

Indeed the comment has been made about Part II that one cannot tell that it was written by an engineer.

The main effort on Part I was to put the operational methods and strategy that had been developed into an optimum format. When Part I and Part II were delivered to NRC on August 21, 1980, Part I was formated with a parallel depiction on facing pages. Specifically, the procedural steps were depicted by flowchart on the left facing page and by double columnar format on the right facing page. The flowchart, in some cases, would include more than was on the right facing page in which case that portion would be shaded highlighting the remaining portion which was covered on the right facing page. The two columns were arranged such that the left column calls for a verification and the right column calls for remedial action if the verification has a negative result. Figure 7 provides an example of the layout in this early version. Part I was organizcd into three sections.

I. Immediate Actions II. Vital System Status Verification III. A. Treatment of lack of adequate subcooling margin B. Treatment of lack of primary-to-secondary heat transfer C. Treatment of too much primary-to-secondary heat transfer D. Follow-up actions for OTSG tube rupture E. Cooldown proceduresSection II referred the user to the proper Section III subsection but only if an abnormal condition was identified in performing Section II. The cooldown procedures were provided for use after the plant was brought to a stable condition.

On November 29, 1980, the ATOG approach was presented to the Three Mile Island Unit-1 subcommittee of the Advisory Committee on Reactor Safeguards (ACRS) using the General Public Utilities version of the display including an application of data from the Three Mile Island Unit-2 incident. The reaction brought comments of "something magnificent", "have my compliment",

"never seen anything a rational as this" and " outstanding". A similar presentation to the full ACRS on December 4, 1980 provoked similar i reactions.

The procedures themselves were still not satisfactory to AP&L. They had an inconsistent level of detail and the "go to" looping was too complex for 6A-10

practical use. In addition the content still needed some refinement. So, in 1981, AP&L began to refine the draft Part I and to develop a method to effectively implement the refined procedures.*** One of the unsatisfactory aspects of Part I was the format. The flowchart on the left facing page was not well received by the plant operations staff and it was felt that the columnar format on the right facing page could be improved. A survey of "off average" situation procedures in eight other industries revealed that seven of those industries used layered format 3 or a format with more than one level of detail in a form that facilitates referring to the more detailed level only when the less detailed level is insufficient for that person, moment and situation. In an experiment conducted in the same study3 using nuclear operators and comparing the advantages of an enhanced narratiu format, columnar format and layered format the columnar or layered format were generally preferred. Without knowledge of this study, the ANO plant operations staff developed an effective combined columnar and layered format.

In the combined format the use of two columns is continued. The left hand column states briefly the objective to be accomplished. This credits a trained operator with knowledge of the "how to" and provides easily and rapidly identifiable general direction in managing a plant transient. This column contains no component numbers, no setpoints, no lists and no explanations. All cautions, notes and go to statements extend across both columns. The objective stated in the lefthand column relates to all actions called for in the righthand column. The righthand column expands on the objective stated in the lefthand column. This column may contain component numbers, setpoints, lists and explanations. The righthand column can state how to accomplish the corresponding objective stated in the lefthand column.

For example, if the lefthand column says to verify proper operation of a system, the righthand column may list the parameters that indicate such proper operation, or if the lefthand column says to isolate a system, the righthand column may list the valves that must be closed to accomplish that isolation. This provides possible needed and readily accessible information for the inexperienced operator or the operator who has temporarily forgotten a detail without cluttering up the lefthand column with information not needed by most operators. Figure 8 illustrates the combined format.

Implementation of the procedures tests the guidelines' scope and appropriateness since they must be a workable part of the overall plant procedures system. Existing post-trip procedures had to be checked against the new procedures to determine the following:2

1. Necessary actions outside the development program scope but needed for a post-trip procedure in the same time frame. This assures that, although everything may not be considered, the adoption of AT0G does not decrease in any area the adequacy level found in existing procedures. Some actions in the previous procedures may be found to be good but not necessary, and either be delayed or relegated to a lower level of instruction. The goal is to maximize simplicity.

2. Actions that should be included in an instruction for longer term action. Current post-trip procedures include many necessary follow-up actions that are not appropriate for AT0G, but must be included somewhere. Three actions, identification of these items, determination 6A-11

~

or the form in which'they should be given, and optimization of the interface between the form in' which they are given and ATOG , are necessary to make ATOG a workable part of the overall plant procedure system'. Again, the' goal is to maximize simplicity.

'3. .Any post-trip procedures not accommodated by AT0G, but which must remain _ intact. One goal of ATOG is to eliminate these procedures, but that goal may not always be achievable. Any such procedures must be entered in a manner compatible with-ATOG implementation.

.Given the procedure entry condition of plant trip or condition requiring immediate shutdown.to avert a trip and given the ATOG developed operational methods and strategy, by late-1981 the following existing ANO-1 emergency procedures were identified that should be combined into one emergency procedure.

1. Blackout-

2. Reactor Turbine Trip

3. Degraded Power ,

4. LOCA

5. RCP trip (loss of all 4 portion only)  ;

6. Emergency Shutdown ,

7. OTSG Tube Rupture .

8. Loss of-Steam Generator Feed (to both Steam Generators portion only)

The following existing emergency procedures were identified as candidates to be reclassified as abnormal operating procedures.

1. Load Rejection

2. Turbine Trip (changed to turbine trip from less than 20% power)

3. Moderator Dilution t

4. Loss of Condenser Vacuum

5. High Activity in RCS

6. Loss of Instrument Air

7. Loss of Service Water

8. RCP Trip (except for loss of all four) -

9. Loss of Reactor Coolant Makeup

10. RCP and Motor Emergencies

11. Loss of Neutron Flux Indication

12. OTSG Tube Rupture (for leaks within makeup capacity)

~

13. Loss of Steam Genevator Feed (for one steam generator only)

14. Pressurizer Systems Failure

15. Loss of Decay Heat Removal System

16. Remote Shutdown

17. Natural Emergencies One existing emergency procedure, Refueling Accident, was identified as a candidate to be incorporated into the Fuel Handling procedure.

Based on this procedure structure and operations staff preferences, Part I was reorganized somewhat into the following sections:

6A-12 j

l l

l l

l I. -Symptoms or Initiating Conditions

.II. Immediate Actions III. Follow-up Actions' IV. Tabbed Section for~ Abnormal Conditions A. Overcooling B. Loss of Subcooling Margin C. Overheating D. Inadequate Core Cooling

~

E. Tube Rupture F. Degraded Power G. Blackout H. Loss of NNI Power I. Main Steam Isolation J. ESAS K. HPI Cooldown L. Emergency Boration This' organization retains the feature in which the sections of Part IV are referred to only under abnormal conditions.

A decision was made to use both the AT0G operational methods and strategy

-and the combined format for ANO Unit-2 also so that the emergency procedure philosophy would be consistent between the units. This decision was made even though ANO-2 uses an NSSS supplied by a different manufacturer because it was felt that there is nothing unique to the B&W NSSS about a syrrtom oriented approach, a P-T diagram tool or the combined format. Accordingly ANO-2 has a display similar to the one in AN0-1 installed in the control room.

Perhaps the most critical portion of the effort-is the actual implementation process. I The initial rough draft outline of the emergency procedure was completed in March 1982. This involved a thorough review of existing emergency procedures. A requirement was set that the new emet gency procedure would contain the steps and philosophy of the old procedures as a minimum unless a -

specific change was justified. This provided a foundation from which to depart and facilitated a review of changes to be made under the provisions of.10CFR50.59. This decision also contributed to operator confidence in the new procedure and enableg. direction of special training attention to the changes. .

Considerable effort and thought went into the writing of the ANO emergency operating procedures. While this has not resulted in perfectly written procedures, it has resulted in certain favorable features that, in many cases, may be enj,oyed without being recognized. In order to maintain continuity in making future revisions and avoid the inadvertent destruction of these favorable features, an emergency operating procedures writing guidance was drafted in April 1982. This guidance attempts to provide the information necessary for the reviser to recognize the favorable features and utilize them in his revision efforts. The guidance does not attempt to address technical bases for procedure content but restricts itself to the features that have been incorporated generally in the writing of the emergency operating procedures. As guidance, it is also not intended to 6A-13

=

place restrictions on departures from such features or improvements that can

.be made to such features but does intend to assure that departures from the original.. features are made consciously. The guidance does not attempt to.

address all areas inherent in a quality documents that accomplishes an objective of efficient communication As a result, it does not contain-

~

instructions to. spell words correctly or to use words whose meaning.will be clear to the intended reader. The guidance includes seven sections.

1. Role of Emergency Operating' Procedures Within'the ANO Procedure System

2. Format and Level of Detail of Emergency Operating Procedures

3. Philc ophy and Approach

4. Control Room Interface

5. Consistency

6. Organization

7. Bases The section on consistency gives some conventions that were used in writing the emergency operating procedures for the convenience of the reviser but encourages the reviser to be aquainted enough with the emergency operating procedures to maintain consistency in the revision. Among other things, this section includes a list of common use nomenclature and abbreviations.

The bases section calls for a separate b'ases document consisting primarily of references to technical documents thereby identifying the source of the various instructions and numbers in the emergency operating procedures. The bases document will not provide the source of component numbers or basic design data but will provide the bases or references thereto of limits, parameter values, margins and specific instructions that have more behind them than meets the eye. Such a document enables the reviser to avoid unwittingly negating valid instructions because of a lack of understanding

, of them and provides a place for him to record the basis for the revision as well. The writers guidance merely calls for this separate bases document to be developed as a companion to the procedures. This guidance matured as the procedures did and things that evolved during the procedure writing process were incorporated. ,

The first draft of the mergency procedure was sent out for plant operations personnel review and comment in July 1982. In addition to the old procedures and the training and study document, use was made of small break LOCA guidelines; information generated from reactor vessel brittle fracture concerns, loss of instrument power concerns and void formation concerns; and experience gained'from the B&W simulator in Lynchburg, Virginia, as well as actual experience during plant transients.

Changes were also prepared for reclassifying the previously mentioned y emergency procedures to abnormal procedures. The majority of this effort involved the two procedures that were partially covered by the new emergency procedure and partially reclassified as abnormal procedures.

6A-14

The extensive use of plant operations personnel review resulted in refinement of the draft until in September 1982 a fully developed draft of the new emergency procedure was ready. A preliminary and informal exercise of this draft on the B&W simulator in October 1982 during a one week operator requalification session provided a final check out of the new procedure before going on to the verification process.

The verification process was used to ensure the consistency of the E0P with the writing guidance and the accuracy of the equipment designations in the new emergency procedure and to provide a basis for the 10CFR50.59 review of the E0P by comparing it against the existing procedures which the new emergency procedure was intended to replace. Figure 9 shows the checklist used to aid in accomplishing these things.

The writing guidan:.e was used to develop the criteria for Section I of the checklist. These criteria represented aspects of all sections of the writing guidance that lent themselves to translation into a checklist criteria. The verifier was also asked to have sufficient familiarity with the writing guidance and the new emergency procedure to make more general observations.

To make sure that, at worst, the transition to the new emergency procedure from the existing procedures did not involve a degradation of the procedure, a comparison of the new emergency procedure with the existing procedures which the new emergency procedure is intended to replace was made. This comparison looked at every instruction in the existing procedures to be replaced and determined that the new emergency procedure either had that instruction or that the instruction had been modified or deleted intentionally with reason. The verification comments included identification of the intentionally modified or deleted instructions and gave the reason. i All equipment designations were independently verified to determine that instructions in the new emergency procedure called for.use of the proper equipment. This included valve numbers, breaker numbers, buss numbers, etc.

After completion of the review portion of the verification, all comments that were generated were addressed either by procedure modification or by justification of the new emergency procedure as written. The comments indicated that the draft pad few problems within the scope of the verification. The verification did identify that special attention needed to be given to organizat.ional matching of the left and right hand columns.

Because of the difference in level of detail between the two columns, matching of the step numbering conventions between the columns was not straightforward. A substep "A" in the left hand column might end up corresponding to a substep "B" in the right hand column. Another notable finding was the need for negative GO T0 statements, i.e., there were locations in the procedure where plant conditions might tend to indicate the need to go to another location in the procedure but the procedure was written with the intention that the user remain in that location in the procedure. "D0 NOT GO T0" became an appropriate instruction along with the "GO T0" instructions that already existed. A limited nunber of other minor comments were also generated.

6A-15

.The resolution of the verification comments resulted in a revision of the draft emergency procedure before moving on to the validation process in December 1982.

The validation process. looked-at'the usability and effectiveness of the new emergency procedure on a more integrated basis. This was accomplished by-selection of a set of scenarios and walking through the procedure in the control room as applied to each scenario. All conditions and actions in the walk'through were simulated.

The scenarios were selected in such a manner as to exercise every instruction in the procedure. In doing so, of course, many instructions were exercised multiple times. Figure 10 shows the list of 10 basic sc'enarios with a total of 31 variations which was used.

To accomplish the walk through a set of scenario instructions for each scenario was provided to the evaluator. The evaluator, who was-the shift supervisor, directed the control room operators, who had the procedure, as to the conditions and circumstances as they came to them in following the procedure. The operators were not informed in advance of a situation. Upon discussing each~ step with the evaluator, the operators were told of any abnormal conditions as indicated in the, instructions to the evaluator. For example, .in a stuck rod scenario, when the operator was told by the procedure to verify "all rods on bcttom" and reported to the evaluator that they were, the evaluator corrected this observation by stating which rods were not on bottom and what position they were at. Both the evaluator and operator were given opportunity to comment both during and after the process of walking through the scenario. Comments were made on any aspect but each scenario was specifically observed for the items included in the validation checklist shown in Figure 11.

i The walk throughs themselves were accomplished over.a period of about four weeks on the back shifts. Actual elapsed time was about 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br />. Operator interest and participation was excellent even to the extent of some individuals working overtime to extend their involvement. One observation regarding the validation process itself was that some informal operator -

training on the procedure before the walk throughs would have enhanced the walk through effectiveness.

Again, as in the verification process, the comments generated in the validation process indiqd'ted that the procedure had been well prepared.

Forty-three comments were generated from the 31 scenario variations.

i Several of the comments resulted in additional steps in the procedure, some procedural notes were added and some steps were modified. Control room modifications addressed some of the comments and some of the comments were flagged to be addressed by training. In some cases, the lack of any action regarding the cominent was justified. The comments were quite constructive and also made each operator who participated in the validation process a part of the effort to develop the procedure.

,_ The resolution of the validation comments resulted in a revision of the draft emergency procedure before moving on to Plant Safety Committee review and approval.

6A-16

The Plant Safety Committee review and approval proceeded as it would have for any procedure revision. At this time, the Committee had before them documentation of the efforts that had already transpired. The procedure had also been revised to incorporate changes due to plant design changes installed during the refueling outage in process at the time. As part of the review package, the remaining existing emergency procedures being revised as abnormal procedures were also submitted to the Committee. In January 1983, the Plant Safety Committee approved the new emergency procedure and it was officially implemented.

The timing of this action was intentionally planned to occur during a refueling outage. This permitted implementation without the new procedure becoming immediately applicable. This was desirable in order to prevent the training on the new procedure to be accomplished on an official procedure, not still subject to substantial revisions which would initiate the need for significant retraining. At the same time, the training could still be completed for all shifts prior to the time that the procedure would become applicable. This advance planning on the timing permitted the procedure to be implemented with a clean break from the old procedure. There was no interim period during which some shifts had not been trained on extensively revised applicable procedures and operators did not have to undergo training on a draft version of a new procedure. In addition, this permitted the use of the normal requalification training cycle for the training.

The classroom training covered nine basic areas as follows:

1. Background and Philosoohy

2. Procedures Affected

3. Format of the New Procedure

4. Deviations From Old Procedures

5. Procedure Entry Conditions

6. Immediate Actions t

7. Follow-up Actions

8. Use of the SPDS P/T Diagram

9. Primary to Secondary Heat Transfer Concepts The Background and Philosophy gave a brief historical background of the development program and introduced the basic concepts of departure from event oriented procedures.

The next area identified _the deleted procedures, revised procedures and those that were reclassified from emergency to abnormal. New controls on emergency procedure revisions were also discussed.

The Format discussion not only introduced the combined format but covered other features such as the use of notes, cautions and "go to" instructions.

Seven specific areas of instructional changes from the old procedures were pointed out. Five were a result of licensing issues (reactor coolant pump trip criteria, pressurized thermal shock, inadequate core cooling, etc.),

one was the list of new specific parameters requiring a manual trip which

, was developed in drafting the entry conditions for the new procedure and one was those changes resulting from design changes installed during the refueling outage.

6A-17

The_next three areas covered in the training were addressed by complete coverage of each step of the emergency operating procedure with a detailed

-discussion to enable the operator to understand the technical bases for each step and the structure of the procedure.

The last two areas were discussed based on the companion training and. study document.

During the classroom training, the operators were requested to provide comments and suggestions as the training was conducted. These comments were evaluated for future procedure revisions and, in fact, resulted in some procedure refinements.

In addition to the classroom training, the validation walk through provided a considerable amount of training and the scheduled annual operator simulator training began using the new procedure in March 1983 after a final check out of the procedure dynamics on-the B&W simulator in late February i-1983.

The final checkout of the procedure dynamics on the B&W simulator in Lynchburg, Virginia, was a sort of add-on to the validation process, serving as a proof-of-the pudding for the plant operations staff and looking particularly at dynamic aspects of the new procedure which could not be examined during the control room walkthrough. Because the simulator is a generic one, not perfectly matching the Arkansas Nuclear One - Unit 1 design, scenarios from the original validation set had to be selected that would not be affected significantly by design differences. This resulted in a total of 10 variations of five basic scenarios.

Three four-hour sessions were conducted for this effort. Simulator operators were not told what scenario to expect or when to expect it. All 10 variations were exercised using the new procedure. When necessary to fully evaluate the instructions when plant conditions were changing too rapidly, the simulator was placed in the " freeze" mode. A few procedural inadequacies, several improvements and a number of potential improvements were identified. These results were used in conjunction with the operator comments from the training session to prepare a revision #1 to the procedure which was implemented prior to the completion of the refueling outage. This revision could best be characterized as a refinement since, again, the test of the procedure confirmgd its overall quality and effectiveness.

Itbecameapparentdurifigtheabovedescribedimplementationprocessthat the quality and effectiveness that had been achieved in the new procedure was still subject to the same adulteration by subsequent changes that was largely the reason for some of the problems with the old procedures.

Accordingly, the ,need for a way to keep every new regulatory issue from getting tacked on to the emergency procedure and to keep design changes from getting incorporated into the emergency procedure in a manner inferior to the procedure itself was identified. As a result, changes in the administrative control of the new procedure were made. The new controls make use of the bases document called for in the writing guidance. They also call for use of the writing guidance in making revisions. In addition, an appropriate level of verification and/or validation (appropriate level may be none) must be identified for every change to the emergency procedure.

6A-18

,, s

-7

, . . . . . - , . _ _-. . .-~ .. ,

.i

" The identified-level'of' verification and/or validation must be accomplishedL prior to implementationLof the change. With.the controls, it.is expected.

that the gradual degradation of procedures experienced'in the;past as a resulti fo inappropriate and' comparatively carelessly made changes will tur

-avoided _on-the painstakingly l achieved product. attained in'the manner.

described in this paper.

FUTURE c 'It.is hoped thatiimprovementLin.the' emergency operating procedures can-continue after this initial-effort. As the "better. approach" matures and

~

the. operations! staff has more^ exposure to it, ideas'for improvement should~

be born. Such ideas are' expected.to continue to aid the nuclear plant operator in becoming a more effective manager of the systems and components

.in a nuclear powee plant.

'IN CONCLUSION-It~should be obvious to the reader by now that this effort has been and continues to be'a massive one. However, it is expected to be a wise investment. In addition to generating some . tools that can aid in acquiring a better understanding of the plant on a system and functional level, it raises the status of instructions ~ to the' operator from that of a stepchild of the safety analysis to that of'a. top = level ~ vital component of nuclear.

power'. ..This .is in recognition of the: fact that the operator and his 1

capability is the single-most important positive factor..in. the safe 'and economic. operation of a nuclear power: plant. Contrary'.to traditional

, . . efforts to keep-the operator from harmin'g things, this effort hasfand continues to build on the operator as the cornerstone of a . firm foundation

- on which the safe and economic operation of a nuclear power plant rests.

t ,

i l ACKNOWLEDGEMENT I

-The review.and comments provided by D. A. Napior and J. J. Kelly of Babcock and Wilcox are greatly appreciated. The work of J. McWilliams, B. Garrison' and L. Taylor of tiie ANO operations staff has been vital'in making the

• application of these concepts a practical reality.

• 4 f

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6A-19 e

w ww -=q g- r,

, w ,wg mw-.- y-tv-wy ww a -, e- -v- e,----ww,-y-w.-w.a.w-. wewrem2- --me+--we,-u-+.t*-Hw---m-*MTee *- >-m- - =vv 'e - ~ ' '

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• Note that the relevant effects of natural events (earthquakes, tornadoes, etc.) produce the same relevant symptoms, i.e.' that an earthquake that produces a small steam line break will produce the same symptoms as a small steam line break. Natural events are therefore inherently addressed.

• • Diagrams were not prepared for_LOCA's due to the extensive analyses for LOCA's which had just been completed. However, event tree paths that~ ended in LOCA were reviewed for conformance to the just revised small break guidelines.

• • • (NOTE: -It should be noted at this point that the traditional approach of maintaining NSS vendor guidelines from which to write the procedures has-been. abandoned by AP&L. Since-Part I was-already plant specific, all it needed was refining from the draft stage at which point the original draft would no longer serve any purpose. As a result, AP&L no longer has any emergency procedure guidelines unless Part II could be considered to be such.)

f l

/

i 6A-20

.1 . . _ _ _ __ . - - -

REFERENCES

1. ' United. States Nuclear Regulatory Commission, " Quality Assurance Program

- Requirements (Operation)", Regulatory Guide 1.33.

2. Kelly,.J. J. and Williams, D.-H.; " Abnormal Transient Operating Procedures'.for Nuclear Power Plants"; Proceedings of the American Power Conference,'.Vol. 43, Chicago, IL, 1981. -

3. . Review of Effectiveness of Emergency Procedures for Operator Use, Lund ConsultTng, February 1981 -

4. Corcoran, W. R.; Finnicum, D' J.;.Hubbard, III, F. R.; Musick,:C. R.;

Walzer, P. F.; "The Operator's Role and Safety Functions", presented at the Workshop on~ Licensing and Tech'nical-Iss'ues - Post TMI, Atomic

, _ Industrial Forum; March 1980.

5. Corcoran,~ W. L R. ; Porter, N.' J. ; Church, 'J. F. ; Cross,' M. T. ; '"The Critical' Safety Functions and Plant Operation", presented at the International Conference on Current Nuclear Power Plant Safety Issues, International Atomic Energy Agency, October 1980.

6. Womack, E. A. ; Kelly, J. J. ; Elliot, N. S.'; " Engineering Basis for Operator Control of Nuclear Power Stations- in Abnormal Operations -

Closing the Loop"; Proceedings of the American Power Conference, Vol. 42, Chicago,.-IL, 1980.

7. Fortney,. R. A. ; .Snedeker, J.' T. ; Howard, J. E. ; Larson,- W. W. ; " Safety Function and Protection. Sequence Analysis"; presented at the American Nuclear Society Winter Meeting; November 1973.

8. Napior, D. A.; Kelly, J. J.; Gill, R. L.; "A Symptom-Oriented Approach-to Post-trip Transient Control"; presented at the American Nuclear Society Annual Meeting; June 1981. ,

9. Analysis and Evaluation of Crystal River - Unit 3 Incident; NSAC-3; Nuclear Safety Analysis Center; March 1980.

10. Personal _ communication with Florida Power Corporation staff.

11. " Interim Reliability Evaluation Program: Arkansas Nuclear One - Unit One -Power Plant" (draf t), SAND 82-0978; Sandia National Laboratories, April 1982.

12.~ Pine, S.; Comments presented during " Overview of EPRI's NP501-4 Enhancement Study and Summary of Findings"; EPRI Summer Workshop on Enhancement Approaches for Nuclear Power Plants, August 1981.

13. Personal communication with B. A. Terwilliger.

14. " Human Factors Criteria for Procedures"; Kinton, Incorporated; July 1980.

6A-21

O-4 4-ANTICORE MELT ANTl RADIOACTIVITY RELEASE

• REACTIVITY CONTROL CONTAINMENT INTEGRITY '* INDIRECT

• RCS INVENTORY CONTROL RADIOACTIVE e ISOLATION RE LE ASE CONTROL

• RCS PRESSURE CONTROL FUEL POOL COOLING e PRESSUR E/TEMPERATUR E e CORE HEAT REMOVAL WASTE PROCESSING CONTROL SPR AY CHEMICAL e RCS HEAT REMOVAL

• I LE GAS i TROL rs ~

r o MAINTENANCE OF VITAL AUXILIARIES ULTIMATE HEAT SINK ELECTRIC POWER COMPONENT COOLING WATER INSTRUMENT AIR HABITABILITY FIG. 1: CLASSES OF SAFETY FUNCTIONS 6A-22

--e-7 , ,w-- -, -- --, n - --- n , . - , - - - , .- ,- e w -- - - - , - - - - - - - -

I Utsidy enout Gata f T*antent Anaarset Defines time to key eventt.

satete sequence Deeram cent. ems cereme er frenos.

Organaes piant specdc proves soecdic semotoms

• Sata ento safety funcinong 5e*C'ed o'en'"ee brancf'et Event free and eOentetes systemattCally determene wareus Diant s*5te*eDer renconse emites e CM can eWve Dewang a durer's event poggiageq in.fiatmg event II / ,

/ /

" o,.,t cu ne, e,. , cu. r,e. ^"n,

i s.m.,a'" + ---- c. ec,e. .T " oor.se 4,c *-

,'t, :a'an.

2 i-ete acier Caute Wheels tsad 51 IO Drewsce er,0ul enWmaleOn D ver'mnent Corrective ACitOn1

/ 3p 4 fo'eCaut@S 880euO SCleons

, ans e,,1.a,.s _r.e, l gos,ent m nVC5

'Or IMG 00erating guide *mei y* ,g gn

{nderstand.

)~/ '

1,a.r r.g s~ato, A, . . t,,_

._4,. _ . _at ._.

Test guecefenes to alSure accuracy of retultant DianI )

response Fmal transaent operatma guelsnet.

Utdefy we.tes procedures 4

1r Operator traming c FIG. 2: ABNORM AL TR ANSIENT OPER ATING GUIDELINE PROGR AM 6A-23 wy y - , - -3

I j.

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FIG. 3: SIMPLIFIED LOSS OF FEEDWATER EVENT TREE 6A-24

. . . _ - -g n,- - *:ano- "*

2  ;

Post Trip d 2400 N g Window  %

3 A

9

')

e---

L...sw a *,

$3 2000 '

Sutcooled Region 4 f_

5 1600 -

3 E _ [ Sucerneat

'2 Steam Pressure di f ,/ Region 3 1200 Limit a ',-'

d

---- L.. ---.y 3; 800 -

~/g Saturation 6 -

y L -

3 . - C Subcocied Marpn 5

a Line

@ 450 500 550 600 650 Reactor coolant and steam outlet temperature. F p End Point - Post Trip with Forced Circulation (T%, and T.yo)

U and for Natural Circulation (T ec y Normat Operating Point - Power Operation (T%)

' ,1 End Point Post Trip with Natural Circulation (Tno ,)

FIG. 4: B ASIC PRESSURE-TEMPER ATURE (P-T) DISPL AY I

6A-25

em P

G #'

}2400

[/

= i 3 Path ot : r.-. j i'>

2 2000 Tnot 4 V-

c. /

~

/

E 51600 -

3 ll 31200 Steam Pressure i // /

7 j _ , \ / ./

p--

) 800 .

Steam Pressure /

} Excursion /

'l /

g 400 -

E

" 400 450 500 550 600 550 Reacter coolant and steam outlet temperature, F FIG. 5: TYPIC AL POSTTRIP RESPONSE 6A-26

P /

f 2400 r

///

6

$ 2000 -

3 C.'.'.'aG dl F Path of f '

• : 9 IW s/

E

$ 1000 -

Y ,'/

4 '8 f

E O 3 8 v 1200 -

% /

g 8 . 800 .

- -- --- - /- - ,lj E / Saturation cI 400 -

400 4'00 '00 550 600 650 Reactor cnolant ard steam outlet temperature. F FIG. 6 A: Inadequate subcoofing margin:

Tny is not pregressing toward its target value; in fact. it has rapidly dropped through the subccoled margin I ne. This condition is diagnosed as loss of adequate primary inventory subcool.ng, or simply "inadeauate subcoaling margin," and the procedure is written with dir ections to take care of inadequate subcooling margin.

l l

l l

6A-27

t~

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? 4 'll 3

t g ,/.i..yseu i(. ji t 2000 - q,* , ,

& rath of /

$ Ihe l[

$ 1600 0

3 ~/

?, 0 / /

b* " " ' '

7,1200 Omit k / /

e t, ______'t_____,/ / -

u 800 A w' ,-

$ A CA)

T 400 450 too 550 r>00 650 Reactor cociant and ste em outlet temperature, F FIG. 6B: Loss et primary to secenrfary heat transfer:

be is increas:ng as SG Ts.t is decreasing A ai between the two is growing larger. The secondary a no longer removing heat and has lost couphrg with the primary. T his condition is diacnosed and ticatec as loss of (inadequate) primary to secondary heat transfer, 6A-28

/

y 2400- /

a a e e

3 4 r-J

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2 2000 J' ' /

E Pat Nie 5 cf[/

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~$ 1600 -

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.M c (g Steam hessure d

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Lmyt c, - --

s --- - y 8

u 800 -

/

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A /

d 400-4C0 450 %0 %0 fo9 650 Reatter coolant and steam o et'et temoc<alo e. F FIG. 6 C: Excessive primary to secondary heat transfer-SG Tui has decicased belou its estabbshed lim.t Ts., and Tr.,,i have reached equal values but both have gone out of the posttrip window fo now'ng SG T u, This cond: lion is diar, nosed and treated as excessive primary to secondary heat transfer.

i l

6A-29

V 'flev .e Ca' = yewedial

• esen e temn l'*,* *** "d 3s !s a t.*J

, g raq pg,q 4 psig -- -- - - ---. -- -- - .. __

c tuat e f 4tuateJ Ve r t f y_ t he f ol l ne. t og t m

l

' " I" "* 'S^5 * == I550 '5'c area" 5

E m 7erify hP!/tP! terify sp!, tp! and + "I '

' # I4 naveU actuated 2,'I3.I aaJ d ' I ' U""* ' I*

On Ganels C 16 88 tsolatica and by C-lh. A C-26 & cooltng og panels -

noting that the colors of cow-C-16. C-3 8. 4 C- 26 ponents' fadicatine. la ps en

• the TS panels C-le , t'-le. .-

l - g C-26 certespoe4 oe. - sor of the switch narwplate.

, lee eta *wp taen (los . ,ancup tar 6 be b) Close makeup tank ot.tiet valse 3 y'd

[#7 Gloc k valve (Rv Sta(6 val.e (MU-13) and ERV blocir valve (CV-1x0) g g. } tym) (CV-1000).

4 c) If subcooling margan as lost, trip all RCFs. While proper-I f 50*! 's terify Penetratia, ly throttling feedsater, raise lost, fesp All Room Isolation: OTSC levels to 96-9$1.

RCrs. Coper Lamps Cut Paise 07% tevel- FIL7 Induated 4 PSIC A! ARM to 91-M reegettet Pressere a) Verify HFI, LFI and reactor bui1 Jing 1setation anJ cooling I channels 1. 2. 3. 4. 5. and 6 Reestabihn have actuated by noting that g gtp 5,4 r the colors of components

• y injection & indicating lac.ps on the 3 e ICW panels F-16. C-18 and C-2A W " '

c e t **+ rm et te st a roler of O l the switch m awplate.

"O 10 psig 4 )

4 t a4 t ef b) Close makeup tank outlet valve (MU-13) anJ f.RV block valve a

qg (CV-1000).

verify Prcper () v er f f y proper penet rat ion ro..e tear.tcr Buildin Abolatico by not ing all room Trav Fla, isolat ion dae:Per lanps out, flow inJacatcJ. anJ negative penetration room presearc inJicateJ.

', d[ d) Reestabit=h RCP seal injectionand it:-

30 PSIC Al>FM

, a) Verif y proper RB spray f low.

I y b) Verify NaOH valves are open.

- - en -

Section li FIGURE 7 First Draft Format

Figure 8 - CURRENT FORMAT PLANT MANUAL SECTION:

EMERGENCY OPERATING EMERGENCY OPERATING PROCEDURE 1202.01 6 of 110 0 5/27/82 REACTOR TRIP FOLLOW-UP ACTIONS (CONT'D) l

2) Verify proper 2) Proper Response of the Secondary System Secondary System response.

l NOTE l l If SLBIC has actuated or if either steam generator pressure is < 600 l l PSIG go to the SLBIC tab.

l l CAUTION l

l If an overfilling condition exists on either steam generator (rapidly l l increasing steam generator level) trip the main feed pumps and start l l the Emergency Feed System.

l l A) Turbine bypass or Atmospheric Dump valves l controlling header pressure at setpoint l + 110 PSIG.

I l If MSIV's are closed, open the Atmospheric l Dump Isolation Valves and select "ATHOS" I with the Dump valve selector switch.

l l B) ICS in track, runback in progress with l feedwater responding. t l

l Any ICS station in HAND must be adjusted to I the required output or returned to AUTO if l operable.

I -

l C) Only one Main Feed pump on at minimum speed.

l l If both main feed pumps have tripped, verify

,) the emergency feedwater system on.

i

.'l

'l D) Feedwater Crossover Valve open.

I i

l If the crossover valve cannot be opened, use l EFW for the affected steam generator.

I l E) Main and lo-load blocks closed.

I l If not, place the control switch in OVERRIDE l and close the valve. if the valve is in-l operable, close the affected loop main feed l isolation valve, CV-2630 or CV-2680, and use l the EFW System.

l l

l 6A-31

FIGURE 9 ABNORMAL TRANSIENT OPERATING PROCEDURES VERIFICATION CHECKLIST I. Writing Guidance Yes No Comments Exits to other procedures identifiable Combined format (Columnar Layered)

- Left Hand Column Minimum of component numbers Minimum of set points No lists No explanations (other than notes)

Cautions

- Right Hand Column Corresponds to left hand column Lack of Reliance on SPDS Consistency

- Emphasis of Tabbed Section Titles

- Minimum "Go To's"

- Component Designations Pump and tank names i Electrical numbers Valves

- Nomenclature and Abbreviations Match Writing Guidance Organization

- Initiating Condition,s

- Immediate Actions '

- Follow-up Actions

, Tabbed Sections Based on Observables 6A-32

FIGURE 9 (CONT'D)

II. Technical Content Yes No Comments

-Scope Instructions from the following Event Procedures are covered:

Blackout Reactor Turbine Trip Degraded Power LOCA RCP Trip (loss of all 4 portion only)

Emergency Shutdown OTSG Tube Rupture (for leaks in excess of makeup capacity)

Loss of Steam Generator Feed (to both steam gerierators)

Component Identifiers are Correct III. General Comments t

l I

l .'e i

e 6A-33 o

W^

FIGURE 10 ANO UNIT 1 SCENARIOS FOR VALIDATING THE EMERGENCY PROCEDURE

1. _ Automatic reactor trip with no abnormalities.

2. Automatic reactor trip with more than one control rod failing to insert.

a) Control rods stuck b) CRD breakers fail to trip

3. Reactor-trip with a loss of offsite power.

a)' Power available but_did not transfer

-b) Offsite power not available c) .Only one diesel operable

4. Blackout (loss of all AC power) ,

-a) Offsite power available but did not transfer b) Loss of DC inhibits diesel start c) Loss of all AC power /no AC power restored d) Offsite power available but degraded

1) < 75%

2)- > 75% but < 90% -

I

! e)z Offsite power restored-after 30 minutes t 5, Loss of NNI Power a) All NNI power lost -

b) Loss of NNI X AC. ,

c) Loss of NNI X DC d) Loss of NNI Y power

6. Reactor Trip with Ov,ercooling a) Failedopenm5infeedblockvalve(startingwithanoverfill condition)

! 1) Sufficient overcooling to cause a loss of subcooling margin b) Stuck open main steam safety

, c) Failed open throttle valve with leaking governor valves

7. Reactor Trip With a Loss.of Subcooling Margin

'a) , Spray valve stuck open b) ERV stuck open with a failure to trip RC pumps when the subcooling margin is lost 6A-34

+- r

FIGURE 10 (CONT'D)

ANO UNIT 1 SCENARIOS FOR VALIDATING THE EMERGENCY PROCEDURE c) RCS leak within HPI capacity

1) Unable to restore RC pump motor cooling

2) Failure in HPI system

3) Inadequate core cooling d) Large RCS leak

8. Reactor Trip with Overheating a) Loss of all feedwater (feedwater not restored) b) Loss of all feedwater (feedwater is restored)

9. OTSG Tube Rupture a) Large rupture causing a reactor trip b) Small rupture within HPI capacity

10. Steam Line Break a) Downstream of MSIV b) Upstream of MSIV outside contair. ment c) Inside containment t

S i

f 6A-35

!~

i FIGURE 11 EMERGENCY PROCEDURE VALIDATION CHECKLIST Event 1).

Description:

-Automatic reactor trip with no abnormalities.

Yes No Comments

1. Did the procedure lead the operator through l l l l l l the event-to a safe stable condition?

C0'MMENTS Yes No Comments

2. Did the Operators understand each step l l [ el -l l.

l of the procedure involved in this event?

COMMENTS Yes No Comments

3. Are any significant actions required to l l l l l l

.be'done that"were not addressed in the procedure?

COMMENTS 6A-36

FIGURE 11 (CONT'D)

EMERGENCY PROCEDURE VALIDATION CHECKLIST Yes No Comments

4. Are notes and cautions adequate? ( l l l l l COMMENTS Yes No Comments

5. Are there any significant operational l l l l l l difficultias? (Example: controlling a component at one location while observing indication at another location)

COMMENTS i

Yes No Comments

6. Are there any steps that could not be l l l l l l accomplished due to procedure error? (Example: use pressurizer spray when RC pumps are not running)

COMMENTS ,'

6A-37

FIGURE 11 (CONT'D)

EMERGENCY PROCEDURE VALIDATION CHECKLIST Yes No Comments

7. Is the equipment accessable and capable l l l l l l of being operated in the manner described in the procedure?

COMMENTS

8. Overall comments for this scenario:

f

/

a Evaluator Date 6A-38

~

APPENDIX 6C EMERGENCY OPERATING PROCEDURES WRITING GUIDANCE PURPOSE Considerable effort and thought has gone into the writing of the ANO emergency operating procedures. While this has not resulted in perfectly written procedures it has resulted in certain favorable features that in many cases may be enjoyed without being recognized. In order to maintain continuity in making future revisions and avoid the inadvertent destruction of these favorable features, this guidance attempts to provide the information necessary for the reviser to recognize these features and utilize them in his revision efforts. This guidance does not attempt to address technical bases for procedure content but restricts itself to the features that have been incorporated generally in the writing of the emergency operating procedures. This guidance also is not intended to place restrictions on departures from such features or improvements that can be made to such features but does intend to assure that departures from the original features are made consciously. There is also no intention that this guidance address all areas inherent <in a quality document that accomplishes an objective of efficient communication. For example, there is no guidance that instructs the writer to spell words correctly or to use words whose meaning will be clear to the intended reader.

1. ROLE OF EMERGENCY OPERATING PROCEDURES WITHIN THE AND PROCEDURE SYSTEM The scope of emergency operating procedures is restricted to actions to be taken following any automatic reactor trip or following the development of any condition that requires an immediate shuidown.

Other off-normal situations that do not meet these criteria are to be covered in abnormal operating procedures and actions to be taken under normal conditions are to be covered in the operating procedures.

Points at which a procedure other than an emergency operating procedure should be followed should be made identifiable, e.g., maintaining hot shutdown is covered by an operating procedure not an emergency operating procedure.

2. FORMAT AND LEVEL OF DETAIL 0F EMERGENCY OPERATING PROCEDURES TheANOemergency$peratingproceduresemployatwocolumnarformat.

The left hand column states briefly the objective to be accomplished.

This credits a trained operator with knowledge of the "how to" and provides easily and rapidly identifiable general direction in managing a plant transient. This column should contain a limited amount of component nuinbers and set points, lists and no explanations. All cautions should appear in this column and may appear in the right hand column as well. The objective stated in the left hand column should relate to all actions called for in the right hand column.

The right hand column expands on the objective stated in the left hand column. This column may contain component numbers, setpoints, lists, and explanations. The right hand column can state how to accomplish 6C-1

b the corresponding objective stated in the left hand column. For example, if the left hand column says to verify proper operation of a system, the right hand column may list the parameters that indicate such proper operation, or if the left hand column says to isolate a system, the right hand column may list the valves that must be closed to accomplish that isolation. This provides possible needed and readily accessible information for the inexperienced operator or the operator who has temporarily forgotten a detail without cluttering up the left hand column with information not needed by most operators.

3. PHILOSOPHY AND APPROACH The ANO emergency operating guidelines are built on the philosophy that, to the extent practical, an operator should not have to identify what has occurred, e.g., LOC /, MSLB, to take proper actions in attempting to maintain core cooling and minimize offsite releases.

Certain parameters indicate the extent to which these objectives are being maintained, and controlling these within desirable values by any means regardless of the cause of a problem will accomplish these objectives. This philosophy does not discourage an operator from diagnosing the cause of a transient for that must eventually be done and the information available in the control room to an intelligent

-trained operator will normally lead automatically to a diagnosis.

However, the approach followed in the ANO emergency procedures intentionally does not require such diagnosis to the extent practical and consequently should accommodate misdiagnoses as well. This approach was developed as part of the Abnormal Transient Operating Guidelines work done by the B&W Owners Group in 1980 and additional information is available in the documents produced by that program.

The philosophy and approach described here should be kept in mind in making revisions to the ANO emergency operating guidelines.:

4. CONTROL ROOM INTERFACE Certain informational aids have been provided in the control room that are consistent with the philosophy and approach of the ANO emergency -

operating procedures. Notable among these aids is the CRT displayed Pressure-Temperature diagram. The interface between these aids and the emergency operating procedures should be intentionally optimized.

However, the CRT_ displayed aids are not safety grade and care should be taken in writing thi emergency operating procedures to not require the availability of non-safety grade aids.

In addition, care should be taken in writing the Emergency Operating Procedures to avoid asking the operator to use information whose availability is inconsistent with the timing and location of the actions to be based on that information. In the rare case that a situation is identified in which vital information is not adequately available, steps should be taken to make it adequately available and it should actually become adequately available prior to incorporating its use in the Emergency Operating Procedures.

6C-2

5. CONSISTENCY Certain conventions were used in writing the emergency operating procedures. These are identifiable by examining the procedures and the reviser is urged to be acquainted enough with the Emergency Operating Procedures to enable him to maintain consistency in the revision.

However, some of these conventions are listed here for convenience.

A. Check-Off Provisions - No check-off provisions are included. This avoids the raising of questions about whether a step was performed because it was not checked off and results in a cleaner procedure.

Since adequate space is available in the margin, etc., to make marks to keep ones place, check off provisions are unnecessary.

B. Instructions to go to a tabbed section of the procedure are conspicuous, consistent and unique.

C. Use of "go to" instructions are minimized for simplicity.

D. Pump and tank names are normally utilized rather than their component number. Annunciator, panel and bus numbers are normally utilized instead of their name. Valve names and numbers are normally both used when the valve has a generally accepted name.

Otherwise, only the valve number is utilized.

E. The nomenclature and abbreviations generally accepted at AN0 and used in the Emergency Operating Procedures are listed in attachments to this guide, one attachment for each unit. The attachments are not intended to be comprehensive; therefore, other nomenelature and abbreviations not listed will be necessary in the Emergency Operating Procedures. i F. Boxed Emphasis-A special form of emphasis is used for steps that are to be taken at the same time as other steps which are not directly related when it is important that such steps be taken at that time. For example, if a required manual operation of a valve -

should be accomplished while an individual is in the vicinity performing another task, it would fall in this category. The special emphasis is a step enclosed in a box and crossing the entire page, i.e. both columns.

6. ORGANIZATION Consistent with the philosophy and approach, the Emergency Operating Procedures are organized as a single procedure with initiating conditions, immediate actions and followup actions. Tabbed sections are provided'for use in the event that an abnormal condition is identified while taking the immediate or follow-up actions. In general, these tabbed sections are organized based on observable abnormal conditions instead of events. The followup actions section directs the user to the tabbed section. (A unique event such as a steam generator tube rupture may be covered as a tabbed section and be directed to in the immediate actions. Such events are rare if not 6C-3

restricted to the example given.) Discussion sections are provided in the tabbed sections as an aid if needed and for training purposes.

Revisions should not depart from this organization inadvertently.

7. BASES A separate bases document consisting primarily of references to technical documents has been maintained identifying the source of the various instructions and numbers in the Emergency Operating Procedures.

This document does not provide the source of component numbers or basic design data but does provide the bases or reference thereto of limits, parameter values, margins and specific instructions that have more behind them than meets the eye. This enables the reviser to avoid unwittingly negating valid instructions because of a lack of understanding of them. The reviser should make conscientious use of the bases document and also incorporate the bases for his revision.

t

?*

e h

6C-4

ATTACHMENT 1 ANO-1 GENERALLY ACCEPTED NOMENCLATURE AND ABBREVIATIONS ATMOS HPI NSS Aux. FW HP Lift Pump OTSG BAAT N S- P/T BWST IS PZR CFT R.B.

Control Rod f0A Reactor Bldg Core Flood Tank LPI .

RCP CRD Flain Feed Pump RC Pump CRDM Flakeup RCS CRT lakeup Pump RPS CWRT eup Tank RTD Dasey Panel gj AA Decay Heat Pump MFWP SLBIC T '

SPDS DH Pump g.; y S/U DI R y EFW 7,ffg ave ERV T t1DTT c ESAS yng 3 H

U/V t

F I

r i

f 6C-5

backfeed on bus- Refers,to energizing.an elec-trical bus from the emergency diesel. Power is transmitted in a direction opposite to its-normal direction.

Blackout- Loss of all AC power including ,

Emergency Diesels.

l Brittle Fracture Limit That limit imposed on RCS pressure due to the temperature

[.

g of the HPI water.on the reactor

[ vessel walls.

i

" Bump" an RC pump' Start an.RC pump, run forL10 seconds, then stop. i i

Cold Shutdown . Reactor subcritical.by at least

! 1%^K/K and T ave is at or greater t

than 525 F.

?

" dead headed" Starting a pump with its discharge valve closed.

Degraded Power Loss of offsite power with the i

Emergency Diesels operable.

6C-6

ES Standby (M/U pump) . Refers to the makeup pump whose suction is NOT aligned to the makeup tank and whose discharge is only aligned to two HPI nozzles.

" float" the makeup tank on the BWST. Valve alignment whereby the M/V tank and the BWST are connected through the M/U pump suction piping.

The M/V tank level should decrease until the-M/V tank head (including i

the H verpressure) equals the' 2

BWST head.

Hot Shutdown Reactor subcritical by at least 1%.

^K/K and T ave is at or. greater than 525 F.

HPI/LPI " piggy back" System alignment whereby the LPI pump discharges into the suction of

., the HPI pump to provide a flowpath from the R.B. sump to the RCS when system pressure is >LPI pump head.

N 16 Monitor Refers to a radiation detector on the main steam line, calibrated to 6C-7

detect the gamma radiation given off by decaying nitrogen produced by activating oxygen.

Operating M/U pump Refers to the M/U pump whose suction is aligned to the M/U tank and discharge goes to normal-M/U.and seal injection.-

Re-flux boiling Method of Primary to Secondary heat transfer where boiling occurs' 4

in the core producing steam that is condensed in the steam generator.

The condensed steam flows back to the core to be boiled off again.

~

l Subcooling Margin or T sat Margin The temperature difference between actual system temperature and the saturation temperature for the

,' system pressure.

tailpipe Refers to the piping on the discharge of the pressurizer relief and'ERV safety valves.

4-6C-8

Tube Rupture Refers to a steam generator tube rupture allowing a primary to secondary leak.

J t I a

a e

l I

- f V

6C-9

ATTACHMENT 2 ANO-2 .

GENERALLY ACCEPTED NOMENCLATURE AND ABBREVIATIONS ATMOS Main Feed Pump SAA BAMT MFW Safety Injection CEA MFWP Tank

-CEDM- MOV SDC Pump Charging MSIV.- Shutdown Cooling Charging Pump MSR Pump Containment Bldg M/U SIT CPC NOTT SPDS CRT NSS S/U-

!- ^T PPS yW DI P/T ave EFW 'T 1- PZR c T

1 ESFAS RCP H T

HPSI RC Pump sat H. S. -RCS U/V LOCA RID VCT LPSI RWT . Volume Control Tank j

i 1-l t

[-

6C-10

APPENDIX 6D DESCRIPTION OF THE PROGRAM FOR VALIDATION OF E0P'S The program for validation of E0P's actually consists of two parts, verification and validation.

The verification process is used to ensure the consistency of the E0P with the writing guidance and the accuracy of equipment designations in the E0P and to provide a basis for a 10CFR50.59 review of the E0P by comparing it against the existing procedures which the E0P is intended to replace. The checklist used to aid in accomplishing these things is attached.

The writing guidance is used to develop the criteria for Section I of the checklist. These criteria represent aspects of all sections of the writing guidance that lend themselves to translation into a checklist criteria. The verifier is also asked to have sufficient familiarity with the writing guidance and the E0P to make general observations.

To make sure that, at worst, the transition to the new E0P from the existing procedures does not involve a degradation of the procedure, a comparison of the new E0P with the existing procedures which the new E0P is intended to replace is made. This comparison looks at every instruction in the existing procedures to be replaced and determines that the new E0P either has that instruction or that the instruction has been modified or deleted intentionally with reason.

All equipment designations are independently verified to determine that instructions in the E0P call for use of the proper equipment. This includes valve numbers, breaker numbers, buss numbers, etc. i After completion of the review portion of the verification process, all comments that were generated are addressed either by E0P modification or by justification of the E0P as written. Some comments generated by the verification review may already include the justification such as an -

identification of a step in the existing procedure that was left out of the new E0P with an explanation of why. This resolution of the verification comments results in a revision of the draft E0P being prepared for implementation before moving on to the validation process.

The validation process l'ooks at the usability and effectiveness of the E0P on a more integrated basis. This is accomplished by selection of a set of scenarios and walking through the E0P in the control room as applied to each scenario. All conditions and actions in the walk through are simulated.

The scenarios are' selected in such a manner as to exercise every instruction in the procedure. In doing so, of course, many instructions are exercised multiple times. The attached list of 10 basic scenarios with a total of 31 3

variations is used.

To accomplish the walk through a set of scenario instructions for each scenario is given the evaluator. The evaluator directs the control room operators, who have the procedure, as to the conditions and circumstances as 60-1

t they come to them in following the procedure. The operators are not informed in advance of a situation. Upon discussing each step with the evaluators, the operators are told of any abnormal conditions as indicated in the instructions to the' evaluator. For example, in a stuck rod scenario, when the operator is told by the procedure to verify "all rods on bottom" and reports to the evaluator that they are, the evaluator corrects this observation by stating which rods are not on bottom and what position they are at. Both the evaluator and operator are given opportunity to. comment both during and after the process of walking through the scenario. Comments are made on any aspect but each scenario is specifically observed for the items included in the attached validation checklist.

After completion of the review portion of the validation process, all

. comments that were generated are addressed either by E0P modification or by justification of the E0P as written. In addition, comments may be addressed by control room design change or training. This resolution of the validation comments results in a revision of the draft E0P being prepared for implementation before moving on to Plant Safety Committee review.

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ABNORMAL TRANSIENT OPERATING PROCEDURES VERIFICATION CHECKLIST I. Writing Guidance Yes No Comments Exits to other procedures identifiable Combined format (Columnar Layered)

- Left Hand Column Minimum of component numbers Minimum of set points No lists No explanations (other than notes)

Cautions

- Right Hand Column Corresponds to left haiid column Lack of Reliance on SPDS Consistency

- Emphasis of Tabbed Section Titles

- Minimum "Go To's"

- Component Designations Pump and tank names Electrical numbers Valves

- Nomenclature and Abbreviations ,

Match Writing Guidance Organization

- Initiating Conditions l - Immediate Actions I

- Follow-up Actions ,'

- Tabbed Sections Based on Observables ,

60-3

II. Technical Content Yes No Comments Scope Instructions from the following Event Procedures are covered:

Blackout Reactor Turbine Trip Degraded Power LOCA RCP Trip (loss of all 4 portion only)

Emergency Shutdown OTSG Tube Rupture (for leaks in excess of makeup capacity)

Loss of Steam Generator Feed (to both steam generators) .

Component Identifiers are Correct III. General Comments I

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6 6D-4

ANO UNIT 1 SCENARIOS FOR VALIDATING THE EMERGENCY PROCEDURE

1. Automatic reactor trip with no abnormalities.

2. Automatic reactor trip with more than one control rod failing to insert.

a) Control rods stuck b) CRD breakers fail to trip

3. Reactor trip with a loss of offsite power.

a) Power available but did not transf'.r b) Offsite power not available c) Only one diesel operable

4. Blackout (loss of all AC power) a) Offsite power available but did not transfer b) Loss of DC inhibits diesel start c) Loss of all AC power /no AC power restored d) Offsite power available but degraded

1) < 75%

2) > 75% but < 90%

e) Offsite power restored after 30 minutes i

5. Loss of NNI Power a) All NNI. power lost b) Loss of NNI X AC c) Loss of NNI X DC d) Loss of NNI Y power

6. Reactor Trip with Overcooling

~

a) Failed open miin feed block valve (starting with an overfill condition) l

1) Sufficient overcooling to cause a loss of subcooling margin b) Stuck open main steam safety c) Failed open throttle valve with leaking governor valves

7. Reactor Trip With a Loss of Subcooling Margin a) Spray valve stuck open b) ERV stuck open with a failure to trip RC pumps when the subcooling margin is lost -

60-5

ANO UNIT 1 SCENARIOS.FOR VALIDATING THE EMERGENCY PROCEDURE c) RCS leak within HPI capacity 1)- Unable to restore RC pump motor cooling

2) Failure in HPI system

3) Inadequate core cooling d) Large RCS leak

8. Reactor. Trip with Overheating a) -Loss of-all feedwater (feedwater not restored) b)- Loss of all feedwater (feedwater is restored)

9. -0TSG Tube Rupture a) Large. rupture causing a reactor trip ,

b) Small rupture within HPI capacity

10. Steam Line Break a) Downstream of MSIV b) ' Upstream of MSIV - outside containment c) Inside containment i

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l EMERGENCY PROCEDURE VALIDATION CHECKLIST Event 1)

Description:

Automatic reactor trip with no abnormalities.

Yes No Comments

1. Did the procedure lead the operator through l l l l l l the event to a safe stable condition?

COMMENTS Yes No Comments

2. Did the Operators understand each step l l l l l l of the procedure involved in this event?

I COMMENTS Yes No Comments

3. Are any significant actions required to l l l l l l be done that were not addressed in the procedure?

COMMENTS 60-7

EMERGENCY PROCEDURE VALIDATION CHECKLIST Yes No Comments

4. Ace notes and cautions adequate? l l l l l l COMMENTS

. Yes No Comments

5. Are there any significant operational l l l l [ l difficulties? (Example: controlling a component at one location while observing indication at another location)

COMMENTS Yes No Comments

6. Are there any steps that could not be l l l l l [

accomplished due to procedure error? (Example: use pressurizer spray when RC pumps are not running)

COMMENTS a

f f

6D-8

EMERGENC:' PROCEDURE VALIDATION CHECKLIST Yes No Comments

7. Is the equipment accessable and capable l l l l l l of being operated in the manner described in the procedure?

COMMENTS

8. Overall comments for this scenario:

f I

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, Evaluator Date k

60-9

APPENDIX 6E ARKANSAS NUCLEAR ONE UNIT ONE EMERGENCY OPERATING PROCEDURE TRAINING PROGRAM j ___

i GENERAL The emergency operating procedure is being implemented during a refueling outage so the initial operator training can be completed prior to startup.

This eliminates the problem of having operators trained on a procedure not yet in place or having a procedure in place that the operators are not yet trained on.

TRAINING SCHEDULE

.The refueling outage schedule allcws five weeks for cperator training prior to startup. The procedure training is conducted during the normal requalification training cycle.

1 Operator training with the new procedure on the B&W simulator will be during the scheduled annual simulator training. .Some of the simulator training '

will be complete prior to startup.

After'the initial training phara, the new emergency procedure will be used in the ongoing operator requali'. ation program in place of existing emergency procedure training. All annual simulator training will be conducted using the new emergency procedure.

PROGRAM DESCRIPTION

• The initial operator training on the new emergency operating procedure involves' classroom training in the areas outlined below:

• Background and Philosophy TMI related - NUREG 0737 requirement Symptom oriented rather than event oriented B&W ATOG guideline distribution

• Procedures' Af fected Overall effect of implementation Procedures deleted Procedures revised Procedures changed from emergency to abnormal operating New emergency procedure revision control 6E-1 W > - , - - , - ,

e Format of the New Procedure Columnar forraat Discussion sections Notes, cautions and "go to" instructions

• Deviations from Old Procedures RC pump trip criteria Pressurized thermal shock New specific parameters requiring a manual trip Defined maximum cooldown rate for a tube rupture Instructions for loss of instrumentation Inadequate core cooling Additions due to design changes installed during 1R5 outage

• Procedure Entry Conditions

• Immediate Actions

• Follow-up Actions

• Use of the SPDS P/T Diagram

• Primary to Secondary lleat Transfer Concepts Natural circulation Reflux boiling Classroom instruction includes complete coverage of each step offthe emergency operating procedure with detailed discussion to enable the operator to understand the technical bases for each step and the structure of the procedure. Operational concepts are discussed based on the B&W ATOG Part II. Operators are requested to provide comments and suggestions as the training is being conducted. These comments are evaluated for future procedure revisions.

A significant amount of training is accomplished while performing the validation of the emergency procedure. This involves a procedure walkthrough in the control room by control room operators.

Training on minor procedure revisions will be conducted through a program of required readings (self-taught) or lectures in the requalification program.

Training on major revisions will be through classroom instruction and walk-throughs. If operational considerations do not allow control room walkthroughs, tra'ining will be accomplished by classroom instruction.

6E-2

7.0 EMERGENCY RESPONSE FACILITIES (ERF)

The concept for Arkansas Power and Light Company's Emergency Response Facilities was conceived in the aftermath of THI as information became available regarding the tremendous logistical problem experienced by Metropolitan Edison in responding to the March 28, 1979, accident. As detailed information pertaining to that accident became available, it became

. apparent AP&L needed to re-evaluate the Company's existing Emergency Plan and associated procedures and make use of.the TMI-2 experience in enhancing plant safety at ANO. To address these areas it was decided that a program should be established with two primary goals:

(1) Ensure that the probability of a TMI-2 type incident at AN0 remains extremely low, and that both AN0 units can operate without any danger to the public health and safety.

(2) In the unlikely event of a TMI-2 type incident at ANO, ensure that any necessary " contingency" plans, procedures and facilities are in place and that corporate personnel are thoroughly trained to cope with the situation.

To achieve these goals, a task force was mobilized to ensure that all concerns were reviewed in a consistent manner, all aspects of each concern were adequately covered, duplication of effort was minimized, solutions were not at cross purposes (i.e., the solution in one area did not jeopardize solution to other areas), requests for information from outside organizations were coordinated, and responses were prepared in a consistent manner.

One area specifically addressed by the Task Force was logistical support.

One of the results of work in this area was the recommendation for, and subsequent construction of, the ANO Emergency Control Center.

i The Task Force's recommendations concerning Emergency Response Facilities were made in the Fall of 1979. During this same time period, the NRC was actively formulating their recommendations pertaining to Emergency Response i Facilities.1 In an effort to reach mutual agreement with the NRC, so that l

construction planning could begin on AP&L's new facilities, a proposal for meeting the NUREG 0578 Technical Support Center (TSC) criteria was submitted to the NRC in Mr. William Cavanaugh's letter to Mr. Darrell G. Eisenhut l dated January 17, 1980 (0CAN018002). This letter was supplemented by a l meeting between AP&L management and NRC's Mr. Eisenhut et al. on February 11, 1980.

AP&L's proposal to the NRC presented a two center approach to meet the TSC recommendations of NUREG 0578. A Primary TSC would be located in the AN0 Administration Building, allowing quick activation and rapid access to informat on. This Primary TSC, however, would not be radiologically habitable. In the event the Primary TSC became uninhabitable, a Secondary TSC, designed to the same radiological habitability requirements as the

. control rooms, would be available within AP&L's Emergency Control Center, which is located approximately 0.65 miles from the plant. Both TSCs would 7-1

be similarly equipped. This concept was specifically approved for AP&L by Mr. Darrell G. Eisenhut's in his letter to Mr. William Cavanaugh III dated April 15,1980-(0CNA048071) and later generically approved for all licensees in Mr. Darrell G. Eisenhut's letter to All Power Reactor Licensees dated April 25, 1980 (0CNA058035).2 The April 25, 1980 Eisenhut letter to All Power Reactor Licensees also outlined guidance for a new facility referred to as an Emergency Operations Facility (EOF),3 which seems to have incorporated into it the previously described Emergency Operations Center (E0C).4 In the April 25 letter, the E0F was' described as being the location where the licensee would evaluate and coordinate activities related to an emergency having or potentially having environmental consequences. The EOF was to have the capability to display the same plant data and radiological information as would be required for transmittal to the NRC. The EOF was to have sufficient space to accommodate representatives from the NRC, Federal, State and local governmental agencies and the media. The overall management of utility resources including recovery operations were to be administered from this facility. The EOF was to be a substantial structure, providing significar,t shielding factors from direct radiation and have the capability to isolate ventilation systems with a filtration system (at least HEPA filters).

Arrangements were also to be made to activate an alternate EOF in the event the near site EOF became uninhabitable.

These new requirements for the EOF coincided with our in-house concept of our Emergency Control Center (ECC). Based on the April 15, 1980 approval of our backup TSC and the fact our ECC (recovery portion) was . designed to the same radiological habitability requirements as the control room, and would be located within one mile of the site (all of which seemed to be exactly what the NRC was requiring at the time), AP&L broke ground in April 1980 on our new Emergency Control Center complex in a good faith effort to meet the NRC's January 1, 1981, deadline.s NRC's guidance on location and habitability of the EOF remained consistent up until the issuance of Generic Letter No. 81-10, dated February 18, 1981 (0CNA028117) (issued 49 days after the original required completion date for the Emergency Response Facilities). In this lrtter, the operational date for the finalized emergency response facilities was changed from January 1, 1981 to October 1, 1982. Table III.A.1.2-2 of this letter, (same as supplement 1 to NUREG-0737 Table 1) provided two options to satisfy the EOF requirements. In our letter dated April 3, 1981 (0CAN048104), responding to this letter, we stated that our facility, on which construction began in April.of 1980, was of the Option 1 type. We proposed a backup facility located at the AP&L Russellville office approximately seven miles from the site. At the time of this April letter, construction on our ECC building was approximately 95% complete. We mentioned in our letter that the protection factor provided by the building was approximately five6. This was based on exterior walls constructed of five inches of precast concrete with limited sealed window space.

Construction of the Emergency Control Center facility was completed in the Spring of 1981. The following information provides a current status of AP&L Emergency Response Facilities.

4 7-2

~

7.1 TECHNICAL SUPPORT CENTER (TSC)

The AN0 TSC may be activated at any time during an emergency by the on call Duty Emergency Coordinator. The TSC is required to be activated per Emergency Plan Implementing Procedures (EPIPs) at the Site Emergency action level. To assure prompt staffing of the TSC, procedures require the activation of the TSC staff at the Site Emergency Action Level. The Duty Emergency Coordinator may activate the TSC staff earlier if deemed necessary.

The TSC provides a location outside the control room for plant management and technical support personnel to gather and coordinate support to the operations personnel during emergency conditions. The TSC functions as the primary information source to the Emergency Control Center (ECC) and NRC.

The TSC also coordinates the Operational Support Center. When activated, the TSC performs the functions of the ECC until the ECC is staffed.

The following Emergency Response Organization positions, staff the TSC during an emergency to provide technical, engineering, and management support to the operations personnel.

1. Recovery Manager

2. Operations Manager

3. Nuclear & Engineering Support Superintendent

4. Maintenance Manager

5. Technical Analysis Superintendent

6. Health Physics Superintendent

7. Nuclear Support Supervisor Additionally, the TSC will be staffed with TSC communications operators and a status board keeper.

The layout of the TSC is shown in Figure 1. The TSC is located on the third floor of the ANO administration building. The administration building is located within the plant protected area and adjacent to the turbine building, providing ready access to the control room and the Operational Support Center (OSC).

! The TSC proper is approximately 900 square feet. In addition to the TSC proper shown in Figure 1, additional office space adjacent to this room has been designated for the NRC's use. Also adjacent to the TSC and available t

' for the TSC staff's use is the ANC Administration Library. This library currently contains the following plant records for both units:

1. Technical Specifications & Licenses

2. FSARs

3. Plant Procedures

4. Technical Manuals

5. ANO Emergency Plan

6. AP&L Nuclear Contingency Plan & Procedures

7. Controlled Plant Drawing (P& ids, Electrical, Vendor Prints, Piping Isometrics, Civil, Architectural, Etc.)

7-3

In . addition to these hard copy documents, the Administration Library also has access to the plant's records management system through the use of a Tandem computer terminal and microfilm set.

The ANO administration building, in which the TSC is located, was constructed-generally in accordance with the Southern Standard Building Code. The Southern Standard Building Code is the State of Arkansas accepted building code and is similar to the Uniform Building Code. The ANO administration building's room air is environmentally controlled through a central heating and air conditioning system.

The TSC has several means of communication with the control room, ECC, OSC, NRC, and State and local operations centers. A summary of the communications available to each of these centers is provided below.

TSC to Control Room The primary means of communication between the TSC and the control room is through the ANO telephone system by using either the dedicated ring down line provided between the TSC and control room or by dialing the facility directly. The ANO telephone system is backed by emergency power to assure its operability during a loss of offsite power.

Communications between the TSC and control room can also be carried out by utilizing the local telephone company's facilities. Lines are i

available to the control room and the TSC independent of the ANO telephone syste'm.

In addition to telephones, the TSC can communicate with the control room through the ANO radio-system, either by using the intercom feature between the facilities or by using hand held portable two-way radios.

TSC to ECC The primary means of communication between the TSC and ECC is through '

the ANO telephone system and the ECC telephone system, which are

• connected by a fiber optic link. Both telephone systems, and the fiber optic link, are backed by emergency power to assure their operability during a loss of offsite power. As is the case between the TSC and control room, telephone communication between the TSC and ECC can be carried out by using either the dedicated ring down line provided between the TSC and ECC or by dialing the facility directly.

Communication between the TSC and ECC can also be established by utilizing commercial telephone facilities. Lines are available to the TSC and ECC independent of the two facilities' telephone systems.

In addition to telephone, the-TSC can communicate with the ECC through the ANO radio system, either by using the intercom feature between the facilities or by using hand held portable two-way radios.

7-4 vr-y

• y w .- * - -  %- m9 - ,y- . ,, ,9, .-q - - --'

TSC to OSC-The primary means of communication between the TSC and OSC is through the ANO telephone system by using the public address capability or dialing numbers directly.

The TSC also has the capability to communicate with emergency teams by utilizing the ANO radio system.

TSC to NRC J

The primary means of communications between the TSC and NRC is through the NRC's Emergency Notification System (ENS) and the NRC's Health Physics Network (HPN). The TSC also have the capability to communicate with the NRC via commercial telephone.

4 TSC - State and Local Operations Centers The primary means of communication between the TSC and the state and local operations centers is through the commercial telephone system.

The TSC also has the capability to communicate with these centers through the Office of Emergency Services (0ES) radio network or the Sheriff radio network.

Currently, plant parameters and meteorological variables are verbally transmitted to the TSC over telephone links between the TSC and control room. Critical plant parameters and special notes are recorded on a large status board in the TSC, ahich is maintained by a " status board keeper."

Meteorological variable and effluent release data are transmitted either via phone line from the control room or obtained from the computerized dose projection portion of the Gaseous Effluent Radiation Monitoring System (GERMS) terminal in the TSC and is maintained by the Emergency Response Organization position responsible for dose assessment. While these methods have in the past, during emergency exercises, provided sufficient information for the TSC staff to effectively carry out their duties, AP&L is-upgrading this capability by adding real time data displays in the TSC of those variables that are essential for performing the TSC function.

Critical plant parameters will be displayed in the TSC using the Safety Parameter Display System (SPDS). Details pertaining to the SPDS and its use for the data display function in the TSC are discussed in section 3.0 of

.th is document.

Real time meteorological variables (wind speed, wind direction, temperature, and atmospheric stability data) will be displayed in the TSC using the Gaseous Effluent Radiation Monitoring System. GERMS terminals are currently available in the control rooms, TSC and ECC; however, the computerized dose assessment portion of the GERM system is still in the test stage.

Ultimately, GERMS will have the capability to acquire real time effluent release data, combine that with real time meteorological data (acquired from the ANO meteorological tower) and produce a graphic offsite dose assessment plot.

7-5 p ~

+&-m a-. ..-w, - ,n ,,

7 v- - - - - - - - --

q.- -

- - - --_..- --y

AP&L is currently correcting software and hardware deficiencies associated with the GERMS dose assessment capability. We anticipate having the dose assessment portion of the GERM system operating (hardware and software modifications complete) by December 31, 1983. Once the system is operating, procedures for its use will be finalized and. training conducted. The GERMS will be declared operational after procedure development and training are complete. This is orojected to be accomplished six months after hardware and software modifications are completed (approximately June 30, 1984).

Currently, National Weather Service regional data is available through telephone contact with this agency. The telephone rumber for this service is maintained in ANO procedures.

The health and safety of Emergency kesponse Personnel located in the Primary TSC is the responsibility of the Recovery Manager. The radiation levels in the vicinity of the TSC are assessed using the following detection equipment:

Detector , Type of Radiation Monitored Location RM-14 Direct radiation - audible Stored in TSC and visual alarm Emergency Kit MS2/ SPA 3 Radiciodine Hallway outside or TSC - hallway on SAM 2/R022 same HVAC system as TSC NMC-16 Continuous air monitor - Hallway outside measures particulate and TSC - hallway on gases - audible and visual same HVAC system alarm as TSC To protect the TSC/OSC staff from excessive amounts of radiation exposure, the guidelines presented in Figure 2 have been established. These -

guidelines are contained in AND EPIP 1903.30, " Plant Evacuation."

When a TSC evacuation is warranted, the TSC staff will evacuate to the Secondary TSC per ANO EPIP 1903.30, " Plant Evacuation." The Secondary TSC is located in the ECC as shown in Figure 7-4. The Secondary TSC was designed to the same radiological habitability requirements as the control rooms, considering its location with respect to the plant. The location of the ECC is shown in Figure 7-3. The secondary TSC essentially will have the same communication and data display capability as the TSC (telephones, radios, SPDS) with the exception of the location of the GERMS terminal. At the ECC, the GERMS terminal is located in a separate room in close proximity to the Secondary TSC. The details of the ECC facility are covered in section 7.3 Emergency Operations Facility.

C 7-6

7. 2 OPERATIONAL SUPPORT CENTER (OSC)

The AN0 Operational Support Center (OSC) serves as a base from which support

' personnel can be accessed to aid the control room.and TSC staff in the recovery. The function of the OSC 'is to provide technical, administrative and logistical support. Their activities are directed by the TSC staff.

The AN0 Administration Building serves as the OSC. The normal work locations for individuals are used as the reporting area in this center with the following exceptions:

1. The Radwaste Coordinator shall report to his supervisor's office in the administration building.

2. The Site Engineering Supervisor shall report to the AN0 Plant Analysis Superintendent'.s office.

3. The Emergency Evacuation Team shall report to tne Main Guard Station and the Emergency Control Center.

4. The Emergency Fire Team shall report to the second floor "

conference room.

5. The Emergency Medical Team shall report to the second floor break room /first aid room area.

6. The Emergency Radiation and Recovery -Teams shall report to the Maintenance Coordinators Office Area (first floor administration building).

The primary means of communication between the OSC, TSC and ECC is by telephone and/or plant public address system. Communications with the emergency teams can also be accomplished utilizing the ANO radio system.

7.3 EMERGENCY OPERATIONS FACILITY (E0F)

The ANO Emergency Control Center (ECC), which serves as AP&L's Emergency Operations Facility, is divided into two distinct functional areas, emergency response and media. The emergency response portion of the building as shown in Figures 7-4 and 7-5, serves a number of different functions; first, it is the central point from which the overall management of AP&L emergency resources are coordinated; second, it is the primary location for coordination with offsite support groups such as the Arkansas Department of Health, Vendors, Contractors, etc. ; third, .it is the primary location for coordinating both technical and non-technical support activities of personnel brought in to' assist ANO personnel; fourth, it serves as the central point for coordinating AP&L's offsite environmental monitoring and dose assessment activities once the expanded Emergency Response Organization is activated; and fifth, it serves as a location for the secondary TSC and OSC should these facilities at the plant be evacuated.

During an emergency the media portion of the ECC will be utilized by AP&L and the State of Arkansas as a media center. Joint news conferences between the coordinating agencies involved in the recovery will be held in this

, facility. The media portion of the ECC is shown in Figures 7-6 and 7-7.

7-7 nw -

o

The ECC is. located approximately 0.65 miles Northeast of ANO in.the least predominant wind direction. The location of the ECC is'shown in Figure 7-3.

The Emergency Response portion of the ECC was designed to the same radiological habitability requirements as the ANO control rooms, considering its location with respect to ANO. The response portion has both HEPA and charcoal filtration available.

In comparing the AN0 ECC with Table 1 of Supplement 1 of NUREG-0737, AP&L complies with Option 1, considering the footnote which states, "If a utility has begun construction of a new building for an EOF that is located within 5 miles, that new facility is acceptable (with less than protection factor of 5 and ventilation. isolation and HEPA) provided that a backup EOF similar to'"B" in Option 1 is provided." The protection factor for AP&L's ECC is approximately 4.3. As was previously mentioned, construction on AP&L's ECC began in April of 1980, and therefore AP&L, per the footnote of Table 1, need not meet the protection. factor of 5 requirement.

A backup ECC was proposed to the NRC in AP&L's letter to Mr. Darrell G.

Eisenhut dated April 3, 1981 (0CAN038104). In this letter we proposed using the AP&L Russellville Office approximately 7 miles from the site, and in a different wind direction than the primary ECC. AP&L has received no response to date regarding this proposal. AP&L still maintains that the Russellville Local Office is the most logical location for a backup ECC and re propose its use to the Commission for this purpose.

AP&L Nuclear Contingency Plan Procedure 15 " Emergency Control Center Evacuation" (attached as Appendix A) provides a method to assure continuity of dose projection and decision making capability during the transition from the ECC to the Russellville Local Office. Figure 15-C-1 of the Emergency Control Center Evacuation procedure shows the layout of the alternate ECC.

Figure 15-C-2 shows its location with respect to ANO. Although the Russellville Offica is seven miles from ANO, it is conveniently located.

Major highways to the local office provide ready access back to AN0 and make the relocation to this facility timely. The Russellville Local Office is also in close proximity to the State and Technical Operations Control Center (TOCC), where the offsite response is coordinated (by road it is only 2.5 miles away). Being this close to the State's TOCC will provide ready access for face-to-face communications. Also, if communication links were lost, this close proximity would provide a ready means of physically transporting information between the two control centers.

Another-important benefit of designating the Russellville Local Office as the backup ECC is that this Office is part of the AP&L micro-wave telephone network. Being a part of this network provides an alternate communication path other than commercial telephone company to ANO, Little Rock and the Bell Telephone System. The Russellville Local Office is also equipped with

-an ANO Base station radio, providing emergency radio communication with ANO and offsite radiological monitoring teams.

The Russellville Office is a large facility and adequately sized to handle the initial emergency response staff. The facility has a considerable amount of parking space, allowing expansion if needed, through the use of trailers. -

7-8 4 7-

Currently we know of no other facility (AP&L offices or other) within 10 and' 20 miles of ANO comparable to the Russellville Local Office, to serve as a backup ECC. We therefore request exemption from locating the backup ECC 10 to 20 miles from ANO in favor-of using the Russellville Local Office.

The current layout of the ECC is shown in Figures 7-4, 7-5, 7-6, and 7-7.

The facility has approximately 72,000 square feet of useable floor space.

The facility was constructed generally in acccrdance with the Southern Standard Building Code. The Southern Standard Building Code is the State of Arkansas' accepted building Code and is similar to the Uniform Building Code. The ECC's air is environmentally controlled through a central heating and air-conditioning system. During an emergency, the HEPA and charcoal filtration system will be activated.for the response portion of the ECC.

When the ECC is manned during an emergency, health physics personnel are dispatched to the center from ANO, to monitor radiation levels and assure habitability.

The ECC has several means of voice communication with the TSC, control rooms, OSC, NRC, and State and local emergency operations centers. A summary of the communication available to each of these centers is provided below.

ECC to TSC The primary means of communication between the TSC and the ECC is through the ECC and AND telephone systems by using either the dedicated ring down line provided between the ECC and TSC or by dialing the facility directly. Both the ECC and ANO telephone systems and the fiber optic link between them are backed by emergency power to assure their operability during a loss of offsite power.

Communications between the ECC and the TSC can also be carried out by utilizing commercial telephone facilities. Lines are available to both of these facilities independent of the two facilities' telephone systems.

In addition to telephone the ECC can communicate with the TSC through the ANO radio system, either by using the intercom feature between the facilities or by using hand held portable two-way radios.

ECC to Control Room The same means exist to communicate with the control room as to the TSC.

ECC to OSC The primary means of communications between the ECC and the OSC is through the ECC and ANO telephone systems, by using the public address capability or dialing numbers directly. The ECC also has the capability to communicate with emergency teams by utilizing the ANO radio system.

7-9

ECC to NRC The primary means of communication between the ECC and NRC is through the.NRC's Emergency Notification System (ENS) and the NRC's Health Physics Network (HPN).

The ECC also has the capability to communicate with the NRC using commercial telephone.

ECC - State and Local Operations Centers The primary means of communication between the ECC and the State and local operations centers is through the co'mmercial telephone system.

The ECC also has the capability to communicate with these centers through the Office of' Emergency Services (OES) radio network or the Sheriff radio network.

Currently, plant parameters and meteorological variables are verbally transmitted to the ECC over telephone links between the ECC, control room and TSC. Critical plant parameters and special notes are recorded on a large status board in the ECC, which is maintained by a " status board keeper." Meteorological variables and effluent release data are tranmitted to the ECC either via phone line from the control room or via the GERMS terminal in the ECC and are maintained by the Emergency Response Organization position responsible for dose assessment. While these methods have in the past, during emergency exercises, provided sufficient information for the ECC staff to effectively carry out their duties, AP&L is upgrading this capability by adding real-time data displays in the ECC.

Critical plant parameters will be displayed in the ECC on the SPDS located in the Secondary TSC. Details pertaining to the SPDS and its use for the data display function in the ECC are discussed in section 3.0 Real-time meteorological variables (wind speed, wind direction, temperature, and atmospheric stability data) will ultimately be displayed in the ECC using the Gaseous Effluent Radiation Monitoring System (GERMS) computer system. GERMS terminals are currently available in the control rooms, TSC and ECC; however, the computerized dose assessment portion of the GERM system _is still in the testing stages. Ultimately, GERMS will have the capability to acquire real-time effluent release data, combine that with real-time meteorological data (acquired from the AN0 meteorological tower) and produce a graphic offsite dose assessment plot.

AP&L is currently correcting software and hardware deficiencies associated with the computerized dose projection portion of GERMS. We anticipate having that portion of the GERMS operating (hardware and software modifications complete) by December 31, 1983. Once the system is operating, procedures for its use will be finalized and training conducted. The GERM system will be declared operational after procedure development and training are complete. This is projected to be accomplished six months after the hardware and software modifications are completed (June 30, 1984).

7-10

l i

Currently, National Weather Service regional data is available through telephone contact with this agency. The telephone number for this service is maintained in ANO Emergency Plan. Implementing Procedures.

' Plant records are available to the ECC staff in-the ECC Technical Resource Center. This center currently contains the following plant records for both units.

1. Technical Specifications & License

2. FSARs

3. Plant Procedure

4. Technical Manuals

5. ~AN0 Emergency Plan

6. AP&L Nuclear Contingency Plan & Procedures

7. Selected Plant Drawings In addition to these hard copy. documents, the Technical Resource Center has access to the ANO records management system through a Tandem computer terminal and a complete set of micro film. Further evaluations of available plant records in this center are to be conducted by July 1, 1983.

When activated under emergency conditions security is provided to the ECC by the plant guard force'. Provisions to augment the ANO guard force can be made at the time of an incident.

7. 4 GENERAL The minimum staffing requirements for AN0 is shown in Figure 10 of the AND Emergency Plan. Figure 10 is reproduced as Figure 7-8 to this document.

Human factors have been considered in the design of the Emergency Response-Facilities. The Emergency Response Facilities themselves and the voice communications described in this document have been in place and available for use by AP&L for the last two annual emergency response exercises at ANO.

During both of these exercises, under simulated accident conditions, the facilities and the equipment in them performed adequately. During both exercises; however, minor modification, have been identified to further enhance our emergency response capability.

With the exceptions of the real-time data display systems in the TSC and ECC, and the acceptance of AP&L's proposed backup ECC, AP&L Emergency Response Facilities are complete. AP&L will continue to use these

' facilities; however, will not declare them operational until their data display systems are in place, operating, and personnel are trained on their use. The SPDS data display system for the' Emergency Response Facilities is scheduled for operations with existing parameters by June 1, 1984 and fully operational by November 15, 1985. The computerized dose assessment portion of GERMS is scheduled for operation by June 30, 1984.

7-11 n 4 --w-

NOTES

~

1. NRC provided guidance for Emergency Response Facilities in NUREG 0578; Mr. Darrell G. Eisenhut's letter to ALL OPERATING NUCLEAR POWER PLANTS dated September 13, 1979; and Mr. Harold R. Denton's letter to ALL OPERATING NUCLEAR POWER PLANTS dated October 30, 1979.

2. This concept was also presented in Draft NUREG 0696 " Functional Criteria for Emergency Response Facilities" published for interim use and comment in July 1980.

3.

The E0F was also described in Draf t NUREG 0696 " Functional Criteria for Emergency Response Facilities " published for interim use and comment in July 1980.

4. The E0C concept was presented in Mr. Darrell G. Eisenhut letter to All Operating Nuclear Power Plants dated September 13, 1979.

5. The January 1,1981 deadline was specified in NUREG 0578" THI-2 Lessons Learned Task Force Status Report and Short-Term Recommendations; Mr. Darrell G. Eisenhut letter to All Operating Nuclear Power Plants dated September 13, 1979; and Mr. Harold R. Denton letter to All Operating Nuclear Power Plants dated October 30, 1979.

6. The protection factor for the ECC was later determined to be approximately 4.3. Discussions pertaining to the protection factor of.

the ECC are contained in AP&L's letters to Mr. K. V. Seyfrit-dated September 18, 1981 (0CAN098106), and October 15, 1981 (0CAN108106).

i e

7-12

y.

J 1 1 GERMS *d*  !

HPti

- TECHt4ICAL Af1ALYSIS I

SUPT.

At10/CB RADIO DUTY EMERGEllCY C00RD./ flUCLEAR &

RECOVERY T1ANAGER SUPPORT Sl i TSC ,

'A' '6" OPERATOR E

N 7 7 t1AltlTEllAtl(

HP SUPT.

l 3 - TELEPHONE STATIOP l

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North FIGURE 7-I

)RT CENTER i/4"- r- o" TECHNICAL SUPPORT CENTER AS AND ANO ADMINISTRATION BLDG.)

LED ADJACEffT TO TSC

. FIGURE 7-2 TECHNICAL AND OPERATIONAL SUPPORT CENTER EVACUATION DECISION FLOW CHART I TSC/OSC Act:,vated I t -

1

~

l ACTIGN: Monttor Area l 6 Radiation and Airborne i  !

I.evels l. ACTION:

• l

11) Increase airborne sur-l 4 if veillance to once per l' l

hour, and~ , ,

Are area radiation levels a 2.5 mR/hrl l  !

but less than 100 mR/hr; and/or  ! I (2) Monitor area dose unevaluated airborne radtoactivity YES rates once per 15 l in excess of I x 10*8 pCi/ce? l l manutes, and- l l 1 6 '3) Evaluate projected in-l t tegrated personnel l

] doses,ay i I I No l (4) Establish stay-times. l

! I i (5) Evacuation not usuallyl 1 necessary. I if l ACTION:

l Are todane concentrattons j YES F ( F 5 1ntain occupancy 103 l > SE-10 pCi/ccf I l of MPC hours; I (2) If iodine concentra-AND/OR l tion > 4 MPC (3.6 x l 104 pcgfeej 1 (a) respiratory protec '

tion required, or l +

(b) precautionary ~ l evacuation requiredl l ACTION:

l Are area ractation levels ,' TIS ' b; (1) Determins within 30 1 > 100 mR/hr but < l R/hr? l l minutes if temporary l or long-ter:a condition .

I exists, and i

l (2) If temporary, evaluatel NO l projected integrated i i doses, og l 3 l l (3) If lona-term precau- l l tionary evacuation l required. .

U l Are radiation levels "

i N/hr? ' l ACTICN:

YES 11 7diEDIATE I EVACL;AI!ON 3 V

l REQUIRED l

l ACf!ON: .%o spectai action required. l l Continue HP area radiation and atr- l l borre level surveillance. I i

I 7-14

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HP3-TAS-Healtit Physics Suot.

Technical Anatysis Supt.

_FlGURE 7-4 Emergency control Center 255- . Nuclear Support Supv.

Second Ficor West End '

() - Denotes Location of Personnel for ANO Administration Sullding Evacuation.

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XT" l FIGURE 7-8 bilNIh!U51 STAFFING REQUIRE 3fENTS AVAll ABLE(7) AVAILABLE( )

lli 30 lil 60 GROUP POSll10il/llllE O!!- Slill l( I ) 111tl filli Senior flanagement Duty Emergency Coordinator - -

1 Operations ( ' ) Shift Supervisor 1 -

Senior Reactor Operator ( ) 1 - -

Reactor. Operator 2 - -

Auxiliary Operator 2 - -

Shif t Tecluiical Advisor (5) 1 - -

floti fication/ 1 1  ?

Communications (6) y llealth Physics llealth Physics Supervisor -

1 -

y llealth Physics Technicians 1 4 4 (Accident Assessment) llealth Physics Technicians 2

)

2 2 (Protective Actions) .

Radiochemistry Radiochemist 1 -

1 ilaintenance I & C Technician 1 Electrician -1(G) 7 y t1echanic 1(0} -

2 Engineering fluclear Engineer -

1 -

Electrical Engineer -

1 f-lechanical Engineer - -

1 Security Security Personnel All per Security Plan

, -- , ,- , c ,,. ,, . _ -_ _ . - __ _ - _ _.

. W  %)

FIGURE 7 BIINIFU51 STAFFING REQUIREhfENTS (cont.)

AVAILABLE I) AVAILABLE(7) - ,

GROUP' Ill 30 IN 60 POSITION / TITLE Oll-SillFT II) l-1111 11111 Firefighting Fire Brigade per local Support Technical Specifi-cations First Aid ---

2(0) Ir. cal Support lotal 10 11 15 (1) Effective September 20, 1982.

(2) Second SR0 to be added to each shif t as they become available af ter achieving a six shift rotation. (reference OCArill8108 and OCAll098206) y (3) In accordance with Section 6 of the Technical SpecificaLions for eacii Unit, the shift

" crew composition may be less than the minimum number of operators (licensed and

- non-licensed) shown for a period of time not to exceed two hours in order to accc.anodate unexpected absence of on-duty shift crew members, provided immediate action is taken to restore the shift crew composition to within the minimum number of operators.

(4) The minimum staff for a Unit which is in Cold Shutdown will be 1 Senior Reaclor Operator,1 Reactor Operator, and 1 flon-licer. sed Operator for that Unit.

(5) The Shift Technical Advisor will be available to be in the Control Room of the affected Unit within 10 minutes of being notified, when either unit is above cold shutdown.

(6) llay be provided by shif t personnel assigned other functions.

t (7) Although such a short response time may be achieved in many cases, it is not possible

, to assure this response time in every instance.

(8) First-aid shift coverage to be implemented at a later date. (reference OCAN098206) r --- - r & & e & "" -~~ - ' ' ~ ~ ~~ ~~ ~ '~

I I I I I

~l A I l ARKANSAS POWER AND LIGHT COMPANY I

l &. I I L I l l i NUCLEAR CONTINGENCY PLAN IMPLEMENTING PROCEDURE I I I I I I

l PROCEDURE TITLE:

I I I I EMERGENCY CONTROL CENTER EVACUATION -

I I

I I I PROCEDURE NUMBER: 15 I

I' i REVISION NUMBER: 0 - 3/7/83_ l l

l l l I i RECORD OF REVISIONS I I I

I Page Revision- I Page Revision l Page Revision i I I ,

I I I I I I I I I -

l- 1 i l

I l i I i I l I I 1 -l-I I I I I I 1 I I I i

[- l I

i I .I I

l -. I I 'l I .

I-1 I I I l l-l l l 1 i ~l l- l 1 I

I 1 I I I I I I I i l l I i I I I I I I 1 I I I l l I

,' -l

~

1 I I l i 1 1 I I I I I I I i

l I I I I l

' i l- I I

I I I I I I I I I I I I i i i I I I i I I l -

.l . I I

I APPROVED BY: &, -,w , APPROVAL DATE:

I l

SENIOR VfCE PRESIDENT ENERGY SUPPLY I i \' l I 1

-7A-1

i l i i l l A l flVCLEAR l PROCEDURE TITLE: l NUMBER: 1 l P l CONTINGENCY PLAN I EMERGENCY CONTROL CENTER I I

- l & I l EVACUATION

( l l

L l 1

l 1 Pace 1 of 15 I

l 15 I l

l l

l l ARKANSAS NUCLEAR ONE l Revision: 0 Date: 3///83 l I

I l I

l i

EMERGENCY CONTROL CENTER EVACUATION l 1 -

1 I

l I. INTRODUCTION i 1

I I

I This procedure addresses the activities related to the relocation of l 1

the Emergency Response Organization to an alternate emergency response l I

facility in the event that evacuation of the near-site Emergency l l Control Center (ECC) is necessary. In general this procedure provides l 1 guidance for determining the necessity for ECC evacuation, for l l maintaining command and control continuity, and for re establishing a l l functional emergency center at the back-up facility. l l

II. l l NOTES AND PRECAUTIONS l

l 1

l The mechanism for evacuating the near-site ECC is based on the l l following concepts:

l l

• l l The ECC has been fully activated by the Emergency Resoonse 1 l Organization, and/or the secondary Technical Support Center has l 1 been established at the ECC. l I

• I l

The responsibility for declaring an ECC evacuation rests with the l I

Incident Response Director (IRD), or with the Recovery Manager in l l the absence of the IRD/IRD alternates. '

l l

• I 1

The decision for ECC evacuation is based on the consideration of I l

protective actions as a result of offsite dose projections and/or l l ECC radiation alarms. I i

• 1 l Unless an immediate evacuation is required due to a rapid l l deterioraticn of conditions, the ECC evacuation would usually [

] occur in stages. Media and non-essential personnel in the fledia l

r l Center and other radiologically uninhabitable areas may be l l required td evacuate first, followed by a secondary ERO group, [

l and then a' primary ERO group thus completing the ECC evacuation. l l The IRD, or the Recovery Manager as appropriate, will determine l l

the exact schedules, priorities, and designation of groups and/or [

] selection of personnel affected by the ECC evacuation [

] decl,a ra ti on.

l l

l l

• Transportation to the alternate ECC will be via personal and l l available AP&L vehicles. Special transportation needs should be l l directed to the Logistics and Procurement Coordinator. l l

l 1

I I

I l

1 l

l l

1 I

I 7A-2

l 1 -1 l .

I I A ] NUCLEAR' l PROCEDURE TITLE:

I l P l CONTINGENCY PLAN l l NUMBER: l EMERGENCY CONTROL CENTER I l 1 .& .I 1 EVACUATION

(: l l

L 1 l

l 1

l 15 l l

l l l Pace 2 of 15 l ARKANSAS NUCLEAR ONE i Revision:-0 Date:

l I 3/7/83 [.

I

.I l l

• l I_

Media personnel are to relocate to the Russellville High School, l or to an alternate as designated by the the Media Center Manager. I l

l

-If an alternate facility is to be used, the alternate location l should be coordinated in. advance with the Arkansas Department of l I Health.

I 1 l

• I ERO personnel are to relocate to the AP&L Russellville District -l l Office unless otherwise instructed by the IRD. The alternate to l l the AP&L District Office is the Little Rock Support Center. I l

l~ III. INSTRUCTIONS l I I l A. l ECC EVACUATION CRITERIA 1 i l 1. I

.I Guidance for determining the necessity for ECC evacuat' ion is i provided in Attachment 1.

I I l 2. I Normal evacuation is a stepwise relocation of the ERO such l l

that the Alternate ECC is activated and partially staffed l l before complete ECC evacuation.

I l l 3. l s'

An immediate evacuation is a rapid and complete evacuation I I

of.the entire ECC at once without delays. I I

B. I I

RESPONSIBILITIES / IMPLEMENTATION '

1 l I 1. I Declaration of an ECC evacuation and subsequent actions are l

-l to be determined by the IRD, or Recovery itanager as I l

appropriate, after considering the following: I 1 ,

l I

a. The specific conditions that exist; and l [

1 l b. Technical Support Manager's recommendation for action l l bfsed upon trends / projections of conditions and the [

l , guidance of Figure 15-A-1; and l l l

l c. Dose Assessment Supervisor's report on the radiological l l habitability of the Alternate ECC based upon offsite l l

dose projections and/or area survey measurements; and l I

l ' d. any alternate or additional actions that otherwise may I

l [

be appropriate based on professional judgment. l 1

I l 2. The IRD shall determine the exact schedules, priorities, and l l

selection of personnel affected by the ECC evacuation i 1 declaration, dependent upon the situation. He may consider l l the following actions: -

I l I l l i l I 1

7A-3

1 I i .I l "A NUCLEAR i l

l. -l PROCEDURE TITLE:

I P 1 CONTINGENCY PLAN l l NUMBER: 1

& . EMERGENCY CONTROL CENTER I l l l l EVACUATION

<( .

l l

.L - l 1

l l

1 15

-l l

1 Page 3 of 15 l l l ARKANSAS NUCLEAR ONE I Revision: 0 Date:

l I 3/7/83 l I

3 I l

l a. -

. l Direct the-Assistant IRD to relocate to the Alternate l l

ECC if habitable, and activate the Alternate ECC with.

i l

l the assistance of the Local Advisory Supervisor. l-l b. l.

l After consultation with the Recovery' Manager and l l

Corporate Security Coordinator, determine minimal ERO l l

personnel staffing to temporarily continue emergency l support activit'ies.

1 l l c. Direct all ECC personnel, except those designated for I

l l l

any necessary minimal support effort, to evacuate and -l l

take essential materials and equipment to the Alternate l ECC.

I l I d. The IRD should temporarily transfer his duties to' the I l l Assistant IRD or the Recovery Manager as he deems l l

appropriate to ensure continuity of ERO control l l

responsibilities while he is in transit to the [

l Alternate ECC.

I 1

(. l e.

1

( l l

After the Alternate ECC has become operational, instruct the remaining ECC minimal support personnel to l I

evacuate and secure the area. l l

l 3. l The IRD should ensure that the Recovery Managdr is advised.

l when the ECC may be evacuated. If the Secondary l

l l Technical / Operational Support Center is operational, the'- 1 l

Recovery Manager shall instruct TSC/0SC staff to gather

l. plant drawings, maps, logbooks, 5520 status reports, and i

l l l

other essential technical materials and portable equipment 1-or instrumentation (e.g. GERMS terminal and modem) in l preparation for evacuation. l l 1 l l The Recovery Manager should advise _the Shift Operations

.I Super;/isor when the ECC may be evacuated. l

-l l l 4. The IRD Staff Manager (IRDSM) should ensure that the Local l l l Advisory Supervisor is advised when the ECC may be l l evacuated. The Local Advisory Supervisor is responsible for l l

'l preparing the Alternate ECC (Russellville District Office) l

' to receive the ERO.

l l l 5. l The IRDSM should ensure that the Corporate Security l l Coordinator is advised when the ECC may be evacuated.

l The l Corporate Security Coordinator is responsible for ensuring l that: l l l l l 1 l

.I I I I i

7A-4

I I I I I l A i NUCLEAR l PROCEDURE TITLE:

l P i NUMBER: l l CONTINGENCY PLAN l EMERGENCY CONTROL CENTER I I i & 1 l EVACUATION I 15 l L

C l l

i l

l l Pace 4 of 15 l l l

l l

1 ARKANSAS NUCLEAR ONE i Revision: 0 Date: 3/7/83 l l

I l

i I

l a. ECC security personnel implement evacuation procedures. l I

i l b. State / local law enforcement is advised, and traffic I 1

control is requested when necessary. I I

I l c. Security is established and maintained at the Alternate l l ECC, utilizing the ANO Security Force. ]

I I

l d. Accountability of ERO personnel is performed at the l l Alternate ECC.

I 1 l

l e. The ECC and plant site is adequately secured after l l evacuation.

I l I

I 6. The IRDSM should ensure that the Emergency Media Center l l Manager is advised of'the necessity for the news media to l l

relocate to an alternate location. The Emergency Media l l

Center Manager shall be responsibile for implementing i I evacuation of the media and coordinating with the State for l b

l activating the Russellville High School.  !

i

(" l 7.

The IRDSM should ensure that an announcement is made to I

l l advise all personnel of the situation, ano the actions to be [

] taken upon ECC evacuation.

I l '

l l 8. The IRDSM should ensure that the NRC and State / local l l

Emergency Operations Centers are advised when the ECC may be l l evacuated.

I l '

I l 9. The IRDSM should ensure that the Telecommunications l l Coordinator is advised when the ECC may be evacuated. The l l Telecommunications Coordinator shall be responsible for i 1 ensuring that communication links between the Alternate ECC i I and the ANO Control Room are operational.

l l 1

i 10. The L'ogistics and Procurement Coordinator should coordinate l l with the Local Advisory Supervisor and the Corporate l l Security Coordinator in order to support any special needs l l for the transport of evacuees and/or for the operation of I l ,the Alternate ECC (e.g. office trailers, supplies, etc). l I

l C. 1 ALTERNATE ECC l

I l 1. I The Alternate ECC is the AP&L Russellville District Office i I

located at 305 South Knoxville Street, Russellville. l I

I l Assigned ERO work areas are identified in Figure 15-C-1. l I

A map showing routes to the Alternate ECC is provided in l l Figure 15-C-2.

I I I I I

I I

7A-5

I I I I  !

l A l NUCLEAR l PROCEDURE TITLE: I !! UMBER: l l P l CCtlTINGEtiCY PLAN- l EMERGENCY CONTROL CEllTER I

( & l l 1 l EVACUATION l 15 l l L I l

- l l 1 I l Pace 5 of 15 l l

l l ARKANSAS NUCLEAR ONE I Revision: 0 Date: 3/7/83 l I

i l l

2. l l Upon declaration of an ECC ERO evacuation, the Local l l Advisory Supervisor should ensure the following: l 1

I l a. All non-essential Russellville District Office l l personnel clear their work areas and vacate the l l building.

l l

b. l l Coordinate with the Corporate Security Coordinator to l l establish area security control. I i

c.  !

l Utilize staff assistance as required to prepare the l l facility for use by ERO personnel and to maintain l l communications with ANO and the ECC. l l

d. l l Convey to the IRDSM any problems and/or requests for l l additional assistance in activating the Alternate ECC. l I

3. I l The Technical Support Manager should instruct the Emergency l l , Radiation Alternate Team Leader (ERAT) to implement the l following actions: l l

1 j i

, a. A radiological survey of the Alternative ECC is l l performed to confirm adequate habitability; l l

1 l b. Establish health physics teams at Alternate ECC ent'ry l l points to perform radiological monitoring of personnel l l prior to entry and vehicle contamination monitoring; l l

[ c. Establish a decontamination team, as required, at the l'

l l Alternate ECC to perform personnel and vehicle l l decontamination actions; and

]

I

d. l l Direct radiation and airborne survey measurements of I l the Alternate ECC are periodically taken, recorded, and l l monitored.

[

l

4. l l After arrival at the Alternate ECC, the IRD should: l l

j a. l Ascertain the operational status of the Alternate ECC. l I

I l b. Reassume IRD duties and obtain a briefing from the l '

l Assistant IRD.

l I

c. I l When appropriate as applicable, instruct any remaining l l ECC minimal support staff to relocate to the Alternate l l ECC.

I i

1 1 I I I I I

I l

_ 7A-6

I I I i l l A l tluCLEAR l PROCEDURE TITLE:

l P I flUMBER: l l CONTINGENCY PLAN l EMERGENCY CONTROL CENTER [ l

) & 1 l EVACUATION 15 f

I L I I I

I l

I

[ }

} Pace 6 of 15 l l 1 ARKANSAS NUCLEAR ONE Revision: 0 Date: 3/7/83 I I I I

I 1

l d. Ensure that the AN0 Shift Operations Supervisor and l l

Little Rock Support Center Planning and Scheduling l l

Coordinator and Federal, State and local emergency l l

operation centers are advised of the relocation to and 1 1 operational status of the Alternate ECC. 1 I

I I S. Upon the conclusion of the emergency, ensure the Alternate l l ECC is deactivated and returned to normal operations. I I

I I

I I

I I

I I

I I

I I

I I

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I I

I I

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I

s. I I

I I

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I '

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I i

1 1

1 I

I I

I I

I I I I I I i I i

i l

l i I l I

I I

i ,

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I I

I I

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• I l

I i

I I

I I

I 7A-7

I i  !

l A l NUCLEAR 1 PROCEDURE TITLE:

I l P l CONTINGENCY PLAtt i It UMBER: l Ef1ERGEtiCY CONTROL CENTER

( l & I 1 I l EVACUATION l 15 l L I l l

l l l l l l l Pace 7 of 15 l ARKANSAS NUCLEAR ONE l Revision: 0 Date:

l i 3/7/83 i I

I I l I ATTACHMENT 1 I I l l I I ECC EVACUATION GUIDANCE I I I I l CONDITION I RECOMMENDED ACTIONC l l ~

i 1. Plant Evacuation declared, Consider relocation of media and/or l

I or likely to occur I i

non-essential AP&L personnel if I additional ECC space is needed to l l

process plant evacuees. I l

l 2. Exclusion Area and/or Area l Consider protective action for media l l Evacuation declared and/or non essential AP&L personnel l l

' consistent with the protective action I l

l recommendations made for the general l public per the applicable ANO l l

I Procedure 1903.31 or 1903.32. I l 3. Area Survey Measurements I Consider evacuation of all non- 1

, i Exceed 2.5 mr/hr in essential personnel from the l Unprotected Areas of ECC unprotected creas of the ECC.

l I l

4. i 1 ECC Protected Area Radiation Verify ECC ARM alarm. '

l l Monitor Warning Alarm (1 mr/hr) l l l

Conduct area radiation survey of I unprotected areas of ECC and evacuate l l

all personnel in those areas if I l necessary.

I I l I Consider having all ERO personnel, [

l l

other than activated Emergency l Response Teams, to remain sheltered in l l ,

the protected area of the ECC, unless l l

otherwise instructed by the IRD. I I

1 5. ECC Protected Area Radiation Verify ECC ARM alarm. i l

l Monitor alarms Hi (2.5 mr/hr) l l and/or iodine concentration Consider evacuation of all non-l exceeds 5' x 10-10 pCi/cc. essential personnel from the 1 l

l protected areas of the ECC. l I

I l All ERO personnel should remain l I

sheltered in the ECC protected area. I l

1 I 1 1 I I I I l i I

~

7A-8

I i .

I l A i l l NUCLEAR I PROCEDURE TITLE:

1 P I tlUMBER: 1 l CONTINGEllCY PLAN I EMERGENCY C0tlTROL CEilTER I i & I l I EVACUATION 15 C l l

L i l i

l l

l l

l l l Pace 8 of 15 l ARKANSAS NUCLEAR ONE l Revision: 0 Date:

l 1 3/7/83 l 1

I I l I I

Increase frequency of airborne and l l

direct radiation monitoring of ECC; l l insure ECC filtered ventilation is l I

operational; record MPC hours. I i 6. ECC Protected Area radiation I If conditions are estimated to be l I

levels exceed 100 mr/hr but temporary (less than 30 minutes),

l I l

less thani R/hr, and/or iodine continue on going protective actions. l concentration exceeds 1 MPC l (9x10-'3 pCi/cc). l l If conditions are estimated to be l l

long-term (greater than 30 minutes), I I

initiate ECC evacuation. I l 7. ECC Protected Area radiation l l levels exceed 1 R/hr, and/or Immediate evacuation of the ECC is l requirea.

l l iodine concentration exceeds '

l 4 MPC. l I I I I I I l I L i I I I I I I ,

- 1 I I I I I I I I I I I I I I I I I I J I I I l l l I I I I I I l l- 1 I I I I i l i I I '

i l I I I I I I I i

7A-9

i l I l A i I

] NUCLEAR I PROCEDURE TITLE:

l P 1 NUMBER: l l CONTINGENCY PLAN l EMERGENCY CONTROL CENTER

( l & I i I l EVACUATION l 15 l L l l l

l l l 1

[ ]

l Paoe 9 of 15 l ARKANSAS NUCLEAR ONE i Revision: 0 Date:

l l 3/7/83 l l

l l l l EMERGENCY CONTROL CENTER l l l 1 EVACUATION CHECKLIST 1 l I

l Incident Response Director Actions I l l i Initial l l

l 1. l Determine the need for ECC evacuation after l considering the following input: l I I

a. l I the specific conditions that threaten the l habitability of the ECC, and l l I l b. Technical Support Manager's recommendation l l

I for action based upon trends / projections of I l conditions and probability of situation l l improvement, and I l l c. The guidance of Figure 15-A-1, and I I l

d. I

, i Dose Assessment Supervisor's report on offsite 1 l dose projections and/or area survey l l measurements.

I 1 l 2. If deemed necessary, declare a normal evacuation l l

l or an immediate evacuation and take the following l actions: .

l 1 l-l a. Select the Alternate ECC facility: l l l l l (1) Russellville District Office if habitable l l based on Dose Assessment Supervisor's l report; l l I l

I (2) Otherwise, the Little Rock Control Center.

I I l b. Determine relocation schedules, priorities, l I

l personnel assignments, and other logistical i I

actions as necessary to implement an orderly l evacuation. l 1 l l 3. Advise the Recovery Manager of the ECC I l

l evacuation declaration.

l l l l 1 l I 1 I I I I l I l

7A-10

I I i i l I A i fluCLEAR l PROCEDURE TITLE:

I P l NUMBER: 1 l CONTINGENCY PLAN I EMERGENCY CONTROL CENTER l

& l l I l EVACUATION I 15 I C I L l_ l I I l l l Pace 10 or 15 l l

l l ARKANSAS NUCLEAR ONE I Revision: 0 Date: 3/7/83 l I

i l l

4. l 1 Direct the IRD Staff Manager to advise the i i following personnel of an ECC evacuation:

I I i

l a. Local Advisory Supervisor l i l

I b. Corporate Security Coordinator l i I

l c. Emergency Media Center Manager l l 1

i d. State / local liaison i l

l i e. USNRC I 1

f. l l Telecommunication Coordinator i l

I 5. l Ensure that an announcement is made to advise l I all ECC personnel of the situation, and  !

I actions to be taken. I I

6. i l

Direct the Assistant IRD to relocate to i I the Alternate ECC if habitable, and activate i I

the Alternate ECC with the assistance I

) of the Local Advisory Supervisor.

l l

7. 1 l After consultation with the Recovery l l Manager and Corporate Security Coordinator, I l determine minimal ERO personnel staffing i i to temporarily continue emergency support l' I activities, and advise designated personnel l l accordingly.

I I

8. I l Direct all ECC personnel, except those i

i designated for any necessary minimal l

I support effort to evacuate and take l

l essential materials and equipment to l

l the Alternate ECC at the appropriate time. I l

l l 9. Temporarily transfer your duties to the l

l Assistant IRD or the Recovery Manager as l l you deem appropriate to ensure continuity l l of ERO control responsibilities while in I

i transit to the Alternate ECC. l I

I I

I I

I I

I i '

1 l

1 I

l I I l l

_ 7A-11

l. I i I A i l-I NUCLEAR I PROCEDURE TITLE:

1 NUMBER: I l' P l CONTINGENCY PLAN I EMERGENCY CONTROL CENTER l l g i & l. l EVACUATION

'l' L 1- 15 .l J i 1 1 I I l Paoe 11 of 15 l l ARKANSAS NUCLEAR ONE l Revision: 0 Date: 3/7/83 l l l I .

l 'l l

l 10. After arrival at the Alternate ECC, the IRD 1 l should:

l l

l l a. .Obtain a briefing from the Assistant IRD l l and reassume the.IRD's duties. l l

1 l b. -Ascertain the operational status of l

l the Alternate ECC. l-1 I

I c. If the Alternate ECC has become l l operational, instruct the remaining ECC l l minimal sepport personnel to l l secure their areas and evacuate to the i I Alternate ECC. l I

I l d. Make certain the ANO Shif t Operations I l Supervisor and:Little Rock Support Center l l -Planning and Scheduling Coordinator I l' and Federal, State and local emergency l l operation centers'are advised of the l l relocation to and operational status' I l of the Alternate ~ECC. I I

l 10. Upon the conclusion of the emergency instruct

'l-i I appropriate personnel to deactivate the l l alternate ECC and return to normal operations. l I

I I

l-l-

~

1 I

l I

l l

1 1

I I

I I

I I

I I

I I

I 1

I I

I I

I I

I I

I I

I I

I I

I

l. ~

I I

I I

I I

I I

I 7A _ _ _ _ _ _

.I i .

l 1 -l l A- -l. NUCLEAR

I. PROCEDURE

TITLE: ~.1 NUMBER: 1 I P _l CONTINGENCY PLAN I

] & I EMERGENCY CONTROL CENTER I l' I EVACUATION -l 15 I C l .L l' l l 'l

.1

1. Pace 12 of-15 l l

l ARKANSAS NUCLEAR ONE l Revision: 0 Date: 3/7/83 l l

l l l

ALTERNATE ECC 1..

l 1

'l ACTIVATION CHECKLIST ~ l l

1.

l I

(Russellville District Office) l I

i A. LOCAL ADVISORY SUPERVISOR ACTIONS 1 I

I i 1. Upon being advised that activation of the Alternate ECC is l-1- necessary, take the following actions: l~

l 1

1 a. Utilize staff assistance as required to prepare

.I i the facility for use by ERO personnel and to 'l i

maintain-communications with ANO and the ECC. 1 I

I l b. Advise all office field personnel to. return and 1' I secure their vehicles and equipment. 1 I

I I c. Instruct all non-essential Russellville District l I Office personnel to clear their work areas and- .1 1 vacate the building. Suspend all customer service i s I activities, but maintain-minimal line crew for I l .. emergency repair capability. I I

l' 'd. Coordinate with the Corporate. Security Coordinator l

l l -to establish area security. control. l l

l Check operational status of office communication l e.

l-

.. l-systems (ANO radio and telephones). I' l

l l f. Convey to the IRD Staff Manager (or Assistant IRD) I 1 any problems and/or requests for additional I l- assistance in activating the Alternate ECC. l I

i l g. Upon arrival by the Assitant IRD, provide l I

follow-on assistance that is determined necessary. I I

2. l-l Upon termination of the emergency, return facilities and office l l operations to normal status, l I

I I B. ASSISTANT IRD ACTIONS I

l 1

,' i 1. Upon being advised by the IRD that an ECC evacuation to the l

.I Russellville District Office is necessary, take the following l

l. actions:

I I

I I '

I 1

I I

I I

I I

I 7A-13

l t

i I I i A I i l NUCLEAR l PROCEDURE TITLE:

l P l NUMBER: I l CONTINGENCY PLAN l EMERGENCY CONTROL CENTER I l l & I l EVACUATION l 15

( l l

L 1 l l

l l

l l Pace 13 of 15 1 1 l ARKANSAS NUCLEAR ONE l Revision: 0 Date: 3/7/83 l 1 1 I

I I

I l a. Confer with the Technical Support Manager to l 1 obtain status of offsite radiological habitability [

] in the area of the Alternate ECC, and to ensure that l l monitoring tasks per Section C3, Contingency Plan I.

1 Procedure #15 will be performed. l I

b. i l Confer with the Local Advisory Supervisor and ensure I i that he has been advised to begin activating the l l Alternate ECC. I l

c. l 1 Obtain support personnel as necessary, and relocate i i to the Alternate ECC. I I

I l d. After arrival at the Alternate ECC, obtain l l activation status report from the Local Advisory l l Supervisor.

I l

e. l l Advise the Telecommunications Coordinator of any [

] communication system problems. l I

i l f.

Advise the Facilities Maintenance Coordinator i

. I of problems with any other facility equipment. l 1

l l g. Advise the Logistics and Procurement Coordinator I of the need for additional operational support, l

l l as necessary.

l l

l l h. Prepare to brief the IRD upon his arrival as to .

l-l the operational status of the Alternate ECC. l l

2. l l Upon termination of the emergency, coordinate with the Local l l Advisory Supervisor to assist in returning the facility to normal l l operations.

l 1

1 I

i i

i l

i I

I I

I I

I I

I I

I I

I I

i l

i I

I I

I I

I I

I I

I I

i 7A-14

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• E PAGE 14 of 15 ALTERNATE EMERGENCY CONTROL CENTER RUSSELLVILLE DISTRICT OFFICE FIGURE 15-C-1

I I i A 1 1 I I NUCLEAR l PROCEDURE TITLE:

I P l CONTINGENCY PLAN I NUMBER: l I EMERGENCY CONTROL CENTER l [

l & 1 1 EVACUATION i 15 I L l l 1 l l l l Page 15 of 15 l l l

ARKANSAS NUCLEAR ONE I Revision: 0 Date: 3/7/83 l 1

I I

l l FIGURE 15-C-2 l l

l l

, I i

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RUSSELLVILLE DISTRICT OFFICE I i . . ,

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l Directions w.wxh yll I

) l From ANO take Highway 333 northeast to Highway 64. Travel east on Highway 64l l to Highway 7T (Knoxville Street) and turn south. Travel on 7T south for l l approximately three blocks. The Russellville District Office will be on i

l

. I the east side of the street. (305 South Knoxville Street) l

' I I

I I

I l

i I

I 7A-16

ARKANSAS POWER & LIGHT COMPANY ARKANSAS NUCLEAR ONE UNITS 1 & E l

RESPONSE TO SUPPLEMENT 1 TO NUREG 0737 REQUIREMENTS FOR EMERGENCY RESPONSE CAPABILITY r GENERIC LETTER NO. 82-33 APRIL 15,1983 H h TCN

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VOL. 2 1

i APPENDIX 68 f

i ANO-1 PLANT SPECIFIC TECHNICAL GUIDELINES

?

i t

Arkansas Nuclear One

~

Unit 1 .

= " M m % " !iR B m a % %; d 5 55 M -

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gbnormal Transient Operating Guidelines  :

(ATOG)

Part II -Volume 1 .

Fundamentals Of Reactor Control For Abnormal Transients

. .'^ -

74-1122058-00 Babcock &WilCOX ,

, , , . 4 ; - ,

BWNP-20004 (6-76) r

( BABCOCK & WILCOX NUCLEAR POWER GENERATION DIYl5CN TECHNICAL DOCUMENT ARKANSAS NUCLEAR ONE UNIT I ABNORMAL TRANSIENT OPERATING GUIDELINES PART II VOLUME 1 74-1122058-00 Doc. ID - Serial No., Revision No.

for ARKANSAS POWER AND LIGHT COMPANY by BABCOCK & WILCOX l

( THIS DOCUMENT WAS PREPARED FOR ARKANSAS POWER AND LIGHT COMPANY UNDER l MASTER SERVICE CONTRACT NO. 582-7065 (B&W No. 582-7108). ANY USE OF THE INFORMATION CONTAINED HEREIN OTHER THAN UNDER THE EXPRESS CONDITIONS OF SAID CONTRACT IS EXPRESSLY PROHIBITED WITHOUT THE WRITTEN PERMISSION OF THE BABCOCK & WILCOX COMPANY.

PAGE 1

BWNP-20007 (6-76)

BABCOCK & WILCOX NUCLEAR POWER GEN ERATION Olvl5loN TECHNICAL DOCUMENT 74- 122058-oo ATOG GUIDELINES PART II TAB NAME VOLUME 1. FUNDAMENTALS OF REACTOR CONTROL FOR ABNORMAL TRANSIENTS e

, Introduction s

Chapter A - Basic Heat Trans fe r Heat Trans fer Addendum A - Subcooled, Saturated, A-Subcooling Superheated Water Addendum B - Natural Circulation B-Natural Circulation Chapter B - Use of P-T Diagram P-T Diagram Chapter C - Abnormal Transient Diagnosis Diagnosis and

& Mitigation Mitigation r Chapter D - Backup Cooling Methods Backup Cooling

( Chapter E - Best Methods for Equipment Equipment Operation Operation Chapter F - Post Transient Stability Stability Determination i

u

~

DATE: ^

8-20-82

BWNP-20007 (6-76)

BABCOCK & WILCOX Numun NUCLEAR POwee otNERATION DIYl580N 74-1122058-00 TECHNICAL DOCUMENT VOLUME 1 FUNDAMENTALS OF REACTOR CONTROL FOR ABNORMAL TRANSIENTS List of Figures Figure 1 Fundamental Methods of Heat Transfer Control Figure 2 Illustration of Parameters Contributing to Natural Circulation Driving Head H Figure 3 Transition to Natural Circulation using EFW Figure 4 DELETED Figure 5 DELETED Figure 6 DELETED Figure 7 DELETED Figure 8 Power Operation P-T Diagram Figure 9 Post Trip P-T Diagram Figure 10 Typical Response of Major Plant Parameters Following a Reactor Trip Figure 11 Overheating Transient (Pre-trip) itgure 12 Overcooling Transient (Pre-trip)

Figure 13 overpressure Transient (Pre-trip)

Figure 14 Depressurization Transient (Pre-trip)

Figure 15 Loss of Main Feedwater g- Figure 16 Small Steam Line Break (0.5 Ft2)

Figure 17 Excessive Fcedwater g Figure 18 Small LOCA in Pressurizer Stean Space Figure 19 Small LOCA in RCS Water Space Figure 20a Ceneral Plant Accident Mitigation Figure 20b Excessive Primary to Secondary Heat Transfer Figure 20c Loss of Primary to Secondary Heat Trans fer Figure 20d Inadequate Subcooling Margin Figure 21 Accident Mitigation Approach Figure 22 Overcooling Diagnosis Chart Figure 23 Overheating Diagnosis Chart Figure 24a Backup Cooling by RPI for Loss of All Feedwater (No Operator Action)

Figure 24b Backup Cooling by HPI for Loss of All Feedwater (With Operator Action)

Figure 25 RC Pressure / Temperature Limits Figure 26 Illustration of Loss of Natural Circulation Due to Buildup of Steam in the Reactor Coolant System Figure 27 Boiler-Condenser Cooling Figure 28 Loss of Natural Circulation - System Refill by HPI Figure 29 Core Exit Fluid Temperature for Inadequate Core Cooling Figure 3G HPI Control Logic Figure 31a Cooldown on one Steam Generator (Steau Pressure Controlled)

Figure 31b Cooldown on One Steam Cenerator (Steam Pressure Not Controlled)

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BABCOCK & WILCOX NUCLEAR PCWER GENERATION DIVI 510N TECHNICAL DOCUMENT 74-1122058-00 VOLUME 1 FUNDAMENTALS OF REACTOR CONTROL FOR ABNORMAL TRANSIENTS List of Tables Table 1 How Failures Af fecting Heat Transfer Can Af fect Reactor Ope ration Table 2' Stand:rd Post Trip Actions Table 3 Actions to Correct Fast Transients

s. Table 4a How to Dif ferentiate a LOCA from Other Transients Table 4b Symptoms for LOCA's That Can be Located or Isolated Table 5 Rules for RC Pump Trips Table 6 RC Pump Restart Guidelines 7

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BABCOCK & WILCOX NUCLEAR POWER GENERATION DIVI $lON suusER TECHNICAL DOCUMENT 74- 22058-oo ATOG GUIDELINES PART II INTRODUCTION The 3-28-79 accident at the Three Mile Island Nuclear Power Generating

/

plant has caused the Nuclear Industry's perspective of emergency operation to change. That accident was dif ficult for the plant operators to handle because several things were happening at once. Loss of Main Feedwater, Loss of Eme rge ncy Feedwater, and Small Break LOCA occu rred at the same time. An incorrect interpretation of pressurizer level misled the ope rato rs to think the core was covered when it was not. The operators r acted on that misleading in formation and core cooling was stopped when q they shut down Eme rgency High Pressure Inj ection and the Reactor Coolant Pumps. The combination of multiple failures and incorrect interpretation of information are the two factors which have caused a new perspective of emergency operation to be developed.

l In the past, eme rgency procedures and operator training concentrated on single event acc ide n t s . But accidents do not usually happen with only single failures; several things often go wrong at the same time. These guidelines have been developed so that an operator can understand what has gone wrong in order to circumvent failures and still keep the core cool with the available equipment.

When failures of equipnent occur, they frequently cause a ch ange in the f

heat transfer from the core to the steam generators. khen the reactor is DATE: 8-20-82 PAGE 4

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TECHNICAL DOCUMENT operating normally, all the heat produced by the core is being removed by the steau generators; primary and secondary sys ten pre s s ur e s, t empe ra-tures, and levels are stable. Heat transfer is balanced. Any transient will cause an upset in the heat transfer from the core to the steam gene-rators and the main objective of emergency procedures is to restore and maintain adequate core cooling. Heat trans fer will be af fected in di f-ferent ways depending on what equipment has operated incorrectly. When the heat trans fer changes, the effects will show up in primary and secondary system pressures, temperatures, and levels. Pressures and I temperatures are paraneters from which three basic symptoms of improper heat trans fer can be derived and used to discover what has gone wrong.

These guidelines will use those heat trans fe r symptoms as the source of information for the operator action. Recognition of just three basic heat t rans fe r symptoms will give the knowledge needed so the ope rato r can re-store and maintain adequate core cooling.

Correlation Between Part I and Part II Use of symptom-oriented procedures involves a more basic approach to plant control and requires a shift in emphasis in operator training. The opera-l tor is no longer impeded by, nor does he rely on, the designer's fore sight l

f in providing the key alarms and indications for every conceivable event l i

l that could occur. The symptom approach of Part I will work, regardless of l

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the event. By training on the ATOG approach, the operator will have a thorough understanding of heat transfer, plant control, and the various options available fo r controlled core cooling when systens and equipment ,

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BABCOCK & WILCOX HuusER HUCLEAR POWER GENERATION DIVISION TECHNICAL DOCUMENT 7'- 22058-00 fail. Part II of ATOG was written to provide the basis for this unde rs tanding with the intent that it be used as part of the operator training program.

7 Part II, Volume I s Volume 1, "Fu ndame n t als of Reactor Control for Abnormal Transients," pro-vides the basic background necessary for understanding heat transfer and builds on this in'lo rma t ion to enable the operator to recognize abnormal conditions when they develop and take the appropriate actions to correct them. Vo lume 1 : overs primarily information regarding the heat trans fe r process, including s ubcooling and natural circulation. Volume 1 also e' shows how to use the P-T diagram and this knowledge of heat trans fe r to

( diagnose abnormal transients and mitigate them.

The preferred method of core cooling is with controlled primary to secon-dary heat trans fer and riany abnormal transients involve restoring a balance to this heat remeval path. However, this is not always pos s ible ;

the re fo re , Volume 1 discusses core cooling methods when the steam genera-tors are not available.

4 volume 1 also covers operational methods for key systems ( fe edwa t e r , HPI, etc.) and equipme nt for various conditions, and provides guidance on verification of plant stability.

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NucteAn Powea ceNenATioN DIYlStoN I 7 '+- 220n-00 TECHNICAL DOCUMENT Volume 1 contains a considerable amount of in formation and should be s tudied periodically for optimum comprehension and retention. Three major points should be kept in mind when reading Volume 1:

1. Understanding heat transfer is essential.

2. Relationship of symptoms and control functions.

3. Dif ferentiating between rules and guidelines.

Heat Transfer i l

One aspect of plant control and the use of ATOG cannot be overstressed:

the import ance of understanding heat trans fer and primary pressure-tem-perature relationships. A thorough grasp of the heat trans fer process and P-T relationships will enable the operator to:

1 recognize ibnormal conditions (symptoms) evaluate plant response to corrective actions implement backup cooling methods when needed Although virtually any event or combination of events could conceivably oc- ,

i 1

cur, they all present the common threat of disrupting core cooling. Thus, l the major thrust of ATOG is to maintain some form of controlled core cooling, whether it be by the . steam generators or ECC systems. Simply put, understanding heat transfer allows recognition of symptoms of ab-normal transients. Recognition of symptoms allows implementation of the appropriate sections of Part I. Implementation of the appropriate sec-tions of Part I and ve rification of plant res ponse allows s tabilization and restoration of controlled core cooling.

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BABCOCK & WILCOX Nuusen NUCtEAR POwlt GENERATION DIVISION TECHNICAL DOCUMENT 7'-n22058-00 Symptons and Control FunctionsSection III of Part I of the guidelines is divided into four main sections to address the basic heat trans fer symptoms (lack of subcooling margin, ove rh ea t i ng , and ove rcooling) and the special case of SG tube ru p ture .

' Part II discusses the import ance of " control functions". These control s functions are:

1. RC inventory

2. RC pressure

3. SG inventory

4. SG pres sur e A fif th i:ontrol function, reactivity, is also important in heat trans fe r

/ cons ide rat ions. However, reactivity is quickly controlled by au tomat ic

( reactor trip, manual reactor trip, and/or emergency boration.

If control of one of these four functions is lost, it will impact primary to seconda ry heat t rans fe r and become evident as one of the three symp-toms. For example, a loss of SG inventory control low (loss of feedwater) will res ul t in a loss of primary to secondary hear transfer (ove rhea t ing ) .

Conversely, a loss of SG inventory control high (too much feedwater) will k res ul t in excessive primary to secondary heat trans fer (overcooling).

Whe. a symptom appears, one or more of these functions are not being con-trolleu properly. Regaining control of these four functions will restore controlled core cooling.

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Rules and Guidelines Volume 1 provides guidance on the operation of systens and equipment for many conditions and vsrious events. When an action must always be taken for the conditions speci fied it is called a rule and is enclosed in a box for emphasis. For example, the RC pumps must always be tripped whenever the subcooled margin is lost; therefore, it becomes the RC pump trip rule.

Whenever specified actions are recommended, but not always mandatory, they are cons id e red guidelines. For example, Table 6 in Volume 1 provides guidelines for RC pump operation for dif ferent plant conditions.

ATOG was de s ig ned for maximum flexiaility in order to address the spect rum f of conceivable transients. The re fo re , rules have been kept to the minimum nec e s s a ry . The user should remember, however, that the guidelines are also important and should be followed whenever they are applicable and fe a s ib le .

Part II, Volume 2 Volume 2, "Di sc u s s ion of Selected Transients," provides detailed coverage of six specific initiating events. Although the ATOG concept is a break from the t rad i t ional event-oriented approach, Volume 2 was structured in the event-oriented approach to meet the following objectives:

1. Validate the ATOG Concept Mo,c ape ra to rs involved in the initial implementation of the ATOG concept will be experienced with use of event-oriented procedures DATE: 8-20-82 PAGE g

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BABCOCK & WILCOX NuuseR NUCLEAR POWER GENERAflON OlV15 TON 7'+-1122058 40 TECHNICAL DOCUMENT and may understandably be resistant to a dif ferent approach. Vol-ume I discusses ATOG in a general overview manner and, standing alone, may not fully promote user confidence in the concept.

Therefore, Volume 2 is provided to give examples of representa-A Live events and how the use of ATOG will lead to successful miti-gation. Although the event is given, the diagnosis and mitiga-tion is written with the assumption that the operator (in the example) is unaware of the specific cause.

In addition, the discussion on each transient demonstrates suc-I cessful mitigation of events compounded by other failures using Y the same basic ATOG procedure. This highlights the relative sim-plicity of using a single, comprehensive procedure as opposed to several discrete procedures.

The transients depicted in Volume 2 are derived from more realis-tic analyses than previously used for design bases accident analy-ses. Thus these t rans ient discussions should give the operator a k better feel for how the plant would actually respond should similar conditions occur. Where available, actual plant data from representative transients is used.

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2. Amplify Volume 1 The s t ruc ture of Volume 2 provides a ready vehicle for conveying more detailed information about transient types (e.g., over-c ooling) and peculiarities and complexities of specific events.

This is especially true for the appendices covering SG tube rup-ture and small break LOCA. These two events are unique in that they cannot be quickly terminated and stabilized. They impact many fac e t s of plant operation and their mi t igat ion is highly dependent on specific conditions at the time of occurrence (in-cluding the size of the leak). Consequently, considerably more event specific information is provided in these two appendices.

The entire purpose of these guidelines is to give an overview on reactor transients, their diagnosis and control, so transients as severe as the Three Mile Island accident will be prevented. Because transients will not follow a planned course, a symptom-oriented approach is necessary to ensure transient control.

These guidelines should provide enough background and understanding so that no matter what happens, the ope ra to r will have su f fic ient understanding to correctly respond to the transient using the principles of heat trans fer control.

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' TECHNICAL DOCUMENT CHAPTER A BASIC HEAT TRANSFER Introduction and Summary This chapter of the guidelines gives the basic principles of heat trans fer that are important for removing heat from the core so that it can be

' properly cooled. The chapter is divided into three parts: 1) " Basic Heat Transfer", 2) Addendum A - "Subcooled, Saturated, Superheated Water", and

3) Addendum B -

" Natural Circu la tion" . Addendum A and Addendum B give information on two general subjects. The part on " Basic Heat Trans fe: "

c ove rs two related topics: 1) the general process for heat removal through the steam generators , and 2) the ways the operator can control r

that heat transfer.

t The preferred way to protect the core and prevent fuel failure is to control the rate of heat removal by transferring core heat to the steam genera tors . Other ways to protect the core do exist; they are covered in a later chapter entitled " Backup Cooling Methods".

l r

To control core heat removal with the stean generator, the operator should u

j balance the heat generated by the core with the heat removal through the s tean ge nerato rs . This section will show the fundamentals of heat trans fer control and how the operator applies these fundamentals to get i

balanced heat removal .

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NUCLEAR POWER GENERATION DivtSION 7'- 22058-oo TECHNICAL. DOCUMENT Heat Transfer Equations The path for heat flow from the core to the stem generator is:

Core Heat  ; reactor coolant Reactor coolant heat  ! Steam genarator water and steam The stem generator then releases the heat either to the atmosphere s or to the condenser.

The concepts of heat sinks and heat sources are useful. For the first heat transfer path the core is the heat source for the reactor coolant and the reactor coolant is the heat sink. When the plant is tripped the reactor coolant pump neat becomes a significant heat source. For the second heat trans fer path the reactor coolant is the heat source and the steam generator water and steam is the heat sink. The a tmos phere and the condenser are heat sinks for the stem from the steam generator. In some unusual cases the reactor coolant can be colder than the stem generator fluid ; then the stem generator is a heat source which passes heat to the reactor coolant sink.

Two " kinds" of heat can be transferred to the stem generators :

1. Generated Heat - which includes RC pump work and nuclear heat l

which is the heat made within the core by the fission process; l it includes decay heat.

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2. Stored Heat - which is the heat of the metal parts of the reactor coolant system and of the reactor coolant When the reactor is operating at steady state and heat removal is

, balanced, the s t ean generators will remove the nuclear heat and RC i pump heat as it is generated and reactor coolant temperatures will s

not change. In other words, the stored heat will stay the same.

If the steam genera tors remove more heat than the core and RC pumps are creating, then they will remove both ge ne rated heat and stored heat; reactor coolant temperatures will drop. Normal cooldown is a 7 condition when both generated heat and stored heat are being removed within a specified rate; this is a controlled condition. If the condition is abno rmal or not controlled then it would be called overcooling and correct ive actions would have to be taken to bring it under control.

On the other hand, if the steam generators remove less heat than the core is creating, then the nuclear heat will increase the amount of reactor coolant stored heat; reactor coolant temperatures will in-b crease. Heacup from 0% to 15% power illustrates a controlled exam-pie @.ere the stored heat of the reactor coolant is increased by L

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74-1122058-00 TECHNICAL DOCUMENT heat addition from the core nuclear heat and the reactor coolant pumps. If a condition exists where the reactor coolant tempe ratur es increase abnonnally it is called overheating; correct ive actions would have to be taken to bring overheating under control.

Equations can be used to desc ribe the heat trans fe r path from the core to the stean generators. khen the heat transfer is balanced:

Equation 1)hcore= reactor coolant for the heat transfer path from the core to the reactor coolant and Equation 2) hreactor coolant = steam generator fluid for the heat transfer path from the reactor coolant to the steam and water in the secondary side of the steam generators Q is heat rate - units are BTU /hr.

khen heat trans fer is balanced all the way from the core to the steau generator, Equation 1 equals Equation 2. But when heat trans fer becomes unbalanced they will not be equal. Interruptions of the heat transfer path can happen when the reactor coolant is not a good heat s ink for the core (hcore N re actor coolant); or when the steam generator fluid is not a good heat sink for the reactor coolant (hreactor coolant / steam generator fluid)- /

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The unbalanced condition of concern for core heat transfer to the reactor coolant is when there is not enou gh heat transfer from the core to the reactor coolant. This can happen when the reactor coolant is no longer subcooled. For example, when the core is partly covered by water and partly by steam or covered completely by s s tean ; then Qcore / reactor coolant. When this happens not enough nuclear heat can be transferred from the core to the reactor coolant and the core will heat up. The stored heat of the fuel clad will increase which will result in increased fuel pin temperatures.

When the stean generator heat flow path becomes unbalanced, then the

' steam generator fluid will remove too much or too little heat from s the reactor coolant causing an overcooling or overheating , condition.

When this happens during a transient, Qreactor coolant will increase or decrease depending on the heat removal by the secondary side.

The reactor coolant temperatures will change in order that tempe ra t ure (thermal) equilibrium can be re-established between the pr ima ry and s econda ry side fluids. To show the e f fects, Equations 1

! and 2 can be written to add temperature terms:

s Equation 1 (Qcore " Qrc) can be written as:

Equation la hcore" rcCprc(Th-Tc )

where: Mrc = reactor coolant system mass flow rate (lbm/hr) r CPrc = specific heat capacity of the reactor coolant (BTU /lbm-F)

Th = core outlet temperature (F)

T c = core inlet temperature (F)

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Equation 2 (hre

• hsg) can be expanded as follows:

Equation 2a: Qsg = UAAT where: U= overall heat trans fer coefficient (btu /hr

- Ft2 - p)

A = total area of heat transfer surf ace (f t2)

AT = temperature differential across the heat transfer boundary (F)

Overall heat transfer coefficient is dependent on many factors, including the fluid conditions (primarily density and flowrate) on both sides of the boundary and the properties of the boundary (primarily. the thickness and thermal conductivity of the barrier and oxide layers). For this discussion we can assume that the properties of the boundary (steam generato r tube walls) remain constant and therefore can be ignored.

The secondary side of the steam genera to r has three different regions along the tube bundle during power operation: nucleate boiling , film boiling, and superheat. Each region has a di f fe rent heat transfer coefficient (U), surface area (A), and temperature dif ferential across the tube wall ( AT) . 'Ihe nucleate boiling region has the highest heat trans fer coefficient of the three and accounts fo r approximately 70-85% of the total heat trans fe r into the stean genera tor over the power range. The heat trans fer coefficient decreases by a factor of 3 to 10 in the film boiling region and again by another factor of 3 to 10 in the superheat region.

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NUCLEAR POWER GENEAATION DIVl510N TECHNICAL. DOCUMENT 74-1 2205840

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The heat trans fer surface areas and AT's involved for each of the three regions vary over the power range with the two boiling regions accounting for an increasingly higher percentage of the total heat t rans fe r with increasing power levels. Thus, to determine the r e f fec t s of transients on secondary heat removal during power s ope ra t ion, the e f fec t s in each of the three regions along the tube bundle must be studied.

However, for the purposes of these guidelines, we are primarily concerned witih control of heat removal by the steam generators after a reactor trip. After trip the steam generato rs are at saturation r conditions with two basic regions, saturated water and saturated

( s t ean . Almost all of the heat trans fer occurs in th e ,wa t e r region and most of the heat t rans fer in the water region occurs in the nucleate boiling portion below the steam / water interface. Saturated water is al arbing the latent heat of vaporization and the nucleate boiling provides a much higher heat trans fer coef ficient (U). Below this level the water is saturated wiin a considerably lower heat L

t rans fer coefficient, although this heat t rans fer coefficient is u still much higher than exists in the steam space.

Very little heat trans fer occurs in the steam space (primary side temperature can be considered equal to Thot throughout the steam DATE: 8-20-82 PAGE

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space). Even though the area is large, the heat trans fer coef-ficient is small due to low steam flow rates and low density with respect to the water region. During for ced circulation the AT ac ros s the tube walls in the steam space is also very small as Thot is close to T sat of the steam. The AT is larger between Thot and T sat during natural circulation but the heat transfer coef ficient is even smaller due to the lower primary flowrates.

The primary factors af fecting heat trans fer in the water region are surface area and the AT between the primary and secondary sides.

Surface area is increased by increasing feedwater flow to raise level. The primary increase in area takes place in the saturated water region. Even though most of the heat transfer occurs in the nucleate boiling region, overall heat trans fer is increased because the area of the steam space (with a very small heat trans fer coef-ficient) is decreased and replaced by area in the saturated water region (with a relatively much larger heat trans fer coef ficient).

The major method of af fecting primary to secondary AT is on the secondary side by varying steam pressure. When steam pressure is de-creased (e.g., by opening turMne bypass valves) saturat ion tempera-ture also decreases wh ich increases the AT ac ros s the tube wall.

The higher A T causes heat trans fer (Qsg) to increase thus cooling '

the primary side. Of these two factors (surface area and AT), AT is

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the major factor. Effects due to surface area are only significant wh ile the surface area is changing. Once a constant water level is maintained, changes in heat transfer are primarily due to changes in A T.

r L Heat t rans fe r can be increased significantly by injecting emergency feed wate r through the upper nozzles. The increase in heat transfer is due to two factors. First, and most significant, the spray of feed water into the steam space reduces steam pressure similar to the action of pressurizer spray. This reduces the saturation temperature which increases heai transfer as described previously.

r Second, where water contacts the tube surfaces in the steam space s the heat transfer coefficient is increased, essentially replacing stean area with water area as in the case of raising steam generator level.

Assuming a minimum adequate level is maintained in the steam genera-tors, variations in steam pressure will have a greater effect on b

heat trans fer than variations in level. 'the best method to decrease s heat transfer is to close the turbine bypass valves and allo the s tean gene ra to r pressure to increase. Allowing steam gene ra tor level to decrease will not have an appreciable effect on heat trans-t fer un t il the level becomes inadequate (too low for maintaining natural circulation or virtually dry with forced circulation).

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NUCLEAR POWER GENERATION DIYlSION TECHNICAL DOCUMENT 74-1122038-00 In summary, the operator can control primary to secondary heat t rans fe r after reactor trip by controlling two major parameters on the secondary side (assuming the capability of the reactor coolant to trans po rt core heat to the steam generators remains intact). The operator can increase heat transfer by reducing stean pressure or by raising s t ean generator level. He can decrease heat trans fer by allowing the steam generator pressure to increase.

FOOTNOTE Equations la and 2a have been simplified to show the general heat trans fer process. To be complete additional heat transfer terms would have to be included. All of the water that flows through the reactor coolant system loops does not flow through the core and get all the way to the steam generators. Some flow is let down to the makeup system, some goes to the pressurizer spray, and there is some "l e ak age" through spaces in the internals. This amount of flow is small and it has been ignored for these equations. Also, all the heat of the core does not go to the stean generators ; some of it is lost through the piping to the reactor building or through the le td own water. But this amount of heat is small compared to the total amount and it has been neglected. Heat is also added by reactor coolant pumps (as in plant heatup to power operation), but it is small compared to core heat when the reactor is at power (but the reactor coolant pumps are a rela t ively large heat source after trip or at low power).

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Control of heat transfer requires control of all the parameters in these two equations. Some are fixed by design or properties of fluids; the remainder can be influenced by the operator. The general methods of heat transfer control are discussed next.

r s Control of Heat Transfer The preferred way of removing heat from the core is to trans fe r the heat to the reactor coolant and then transfer the reactor coolant heat to the secondary fluid in the steam generators . Steam genera-tor heat removal is controlled by adjusting steam pressure and feed-

' water. To keep the core-to-steam generator heat trans fe r in balance A the heat removal rate from the steam generators must be equal to the heat ge nera t ion rate ef the core. In order to balance the heat removal two very basic conditions must be satisfied: 1) There must be enough liquid reactor coolant in the vessel and piping to trans-fer the heat to the steam generators, and 2) the steam generator pressure and level ( feedwate r flow rate) must be balanced at the correct heat removal rate. Figure 1 illustrates these fundamental s_ methods of heat trans fe r control. Figure 1 also shows the controls that the operator can use to change heat transfer.

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BABCOCK & WILCOX NUCLEAR POWit GENERATION DIVISION Numset TECHNICAL DOCUMENT 74- 122038-00 The five fundamental functions of heat transfer control are:

- Reactivity control (core heat output control)

- Reactor coolant pressure control

- Reactor coolant inventory control

- Steam generator pressure control

- Stean generator inventory control khen an abnormal transient occurs, one or more of these five func-tions will be out of control. It is the operator's job to determine which are out of control and to make corrections to restore the righ t heat transfer balance so that. the core heat can be removed by the steam generators.

1. Reactivity control - Reactivity control is usually taken care of automatically by ICS rod control or by reactor trip.

Reactor trip lowers the core heat output to the decay heat level.

2. Reactor Coolant Inventory Control - The link between the core and the steam generator is the reactor coolant. It is the

)

fluid wh ich t rans port s the heat. To do its job best the coolant should be in a liquid state, that is, s ubcoo led .

(Discussion of subcooling is given in Addendum A.)

3. Reactor Coolant Pressure Control - The reactor coolant system f ,

is pressurized to keep the reactor coolant in a liquid state, i.e. RCS poressure > saturation pressure.

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4. Steam Generator Inventory control - The water-steam inventory is the heat transfer fluid which removes the heat from the reactor c oola.n t . In order for it to remove heat at the correct rate, the amount of fluid and its flow rate through the steam generator must be controlled.

s

5. Steam Generator Pressure Control - The wa te r temperature of the reactor coolant is best controlled by controlling the pressure of the steau generator. In combination with reactor coolant pressure control, steam generator pressure control will maintain 1

the reactor coolant in a subcooled liquid state.

Each one of these control functions are discussed individually A as the'y relate to heat transfer.

Steam Generator Pressure Control Heat transfer from the reactor coolant to the steam generators goes to both the stean and water in the generator. After reactor trip the steam and feedwater in the generator are saturated and changes

- of stean pressure will cause a direct change in the saturation temperature of the steam and water. A review of the saturated t

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NUCLEAR POWER oENEGAtlON Ofvl3 TON TECHNICAL DOCUMENT 7'- n 22058-oo water and steam properties will show how much the steam and water tempe rature will be changed by increasing and decreasing steam pressure. There are situations where the operator controls the steam pres sure manually using the turbine bypass valves or the atmospheric dump valves. When the steam pressure is lowered, the heat t rans fer from the reactor coolant to the steam generator in-creases because the steam and water in the steam generator become a colder heat sink causing more heat to flow away from the reactor coolant. Two reasons combine to create the colder heat sink:

f irs t, the saturation temperature of the stean and water is reduced by lowering the steam pressure, which causes the rate of boiloff to increase. The increased boiloff takes away more heat. Second, the increased boilof f requires more feedwate r flow to be added to main-tain level. The feedwa ter inlet tempe rature is colder than the water already in the steam generator, thus its addition contributes to the colder heat sink. Because a colder seconda ry heat sink exists, the primary side temperature will drop as heat is trans-ferred.

Stean pressure can be lowered in two ways:

- By opening the steam line and releasing steam (turbine bypass, stean line break, atmospheric dump valves, stean to EFW pump turbine).

- By spraying Emergency Feedwater into the steam space and condensing it. This is similar to the way pres-surizer pressure is reduced by the pressurizer spray. /

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BABCOCK & WILCOX NuusER HUCtEAR POWER GENERAfloN Divi $loN TECHNICAL DOCUMENT 74-1122058-00 Steam pressure can also increase; but normally it will only increase from the operating condition to the reactor trip condition where it will be limited by the steam safeties or by the turbine bypass val-ves, so the e f fect on reactor coolant tempe ratur e is small. But if r

steam pres s ure is initially low because of a failure, for example a s

s tean line break, the subsequent increase in reactor coolant tempe rature could be much larger when the steam 'oreak is isolated.

After isolation, the reactor coolant adds heat to the generator and causes the steam pressure to increase. Without opera tor action, the s tean pres sur e would increase to the TBV or MSSV se t po int . The ope ra tor can limit the increase in reactor coolant temperature under r

these conditions by lowering the turbine bypass valve se t point and A.

keeping steam pressure low.

Steam Generator Inventory Control Heat transfer from the reactor coolant goes to both the steam and the fe edwa t e r in the secondary side of the s tean generators. When changes of feedwa t er flow or steam pressure occur, the volumes occu-pied by the steau or water will change and the heat trans fe r will change. For example, when the volume of water increases, it occu-pies space fonnerly occupied by steam, so the volume of steam has to

( decrease. This changes the relative amounts of OTSG tube surface area covered by water and steam. Water has a greater heat capacity

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than steam does thus it is a better heat sink for the reactor coolant than stean is. Simply stated there are more pounds of water DATE: 8-20-82 PAGE 26

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BABCOCK & WILCOX NUCLEAR POWEt GENERAfloN OlvlSION TECHNICAL DOCUMENT 7'- 122o58-oo in a cubic foot to absorb hect than there are of steam. If the l

water inventory increases, then the generato r will become a better heat sink for the reactor coolant; but if the water inventory decreases or is lost, the generator will lose some or all of its ability to absorb heat from the reactor coolant.

For example, after trip when the core heat is nearly cons tant, if the water level in the steam generator is raised rapidly without I

changing stean pressure, the reactor coolant temperature will drop and stay low until the water inventory reaches a new level and that level is held (i.e., feedwater flowrate red uced ) . Once the new level is fixed, the reactor coolant will reheat and temperatures will return close to their former values.

This cooling effect of feedwater is caused by the inlet feedwater t empe ra tur e , which is colder than the general temperature of the bulk of the fluid in the steam generator. The inlet feedwater temperature allows a colder heat sink to be established in the steam genera tor.

The stean ge ne ra tor level can, however, be increased slowly after trip without a large drop of reactor coolant temperature by con-trolling the rate of addition of feedwater.

DATE: 8-20-82 PAGE 27

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BABCOCK & WILCOX sumsEn NUCLEAR PoWEn GENERAtlON Divi $lON TECHNICAL DOCUMENT 7'-1122038-o0 Too much inventory can also be the result of overfeeding with the Emergency Feedwater System. Even though its flow rate is lower, Emergency Feedwater will have a proportionally larger cooling effect on reactor coolant than main feedwater because:

r s a) it comes on when the reactor is tripped and core heat is lowest, b) it is colder (Tinlet feedwater is less), and c) it has a steam pressure reduction ef fect that main feedwater does not normally have.

r On the other hand, if steam generator inventory is too low (insuffi-

s. cient feedwater or loss of feedwater can lower the water level), the reduced heat sink will not allow the reactor coolant to transfer all of its heat to the steam generator. When the steam generator's heat sink is red uc ed , the reactor coolant must retain more of the core heat and it will heat up.

For example, if all feedwa ter is lost, the water in the ge nera to r 4 will boil away and only steam will remain to remove heat. But because the steau does not have enough heat capacity, the reactor coolant must retain the core heat and the reactor coolant DATE: 8-20-82 PAGE 28

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BABCOCK & WILCOX Numsen NUCLEAR PowEt GENERATION DIVI 5 ton TECHNICAL DOCUMENT 74- 22o38-oo temperatures will increase. When all feedwate r is lost, the reactor coolant pressure will increase to the ERV se tpoint and the reactor coolant will eventually become saturated as the core continues to add heat. The steam remaining in the ge ne ra tor will flow out through the steam lines and steam pressure will drop; loss of the steau eliminates the heat sink of the steam generators altogether.

Finally, another part of steam generator inventory control is feed-wa t e r t empe ra tur e . The heat sink of the generato rs will be affected by an abnormally low feedwater temperature. A reduction of feed-water heating ste am or loss of a feedwater heater will cause reactor coolant temperature to decrease. Usually ICS operation will stabi-lize the pl an t , but the decreased feed t empe ra ture will cause a change in the heat sink and an increase of heat transfer from the reactor coolant.

The operator should ensure the rate of feedwater addition is control-led properly to maintain the steam generator inventory. Level me asur ement s in the steam generator downtomer give a good indication of the steam generator inventory for control.

Reactor Ceolant Inventory Control Reactor coolant heat transfer can be affected by changes in the mass of fluid in the reactor coolant system or by changes in the f

density of the reactor coolant. g

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( NucteAn powen ceNenATION OlvaSION M-1122058-00 TECHNICAL DOCUMENT Several ways exist to vary the mass of reactor coolant: LOCA or small break , and changes in HPI or makeup, RC pump seal injection, seal return, and letdown. Several ways also exist to vary the den-sity . of the reactor coolant. As shown by the previous discussions g of steam generator pressure and inventory control, changes of the rate of heat trans fer from the reactor coolant to the steam gener-ator can cause the reactor coolant to cool down when the steam generators remove too much heat (low steam pressure, too much fe ed-water); or the reactor coolant can heat up when the steam generators don't remove enough heat (not enough fe ed wa t e r) . These ef fect s cause density changes in the reactor coolant; the coolant contracts g or expands accordingly.

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Regardless of the cause, changes in inventory in the reactor coolant system have two effects:

1) A loss of mass can affect the ability of the reactor coolant to transport heat from the core to the steam generators. If the RC pumps are not running, steam can collect in the hot legs and

{ block natural circulation. When circulation and heat transport I

stops, then the steam generator tempera ture will not " set" the t empe ra ture of the reactor coolant; Tcold will not change when Ts a t-SG ch ange s.

DATE: 8-20-82 PAGE 30

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BABCOCK & WILCOX NUMB ER NUCLEAR POWER GENERATION DIVISION 74-1122058-o0 TECHNICAL DOCUMENT If the mass of the reactor coolant system continues to decrease and the core is mostly covered by stean, the mass of the RC will not provide a sufficient heat sink and the core will retain the heat and heatup. Fuel failures can result if this situation is not corrected. (

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2) A change of mass or density can af fect the ability of the pres-surizer to provide pressure control of the reactor coolant systen (this will be discussed next under Reactor Coolant Pres-sure Control).

Operator control of reactor coolant invento ry requires the ability to balance mass increases or decreases by adding water with makeup or ECC systens or removing mass with the le td own . Control of re-actor coolant density changes requires control of the steam genera-tor pressure and inventory.

The inventory of the reactor coolant system cannot be measured directly. But the operator has two indic a t ions to determine if the inventory is sufficient for core cooling. Pressurizer level is an accurate me asur e of the inventory when the reactor coolant is sub-cooled (except for a rare pos,ibility when free hydrogen gas may exist in the loops; this condi tion will likely exist only after fuel failures caused by uncovering of the core). The other measure is

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BABCOCK & WILCOX NuusEn NUCLEAR POWER GENERADON D!Vi$loM TECHNICAL DOCUMENT 74-1122058-00 the incore thermocouples; if these read subcooled or saturation teinpe ra tur e , then enough mass exists in the reactor vessel to cover and cool the core. But the incore thermocouples will not show if the loops are full.

r Reactor Coolant Pressure Control Reactor coolant pressure control is required to keep the reactor coolant s ub cooled so that the coolant is in the best state to trans-fer heat from the core to the steam generators. For all cases of reactor operation except LOCA's, RCS pressure control is provided by f

the pressurizer. (Reactor coolant pressure control is different for

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LOCA's and small breaks than for other plant co ndi t io ns . It is dis-cussed in detail in Appendix F.) Use of pressurizer heaters and spray is the usual way of increasing and decreasing RCS pressure when a steam and water interface exists in the pressurizer. The pur-pose of the heaters is to maintain the reactor coolant in a sub-l cooled condition by maintaining RCS pressure greater than saturation L

pres sur e; the spray retards pressure increases to limit operation of s

the pressurizer relief and safety valves. Neither the heaters nor spray have enough capacity to prevent large abrupt pressure changes, but t.h ey can moderste small changes. As a backup, the ERV can be used to reduce pressure but it is not as de s irab le to use as the spray because it relieves to the pressurizer quench tank. Frequent use of the PORV can result in failure of the quench tank rupture disk.

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BABCOCK & WILCOX Numsta NUCLEAR POWit GENERATION DIVI $ ION 7'-ti22058-00 TECHNICAL DOCUMENT RCS pressure control by the pressurizer can be lost in two ways:

1) The steam-water interface in the pressurizer can be lost either by draining the pressurizer or if the pressurizer fills solid with water

2) The heaters and spray can fail.

Each of these is discussed below:

Draining the Pressurizer:

If the pres s urize r level drops su f ficiently to uncover the heaters, the heaters cannot provide pressure control because no water is available to be boiled by the heaters to create steam. (

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If the pressurizer drains completely, RCS pressure will then be controlled by the highest fluid tempe ratur e in the system. When the pressurizer drains, the reactor coolant system pressure will decrease to the saturation condition co rres po nding to the hottest point in the system, which could initially be the hot leg containing the pres sur ize r surge line, the other hot leg, or the core outlet.

In ef fect, the hottest point becomes a pressurizer,

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BWNP-20007 (6-76) 1 BABCOCK & WILCOX " E" l NUCLEAR POWER GENERATION DIVISION 74-1122058-00 TECHNICAL. DOCUMENT The operator should not confuse the above losses of RCS pressure control with the normal pressure responses during plant transients.

Any transient which rapidly decreases pressurizer level will cause a concur rent drop in RCS pressure. The rapid decrease in level (except for a LOCA) is caused by a temperature decrease in the RCS.

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The drop in RCS pressure is caused by the expansion of the pressurizer steam space. Additional coolant will flash to steam in the pr es sur ize r as the steam volume expands, which will reduce the rate of pressure decrease. This flashing of steam, however, has a cooling ef feet on the remaining coolant in the pressurizer since the latent heat of vaporization is required to convert saturated water to s t e an . These transients are those rapid enough so that the k

pressurizer heaters can not keep up with this cooling ef fect.

Filling the Pressurizer:

Any transient wh ich rapidly increases pressurizer level will cause a concurrent rise in RCS pressure initially. This rise in RCS pres-sure is usually followed by a decrease in RCS pressure unless the pressurizer heaters can maintain pressure. The rapid increase in A.

Icve l is usually caused by a temperature increase in the RCS. The initial rise in RCS pressure is caused by the compression of the stean volume in the pressurizer, since the insurge acts like a piston. Three things happen to reduce this initial pressure DATE:

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B ABCOCK & WILCOX OI NL, CLEAR PoWis GENERAiloN OlvilloN 7'-1122038-00 TECHNICAL DOCUMENT

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1 increase: The spray effects start to show up; some of the steam condenses on the spray droplets (releasing the latent heat of condensation) and the cooler water which entered the bottom of the pres sur ize r starts to mix with the hotter water, which in turn, increases the condensing of steam. (In addition the spray bypass flow contribu tes some cooling after main spray stops, which is 2

normally balanced by the pressurizer heaters under steady state condi t ions. )

This cooling of the pressurizer may exceed the capacity of the pressurizer heaters to maintain pressure, so that the initial increase in RCS pressure is followed by a large decrease in RCS pressure even though pressurizer level is now stable. The operator can ant ic ipa te this above situation- and manually activate the

! pressurize heaters.

1 If the pres sur ize r fills with water, the spray cannot be ef fect ive for depressurizing because the steam space is lost. When the pres sur ize r filis , the reactor coolant systen may or may not . lose e

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The operator should not confuse the above losses of RCS pressure control with the normal pressure res ponses during plant transients.

Any transient which rapidly decreases pressurizer level will cause a c oncu r rent drop in RCS pressure. The rapid decrease in level (except for a LOCA) is caused by a temperature decrease in the RCS.

s The drop in RCS pressure is caused by the expansion of the pressurizer steam space. Additional coolant will flash to steam in the pres sur ize r as the steam volume expands, which will reduce the rate of pressure decrease. This flashing of steam, however, has a c ooling ef feet on the remaining coolant in the pressurizer since the latent heat of vaporization is required to convert saturated water to s t e an . These transients are those rapid enough so that the s

pressurizer heaters can not keep up with this cooling ef fect, f

Filling the Pressurizer:

Any transient wh ich rapidly increases pres sur izer level will cause a concurrent rise in RCS pressure initially. This rise in RCS pres-sure is usually f. ' ' oe 1 by a decrease in RCS pressure unless the pressurizer UP r - an maintain pressure. The rapid increase in m

leve l is us.,_1y .ede by a temperature increase in the RCS. The initial rise in RCS pressore is caused by the compres s ion of the s tean volume in the pressurizer, since the insurge acts like a piston. Three things happen to reduce this initial pressure DATE:

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BABCOCK & WILCOX NUCLEAR POWER GENERAilON DIYl$10N TECHNICAL DOCUMENT 7'+- 1122058-00 increase: The spray effects start ' to ' show up; some of. the steam c ondenses on the spray droplets (releasing the latent heat of j condensation) and the cooler water which entered the bottom of the pres sur izer starts to mix with the hotter water, which in turn, increases the condensing of steam. (In addition the spray bypass flow contribu tes some cooling after main spray stops, which is normally balanced by the pressurizer heaters under steady state c ondi tions. )

This cooling of the pressurizer may exceed the capacity of the pressurizer heaters to maintain pressure, so that the initial increase in RCS pressure is followed by a large decrease in RCS

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pressure even though pressurizer level is now stable. The opera tor can anticipate this above situation and manually activate the pressurize heaters.

If the pres sur ize r fills with water, the spray cannot be ef fect ive for depressurizing because the steam space is lost. When the '

pres sur ize r fil ls , the reactor coolant systen may or may not lose

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subcooling and become saturated depending on what caused it to fill.

If the filling was caused by HPI or makeup and the steam genera to r is still removing heat, then the RCS will stay subcooled because the makeup (HPI) pumps will cause the pressure to stay at the ERV setpoint and the steam generator will keep the temperature s

controlled. If the filling was caused by heatup and swell because the steam generators were not removing enough heat, then the system may become saturated because the heat from the core will go only into the reactor coolant and not out the steam generators.

When the pressurizer fills, either because of heating the reacto r coolant or because of too much HPI, the water will be lost through k

the ERV and pr es sur ize r safety valves. This loss is considered to be a LOCA, even if the action was deliberately done.

Failure of Heaters and/or Spray:

A failure of the spray and heaterr in the pressurizer control system can also cause a loss of pressure control. If the spray fails on and cannot be turned off, the system will depressurize. Depressuri-L zation may also occur if the heaters fail in the "o f f" mode . The reverse is not true; failure of the spray in the "o f f" mode will only limit the ability to depressurize. Unless something else happens to the plant, pressure increases and decreases will not DATE: 8-20-82 PAGE

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BABCOCK & WILCOX NUCLEAR POWEA GENERATION DIVISION TECHNICAL DOCUMENT 74-1 22o58-o0 occur. If the heaters fail "on", pressure increases will not occur because the spray will operate to provide a balance. However, if the spray . is not working then the heaters can cause the system to pres surize and cause coolant (steam) to be lost through the ERV and the pressurizer safety valves; subcooling will not be lost as long as water covers the heaters. When only stean covers the heaters they will no longer raise pressure and subcooling can gradually drop. If the heaters fail "on" when they are uncovered, no water exists to cool them and they will burn out.

Reactivity Control Reactivity control is usually taken care of automatically by ICS rod control or by reactor trip. Reactor trip lowers the core heat out-put to the decay heat level. The operator must verify rod insertion and decreasing reactor power to ensure the reactivity control sy-stens funct ion properly. After the trip no more heat trans fe r control can be achieved by use of the rods, unless the rods did not fully insert. If one or more rods are s tuc k out after trip the operator should manually trip them. If one or more rods remain s tuc k out the operator should begin emerge ncy boration and a reactivity balance calculation should be pe r formed to ensure a shutdown margin in excess of 1% Ak/k is achieved.

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( NUCLEAR POWER oENERATION Olvl51oM

( TECHNICAL DOCUMENT 74-1122058-00 Summary The preceding discussion introduced the concept of reactor-steam generator heat transfer and the balance that heat transfer must 7 h av e . Wh en an imbalance of heat trans fe r oc cu r s , its effects will often be transmitted throughout the steam and reactor coolant s

systans. 'he purpose of unde rs tanding heat trans fe r is to unde rs tand its ef fects so the operator can diagnose what has gone wrong and correct it. An understanding of the major influences on reactor-steam ge nerato r heat transfer control (reactor coolant systan inve ntory control, reactor coolant pressure control, steam 7 genera tor pressure control, steam generator inventory control, and react ivi ty control) will allow the operator to focus on achiev ing controlled heat transfer and stable plant conditions without necessitating the identification of s peci f ic failures. Thus, an unde rs t anding of the principles of heat transfer and the control

methods pe nni t s a direct and ef ficient approach to ab normal transient diagnosis and correction.

The ef fects of changing one of the controls will nearly always cause changes in other parts of the system and the re fore will require other controls to be changed to balance heat trans fe r. The controls are interdependent because they affect total heat trans fer from core to stean outlet.

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BABCOCK & WILCOX "" I" NUCLEAR POWER GENERAflON OlVISION -

TECHNICAL DOCUMENT 74-i 22038-oo Core cooling with the steam generator can occur as long as two things exist:

The reactor coolant can transport the heat. The best way to do this is with subcooled liquid. Reactor Coolant In-ventory and Pressure Control contribute towards this.

The heat removal is controlled by the steam generator.

Steau Generator Inventory Control and Pressure Control aid this.

Usually an abnonnal transient will be caused by a failure of one or more of the heat transfer controls. The understanding of the con-trol influences allows the operator the freedom of two approaches to abnormal transient correction:

1. He can treat the symptoms by manipul a t ing equipment to regain heat tr nsfer control without knowing exactly which equipment has f ailed . Consequently, proper heat trans fer can be restored quicker and more accurately than if the operator had to hunt fo r the equipment failure. In some instances, treating the symptoms will also uncover the failed equipment.

2. He can use these control f ailures as symptoms of poor heat transfer to discover the equipment that has failed and by doing so , isolate it, remove it from service, or repair the

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equipment.

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( NUCLEAR POwlt GENERATION DIVISION TECHNICAL DOCUMENT 74- 22058-00

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Unde rs t anding the influence each of these controls has on overall heat transfer will also give an understanding of what the outcome of an action is. All operator actions will have some consequence to heat trans fe r and a knowledge of the heat trans fe r will allow e

judgenents to be made about the general effects.

s Table 1 is a summary of the previous disc u s s ion. Like all summar-ies, material has been condensed. When that happens, informa t ion has been left out. The table should be used only to provide an overview.

The next section builds on the info rmat ion about heat trans fe r and s

extends those principles into a disciplined approach to accident diagnos is and recovery.

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Figure 1 FUt1DAMENTAL METHODS OF HEAT TRANSFER CONTROL SPRAY ERV REACTOR s PRESSURE STEAM CONTROL

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REACTIVITY

]

3 CONTROL

(_) HEATERS STEAM GENERATOR , i g PRESSURE 1' A L

CONTROL o

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t

~ 6 N

J

- stx!

FEEDWATER /

)I (/\

STEAM \ /

GENERATORT INVENTORY

\O LETDOWN MAKEUP (HPI)

REACTOR INVENTORY CONTROL i

-1122058-00

l TABLE 1 HOW FAILURES AFFECTING HEAT TRANSFER CAN AFFECT REACTOR OPERATION FAILURE EQUIPMENT WHICH MIGHT HAVE FAILED EFFCOTS ON REACTOR-STEfJt GfNERATOR CONTROL PRINCIPLE Steam Generator Pressure Low Steam Release - T Drops; Reactor Subcooling increases; Retctor Coolant

- Turbine Valves Open S$ finks;PressurizarMayDrain;IfPressurizerDrains,Then

- Turbine Bypass Open Reactor Coolant Will Saturate.

- Steam Safeties Open

- Other Steam Extraction Open

- Steam Piping Break Steam Condensation -

- Emergency feedwater On Steam Generator Inventory High Level - Feedwater Control Valves Open or Don't Close After Trip - Steam Generator Level Increases; Superheat Lost; 7 Drops ; i (Too Much Feedwater) - Feedwater Pump Overspeed Reactor Subcooling increases; Reactor Coolant Shri$fs; Water '

Overcooling - ICS Controls; Power to ICS Can Enter Steam Lines; MFW Will Probably Not Cause Pressurizer l

- Operator Error in Manual Draining. I

- Emergency Feedwater Not Controlled

- If Emergency feedwater It Uncontrolled After Trip, The j Overcooling Will Be Enough To Drain The Pressurizer; Reactor Coolant Will Satirate. '

Low or No Level - Loss of Feed Cacause of Many Possible Failures In feedwater - Steam Generator Level Lost; T Increases; Pressurizer fills; (Not Enough Feedwater) And Condensate System Reactor Subcooling Lost; PresUrizer Relieves Through Safeties Overheating - Feedline Break (LOCA).

Reactor Coolant Inventory Lcw - Loss of Coolant - Pressurizer May Orain; Reactor Coolant Will Saturate; If In

- Failure of Letdown, Makeup Seal Injection, HPI Natural Circulation Flow to Steam Generators Iby 8e Blocked

- Overcooling (Too Much Feedwater, Low Steam Pressure) By Steam In Hot Legs.

High - Failure of Letdown, Makeup, Seal Injection, HPI - If HPI or !bkeup Failure Fills the Pressurizer, the RCS Will Co

- Overheating (Not Enough Feedwater) to 2S00 PSI but Will Remain Subcooled.

- If Overheating Failure Fills the Pressurizer, the RCS Will Go to 2S00 PSI and tre RCS Temperature Will Increase; Subcooling Will Be Lost.

- In Either Case, a LOCA Through the Pressurizer Safeties Will Occur.

Reactor Coolant Pressure Low PCS Pre ur n 1 E uipment - If RCS Pressure Orops Too Low, Subcooling Will Be Lost.

- Heaters Fall Off Loss of Reactor Coolant Inventory Control (Low)

High RCS Pressure Control Equipment - RCS Pressure will Increase to 2S00 PS!; Coolant Will Be Lost

- Heaters fail On, and

- Sprays fail Off until the Heaters uncover.

Loss of Reactor Inventory Control (High) e

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NUCitAt POwta GENERATON Otvl5CN TECHNICAL DOCUMENT 74- 122058-00 k'

ADDENDUM A (SUBC00 LED, SATURATED, SUPERHEATED WATER)

The state (solid, liquid or gas phase) of the water in the reactor coolant system or the stean system is determined by the pres sure and temperature F conditions which exist. The terms subcooled , saturated, and supe rheated

( are normally used within operating procedures. These- terms mean the following:

Subcooled : Water can exist only in the liquid state.

Satura' + If heat is added to subcooled water, a temperature, fo r the existing pressure, will be reach ed where the r water can exist either as a liquid or as a gas t (steam). At this point, the liquid is called satu-ated water and the gas is called saturated steam.

Either the liquid and s tean state both can exist at this temperature and pressure. Heat must be added to saturated water to change it to saturated steam.

Heat must also be removed from saturated steam to change it to saturated water. The heat required to s make the change is called the latent heat of vapo riza tion for heat added and the latent heat of condensation for heat removed.

Su pe rh ea ted : Water can exist only in a gaseou s or steam phase.

This phase can be distinguished from saturated con-ditions because the temperature will be higher than the saturation temperature for the existing pressure.

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BABCOCK & WILCOX NUMBE R NUCLEAR POWER GENERATION DIYl5K.N 74- 20s8-00 TECHNICAL DOCUMENT The normal state of the steam coming out of the steam generator is superheated during power operation and saturated af ter trip.

The state of the reactor coolant can be determined by watching the RCS pressure and temperature on a pressure-temperature diagram (see below):

SUBC00 LED L

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SATURATION LINE \

P

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g_ SUPERHEATED T -

P-T conditions which are to the left and above the saturation line are in the subcooled region, and P-T conditions to the right and below the satura-tion line are in the superheated region.

Subcooling Subcooled conditions are maintained in the reactor coolant (except pressurizer) during normal operation. During a reactor transient the operator's primary objective is to maintain the reactor coolant subcooled.

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When subcooled:

1. The prima ry loops and reacrer vessel are solid water and a water level is present within the pressurizer.

2. The pressuricer wa ter level is a measurement of RCS inventory. The g inventory can be controlled by regulation of pressurizer level by q

the MU and/or HPI system an.1 letdown. (NOTE: A special case can exist when the reactor coola.nt is subcooled and a water level is in the pressurizer but the loops are not full. In that case pressuri-zer level is not a true measurement of inve nto ry . That condition is when there is a large amount of free (nor. aqueous) gases in the loop. The production of H2 from the zr-water reaction is necessary 7 for a large amount of such gases in the RCS loop. Since this would g be an uncommon event, reliance on pres surizer level is usually acceptable when the reactor coolant is subcooled.)

3. The reactor coolant is liquid and is ide al fo r heat removal from the core and heat transport to the steam generator by either forced or natural circulation.

4. RC pres sur e can be maintained by the pres sur ize r and can be regu-

. lated by using normal procedures and equipment (sprays and h e a t e rs ) .

5. RC temperature can be controlled by the secondary system (with feed-water available) by adjusting feedwater flow and steam pressure.

S Subcooling should be checked in all parts of the loop. The operator should check Thot, Te old and the incore the rmocou ple s in both loops. Only DATE: 8-20-82 PAGE 43

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The reactor coolant is too close to saturation if the subcooling margin decreases to below about 20 to 30F. This subcooling margin is explained in more detail in Chapter B.

HPI Subcooling Rule: Two HPI pumps chould be run at full capacity when:

e The ESAS is actuated and the HP1 is auto-matically started or e The reactor coolant subcooling margin is lost and the HPI is manually started .

Saturation A loss of subcooling can occur when the pressurizer drains or when filled solid (if the pres surize r is solid because of HPI and adequate core cooling is

p. ov id ed by the steam generators or HPI flow then the Reactot Coolant may stay s ub c ooled) .

A loss of subcooling can be caused by an overheating or overcooling transient or a loss of reactor coolant.

Satur ated conditions can exist in isolated pockets of the loop (i.e.,

f within one or both hot leg pipes and not in cold leg pipes) or within the system as a whole, as would be the case during a major LOCA. Th e re fo re ,

/

M k

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temperatures should be checked in the hot legs of both loops. When the RCS is saturated:

1. The reactor coolant temperature and pressure will not show whether the saturated fluid is liquid or gas (steam).

f

2. Void s ( s t ean bubbles or pockets) can exist within the primary system.

3. The pres sur ize r water level indication is not a true measurement of reactor coolant inventory.

4. If the RC pumps are off, a loss of natural circulation may occur bec ause steam voids can form at the top of the hot legs and block water flow.

r

5. No rmal pressure control by the pressurizer has been lost. The RCS s

hot leg loops, which have a steam bubble at the top, now work as a pr es sur ize r , RC pressure will be controlled by the highest fluid temperature in the system. The amount of steam can change because of steau condensation by the stean genera to rs , by addition of cold HPI water to compress the steam, or by loss of steam generator heat removal.

L Under ideal conditions, subcooling should exist in all parts of the reactor coolant loop to be able to t rans port heat from the core to the stean ge ne ra to rs . However, given the proper conditions, the s t ea:n generators can remove heat when the reactor coolant is saturated.

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For all event s , except a LOCA or a sustained total loss of secondary fluid, saturated conditions should be a temporary ef fect. For example, if steam generator overcooling causes the pressurizer to drain, saturation will occur, but HPI will start and restore the reactor coolant to -a subcooled state.

k' Superheating l

1 Superheated reactor coolant conditions are to the right and below the satu-ration line of the P-T diagram. Superheated steam results when the core is uncovered. Heat from the re is passed to the steam and its tempera-ture rises above saturation. When the reactor coolant is superheated the core is cooled by stean. Steam cannot remove enough heat to prevent the core and clad from heating up. Fuel failure may result. Superheated stean indicates Inadequate Core Cooling (ICC) .

The only accurate measure of temperature when superheated conditions exist is the incore the rmo cou ple s , and they should be used along with hot leg pressure to determine the amount of superheating.

l l

l Superheat Rule: The inadequate core cooling l procedure must be used anytime superheated J

conditions exist in the RCS. See " Backup Cooling Methods" section for a discussion of

/

Inadequate Core Cooling.

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ADDENDUM B NATURAL CIRCULATION khen the reactor coolant pumps are tripped, forced circulation is lost and an alternate method of removing core decay heat must be found. The pre-ferred method is to transport this heat to the steam generators by natural circulation of the reactor coolant. Natdral circulation is pos sib le as long as the following requirements are met: 1) a heat source is available to produce warm (low density) water; 2) a heat sink is available to pro-duce cold (high density) water; 3) a flow path (loop) is available con-necting the warm and cold water; and 4) the cold water is above the warm water. Requirements 1, 2 and 3 are simple to understand. Decay heat in f

the core is the heat source, water on the secondary s ide of the steam

(

generators provides a heat sink, and the hot and cold legs connect the two. Requirement 4, "the cold water is above the warm water," involves a concept c alled thermal center. In reality, heat is trans ferred continu-ously as the water moves up through the core and again as it moves down through the steam ge ne ra to r. The thermal center is the point in the core l or the s t ean generator where the primary water is at ave rage temperature.

7 It can be used to represent the entire column of water in its " average" 5.

c o nd i t ions .

Thermal Center Definition

1. Core the nnal center: That elevation in the core which the reactor coolant may be considered to go from Tcold to Thot-DATE:

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2. Steam generator thermal center: That elevat iot. in the steam gener--

ator at which the reactor coolant may be considered to go from Thot to Teold-Requirement 4 for natural circulation can be met if the thermal center of the steam generator is above the thermal center of the core. This will put the " average" cold water above the " average" hot water, the cold water (more dense) will sink, the hot water (less dense) will rise and there will be circulation.

The rate of natural circulation (gpm) depends on the following things:

e The friction (resistance to flow) of the piping and components

around the primary loops: this is determined when the plant is designed and built; the operator has no control over it.

e The strength of the heat source: this depends on the available decay heat, which is a function of past power history and time since the reactor trip. It will, of course, decrease with time after trip. The operator has no control of this after trip except to make sure the reactor is shut down so that the only heat input is decay heat.

e The strength of the heat sink: the colder the heat sink is, the more it will be able to cool the primary coolant passing through the stean generator. This will make the water more dense and the natural circulation flowrate will increase. The operator can make the heat sink colder by 1) lowering seconda ry steam pressure h i

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(opening the turbine bypass or ADV's more), this will lower secon-dary saturation temperature wh ich will increase heat trans fer across the tubes; or 2) lower feedwater temperature ( for example, shift from main feedwa ter to emergency fe ed wa t e r) , this will I increase the heat transfer across the tubes by providing a larger k '

primary to secondary A T. (The EFW pumps start automatically upon loss of all RCP's) e Dif ference in height between the core thermal center and the steam generator thermal center: As the dif ference in height becomes la rge r the natural circulation flow will increase. The core thermal center is fixed, but the operator can control the steam

/

generator thennal center by two methods: 1) most of the heat trans-N- fer occurs in the violent boiling area just below the established seconda ry side water level. The re fo re , the operator can raise the thermal center by raising the steam generator water level; 2) the operator can add EFW at the top of the ge ne ra to r. This will put feedwater h igh in the generator and thereby raise the average heigh t ( thennal center) of heat removal. This only works while EFW is being added. If EFW is stopped, the thermal center will move i back down to just below the water level .

In summary, the natural circulation flowrate can be changed by changing the dif ference in temperature (density) between the hot water and the cold water or by changing the difference in height between the core thermal center and stean generator thermal center. This can be expressed in equa-tion fo rm a s :

DATE: I 8-20-82 PAGE ,

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NUCLEAR POWER GENERATION DIVISION 74- 2205840 TECHNICAL DOCUMENT APdriving head = hegg (pc -#H) where: APdriving head = available driving head for natural circulation hegg = distance between core thermal center and steam generator thermal center (ef fectis e height)'

pc = density of cold water at steam generator *.nermal center H = density of hot water at core thermal center This is shown graphically in Figure 2.

Natural Circulation (All Other Conditions Normal)

~

When the reactor coolant pumps are tripped, the operator should check two 1 Q

things to make sure natural circulation is be ing initiated properly.

First he should make sure the reactor coolant remains subcooled. If it does not he should make every e f fort to restore subcooling (the methods for doing this are discussed in Chapter C). Second, he should make sure-the thermal center is being raised in both steam generators. Normally, automatic equipment will start EFW and increase level to 50% on the operating range of each steam generator when the RC pumps trip. The operator should monitor this process while keeping the following in mind:  ;

l l l b^

l DATE: 8-20-82 PAGE 50

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BABCOCK & WILCOX NUMBER NUCLEAR POWER GENERAflON DIVI $10N TECHNICAL. DOCUMENT 74- n 22058-oo e As long as EFW is flowing at suf ficiently high rates into the top of the generator it is not neces sa ry to get a level in the genera-tor to have natural circulation. If the heat source (decay heat) is high enou gh , the EFW may come in and boil right off and go out

( as steam. This is acceptable; the thermal center is high and

( natural circulation will develop.

e With two EFW pumps running or with low decay heat levels it is likely that the reactor coolant will be ove rcooled and could drain the pressurizer even with proper automatic control. This is due to the fact that the au tomat ic control will provide essentially full EFW flow until the steam generator levels approach the level f s e t po int. If the pressurizer drains, subc ooling will be lost. As

( was pointed out in the heat transfer chapter, this will not happen if the rate of EFW flow is limited. The operator can do this by throttling EFW flow. After initiation of EFW the ope ra tor should wa tch stean pressure, pressurizer level, and cold leg temperatures.

If necessary, EFW should be throttled to prevent overcooling.

Guidelines fo r throttling EFW are discussed in the Best Methods chapter.

L e If EFW is not ava ilable natural circulation can be initiated using main fe ed wa t e r . Again, the level should be raised to 50% on the ope ra t ing range. This method is not pre fe rred because it takes longer (than EFW) to raise the thermal center and establish natural DATE:

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N circulation. By the time the level is high enough to get flow going there may be so much colder main feedwater in the gene rato r that overcooling cannot be prevented.

Ideally, main feedwater is best used for natural circulation if 1)

.[.-

the required steam generator level is established be fore the pumps t'

are tripped or 2) the steam generator level is established first by EFW.

Figure 3 shows how RCS temperature and pr e s s ur e , and steam generator temperature and pressure will vary during the transition to natural circulation. Approximate times for the trans ient are also included. f-g The times are approximate because the rate of recovery of the steam pres sur e depends on the amount of decay heat available. When s teady state is reach ed , the cold leg temperatures (Teold) vill be just about equal to the saturation temperature in the steam generators. The hot leg temperatures will increase as necessary to develop the driving head required fo r flow (b y developing a dens i ty ch ange between T h and Tc )-

l The best measures to use to see if natural circulation has started is l the cou pling be tween Tc and the steam generator tempe ra ture and the temperature dif ference between Th and Tc . When both Tn and T eare s ub-cooled, they should follow steam generator Tsat when it changes; the t empe ratur e dif ference between Th and Tc should not exceed 50-60F. If W

N 4

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BABCOCK & WILCOX NUM8ER NUCLEAR POWER GENERATION Olvl510N 7'-1122058-00 TECHNICAL. DOCUMENT Tc nly is subcooled and Th is saturated, natural circulation character-istics should be the same as if they are both s ubcoo led . Once natural c ircu la t ion is established and the higher steau generator levels are reached the operator's job is to make sure feedwat er is available to replace the stean generator water being boiled off removing decay heat A

and to keep the RCS subcooled.

Natural ci rcula t ion flow will regulate itself. That is, as the heat source (decay heat) decreases, the AT (T h - T) c will g down, and there will be less driving head available; the re fo re , flow will go down.

f

(

Natural Circulation - Abnormal Operation The discussion so far concerned expected or normal natural circulation conditions. That is, the RCS is subcooled, the level in both steam generators is 50% on the operate range, and both steam generators are being steaned. This section will discuss of f normal conditions:

1) natural circulation with one OTSG, 2) natural circulation with satu-rated RCS, and 3) recognition of loss of natural circulation.

4 One OTSG There may be times when an operator does not want to steam a generator (OTSC tube leak) or cannot steam a generator (steam line break and iso-lated generator is dry). If he is also in natural circulation he can expect the fo llowing :

1 DATE: PAGE 8-20-82 53

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k Teold on the operating generator will be equal to T sat in the operating s tean ge ne ra to r. Tcold in the iso la t ed generator will not be equal to T sat in the isola ted generator; it will probably be much colder being influenced by seal injection water tempera ture coming into the idle pumps. The level in the operating SG may have to be raised to maintain v

adequate natural circulation. Steady state ope ration under these conditions is stable and safe. Plant cooldown, however, is complica ted because the loop with the isolated generator will lag behind the s teaning ge ne ra to r . If there is water in the iso la t ed steam generato r it will become a heat source instead of a heat sink. In fact, the isola ted generator may add enough heat to cause the reactor coolant in the associated hot leg to flash to steam. If this happens, that hot leg will act as a pressurizer and slow down the depressurization during cooldown. This will also slow down the cooldown rate. The operator must careful ly watch subcooling in both loops under these conditions and make sure adequate subcooling margin is maintained by regulating the rate of cooldown with steam pressure control of the operating steam gene ra tor . l l Natural Circulation with a Saturated RCS

[N A subcooled reactor coolant system is the desired state, however, natu-ral circulation can remove core heat when the RCS is sa t ur a t ed . As 3 J

long as the four requirements of Part 1 of this addendum are net, i

1 l

M

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heat will be removed from the core and trans ferred to the steam generator.

The prob imi with saturated natural circulation is that the operator doesn't know how much of the reactor coolant is steam and how much is water (see discussion of saturation in Addendum A) . If the RCS is losing

[ inventory, steam will form in the hot legs and eventually stop natural cir-( culation flow (this is a violation for the requirement that a flow path exists connecting the hot water and the cold water).

This could also be violated by a large collection of noncondensible gases in top of the hot legs, however, such a collection would probably exist only following a core uncovery. At that point the operator would be using f

inadequate core cooling procedures.

(

Another fo rm of natural circulation could s t ill exist under these con-ditions called boiler-condenser cooling (boiling in the core and conden-sing in the stean generator) but it requires a higher steam generator level (95% on ope ra tor range). This method is discussed in detail in the Backup Cooling Methods chapter of these guidelines, k The point to remember is that primary inventory (mass) is unknown under saturated conditions and the re fo re , every ef fo rt should be made to keep the RCS subcooled.

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"'- 22058-00 TECHNICAL DOCUMENT Recognition of Loss of Natural Circulation A loss of natural circulation can occur for various reasons and several indications may be available. If the RCS is subcooled, a loss of natural circulation flow is more than likely a result of inadequate heat removal by the s tean generators. The thermal center in the steam generators may be too low. At low decay heat levels or during single loop cooldown, the SG levels may have to be raised above 50% on the operate range to induce or maintain natural circulation flow. When natural- circulation flow exists, Thot and the incore thermocouples will track together within N10F (although there will be some time lag due to long loop transport times).

In addition, Tcold and Tsat of the SG should track together.

(V The best single indication of a loss of natural circulation flow when the RCS _is subcooled is a divergence developing between the incore thermo-couples and Thot. When the flow is lost, the incore thermocouples will begiu a continual increase toward saturation. The rate will depend on the l decay heat level. Thot indications may also increase but can actually decrease and begin to converge with Teold. In any case, Thot will not i

l increase as rapidly as the incore thermocouples and the two indications will diverge. Another indication of loss of natural circulation is a "de-coupling" between Tsat in the SG and Teold. If Te old ceases to follow l Tsat natural circulation flow is lost. 3 l

l i 1

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When the RCS is saturated and natural circulation flow is lost, this d ive rgence may not develop significantly. The best indication of a loss of natural circulation flow when the RCS is saturated is a trend of incore thermocouple temperature vs. RCS pressure increasing along the saturation

(

curve. Flow can be lost due to low thermal centers in the SG's or "A

blockage due to voids in the RCS. When saturated, SG levels should be maintained at 95% on the operate range and full HPI flow should exist. If voids exist in the RCS, it is possible that boiler-condenser cooling was in progress. As the RCS refills , cooling in this manner is expected to be lost when the RCS liquid level increases above the SG tubes. However, in this case c ooling should be restored by continued refill and by following r

the actions specified in Section III.B of Part I (RCP bumps, reducing SG s

pressure, etc.).

~

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8-20-82 57

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _ J

Figure 2 ILLUSTRATION OF PARAMETERS CONTRIBUTING TO NATURAL l CIRCULATION DRIVING HEAD f

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Reactor Coolant and' Steam Outlet Temperature, F Reference Time Points (Seconds) Remarks l

1 0 RCP's trip; reactor trip.

I 2 60-90 T cold reache maximum value.

3 400 OTSG's at required level; RCS pressure at minimum value; recovery of RCS pressure begins.

l 3-4 >400 Steam pressure being restored by decay heat; TBV's shut.

4-5 >400 RCS pressure normal. OTSG pressure still low due to initial injection of EFW.

5 Depends on Steady state; TBV's begin relieving steam. Primary available AT 40F,

[ decay heat 4-1122058-00 l

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CIIAPTER B +

USE OF Tile P-T DIACRAM Introduction

( The previous chapter provided the fundamentals of heat t rans fe r control and also presented in formation about natural circulation, subcooling, saturation and supe rh ea t ing . These basics are the background information needed to diagnose transients and follow through with the correct operator actions. This chapter builds on that information.

The foundation for abnormal transient diagnosis and operator action is the r

reactor coolant pressure-temperature diagram (P-T) which is used to show

(

how changes of heat transfer af fect plant operation. Examples of reactor coolant systen pressure and temperature res ponse for normal trips are presented in this chapter. The response is also shown for a few selected abnonnal eve nt s. These examples show the dif ference between transients in which all systems and equipment function properly and those which have several failures.

s The P-T diagram is used to identify a transient " type". There are two general " types" of transients which cause the core to steam generator heat transfer to be abnonnal: overheating (inadequate heat trans fer), and over-cooling (excessive heat transfer). Changes of the amount of subcooling can also oc cu r for a number of reasons. The P-T diagram can be used to find out in general what may be wrong and can be used to narrow down the DATE: PAGE 8-2 0-82

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TECHNICAL DOCUMENT the number of possible failures. Obse rving the P-T diagram is the first

' step for abnormal transient diagnosis; the second step is to observe a few pertinent pa rame te rs associated with the " type" of transient to narrow down the possible failures.

The P-T diagram will be used to monitor actions taken by the operator to l

see if they are producing the right effects. When equipment failures ,

i cannot be found or cannot be fixed the P-T diagram can be used to follow the effects of operator corrections as the plant is controlled toward the best possible condition.

1 The diagram may also be used to ensure the plant has stabilized after a ,

i transient has been terminated.

(

l Description of the P-T Diagram Figure 8 shows the P-T diagram with information pertinent to normal power operation. The features of plant power operation that this diagram shows include the saturation line which applies to both primary and secondary water and steam conditions. Above and to the Icft of the saturation line I is the subcooled water region; below and to the right it is the su pe r-i heated steam region.

The reactor coolant information displayed also shows the RPS trip enve- l lope. Two small windows show the expected normal 100% reactor power opera-tion point. One point is based on Thot leg; the other point is based on ,

b

(

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{ TECHNICAL DOCUMENT 74-1122058-00 Teold leg. The s ize of the window is based on an expected approximate instrument error and also an allowance from the desired setting due to ICS control of minor plant variations. Actual " normal" power operation could be anywhere within this window and be acceptable. This window is a

" moving" window because Thot will change as plant power goes up and down.

(

Steam gene ra tor outlet pressure is shown as a line crossing the saturation line, and s t ean generator outlet temperature is also shown. The point where these two lines cross in the superheat region is the "no rm al" steam outlet ope ra t ing po int at power. The amount of supe rh ea t is shown as the difference betwen the saturation temperature (where the steam pressure g line meets the saturation curve) and the steam operating t em pe ra tur e . The amount of superheat will change when the power level changes. (Note: In an actual P-T di s pl ay , supe rh ea t will be shown only if steam temperature is measured. If steam temperature is calculated from steam pressure the P-T diagram will always show saturation temperature even at power.)

Figure 9 shows a P-T diagram for post-trip conditions. Most of the features of Figure 8 are also shown on Figure 9. The important dif ference between Figures 8 and 9 are a line that shows the subcooling margin from the sa t ur a t ion curve and the po s t-t r i p window. This subcooling margin line is to be used only to gauge the condition of the reactor coolant and not the stean generator fluid. Because the reactor coolant conditions DATE: PAGE 60 8-2 0-82

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around the loop can be different and because the conditions can be dif-ferent fr an one loop to the other this line must be compared to reactor coolant pressures and temperatures in the hot and cold legs of both loops.

The amount of subcooling margin was chosen based on the ability to accurately measure the reactor coolant temperatures and pressures (instru-ment er ro rs ) during degraded reactor building environment al conditions (LOCA or SLB). It also includes an extra SF to allow for temperature va riat ions from the point of measurement in the system. This gives assurance that when the reactor coolant is above the margin line, it is truly subcooled and has the ability to move the heat from the core to the generator.

.f If the sub coo li ng margin is lost, the assumption should be made that subcooling has been lost (ie., the RCS is at saturation). The subcooling rule that was given in Addendum A should be invoked (it is repeated here):

HPI Subcooline Rule Two llPI Pumps should be run at full capacity when:

The ESAS is actuated and the IIPI is automatically started or '

The reactor coolant subcooling margin is los t and the flPI is manually started.

A s

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BABCOCK & WILCOX suusEn NUctEAR POWER GENERAllON OlVISION TECHNICAL DOCUMENT 74- n22058-00 "Ih e P-T diagram can also be used to monitor and control HPI and RC pump operation, khen HPI is initiated, it can be throttled only when the s ubcoo ling margin is regained. In general, if the RC pumps have been t rip ped , they can be restarted anytime the subcooling margin is regained f and OTSG 1evel e xis t s (i.e., heat sink available). Exact details of HPI and RC pump control are given in (Chapter E, entiled "Best Methods for Equipment Operation".

Figure 9 also shows a " post-trip" ope ra t ing window. The " post trip window" is the five sided polygon of Figure 9 with upper and lower RCS pressure boundaries of 2400 and 1700 psig respectively with right and left temperature boundaries of 619F and 542F respectively. The fifth side is a k po r t ion of the "s ub c ooled margin line". This window has been drawn to show were the reactor coolant pressure and temperature should end up after reactor and turbine trip. The size of the window has been compiled from a review of several actual reactor trips (plus computer simulations) with and wi thou t equipment failures; its size is not exact and it is pos s ible for a trip ( wi th minor failures) to end slightly outside the window and still have a stable plant. Some judgement will have to be w applied. However, this window gives a good first basis for determining if the plant is ope ra t ing correctly after trip. If the reactor coolant system pressure and temperature move out s ide the window after trip and do not return in a fairly short time (about 2 to 3 minutes), then an abnormal transient is in progress and operator co r rect ive actions are needed. A review of other plant readouts may be required to find out the exact DATE: 8-20-82 PAGE 62

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NUCLEAR POWit GENEGAipoN OtYtSION TECHNICAL DOCUMENT 74-n 22058-00

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, cause. After the corrective actions have been taken the plant will be stabilized and the stable point can be inside or outside of the window (Criteria for plant stability are given in the chapter entitled, " Post Accident Stability Determination".)

i An abnormal trans ient could also be indica ted by the stem pressure and steam saturation temperature lines. Generally, if steam pressure falls below 960 psig after trip, some failure has occurred and the ope rator should begin a diagnosis of the plant. A saturation tempe rature of %542F correspo nds to 960 p s ig , therefore, if stem temperature is lower than i S542F af ter a trip an abnormal condition is indicated. A loss of reactor coolant to stem generator heat trans fe r may also be noted when T e does o.

not follow T sat in the s team generator.

The " post trip window" shows two end points. One is for natural cir-culation. When the RC pumps are off Teold will be nearly the same as steam temperature but Thot will be greater. The value of Thot will depend on the decay heat level. The other end noint shows forced circulation.

1 1

When the reactor coolant pumps are running. Thot and Tcold will be almost f g I

) the same af ter trip and both will be almost the same t empe ra ture as steam t mpe ra tur e. Nearly every trip will end at either the forced or the na tur al circula t ion po int if all equipment operates correctly and no equir ,ent failures have happened. If some minor equipment failures have occurred (a le aky stem safety valve for example), the end point will be a

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somewhere else inside the window, b l

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BABCOCK & Wil.COX Numeen Nucteam roWEA GINtAADON Dm5loN 74- 122058-00 TECHNICAL DOCUlWENT A

The post trip window is a good gauge for determining if systems are operating correctly after a trip. If the path of reactor coolant temperature and pressure stay inside this window, or if the transient path goes outside this window saashtly but returns, then the transient is going

( as expected and the core cooling with steam generator heat t r. ins fer is correct. However, severe exces s ive fe ed wa t er t rans ient s must be d isc ove red before the transient path goes out s ide this window. This will be discussed in acre detail later. If the reactor coolant pressure and tempe ra ture are moving away from this window and do not return, then an abnormal transient is in progress and corrective actions for abnormal transients should be implemented. These corrective actions are directed r

toward restoring control of reactor-steam generator heat transfer, which

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is the preferred method for core cooling.

S ucces s ful transient mitigation can end with reactor coolant tempera ture and pres sure inside the window, but the plant can be stabilized out s ide the window. In some cases it is desirable to achieve stability outside this window,

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s Figure 9 also shows stean pressure; as illu s trat ed its value is at the 960 psig "lo we r" steam pressure limit. After trip steam pressure will normally be approximately 1010 psig. Steam t empe rature is also shown .

After trip the steam temperature should decrease to the steam generator s atur at ion tenperature (approximately ;46F) wh ich is set by the steam s generator pressure of 1010 psig. (Note: In an actual P-T display, steam DATE.

8-20-82 64

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BABCOCK & WILCOX NumiER NUCLEAR POWER GENERATION Olvi5loN TECHNICAL DOCUMENT w 1220ss-ms temperatures will always be shown at saturation tempera ture if the s t c a.;

temperatures are calculated from steam pressures rather than measured.)

Steam pressure and temperature are very important parameters to review to de t ermine if the plant is working correctly after trip. These two parameters in combination with reactor coolant pressure and t empe ra t u re ,

will show if the secondary side is: 1) removing the right amount of heat from t h. reactor coolant, and 2) indicate if the reactor coolant is t rans po rt ing the core heat to the steam generator so the steam generator can remove the heat. It is important to note that other parameters that are not displayed on the P-T diagram must also be checked to ensure proper primary to secondary heat t rans fe r . For example, excessive main feedwater f

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will not initially cause noticeable steam ge ne rator pressure or tem pe ra t ure reduction. By the time excessive feed wa t er causes the transient path to leave the pos t-trip window, the steam generator will be over filled. The re fo re , main feedwa te r flowra t es and SG levels must be checked very early following a reactor trip.

Heat Transfer Characteristics Shown by the P-T Diacram s

This section will show examples of various transients on the P-T diagram.

Both normal and abnormal transients are shown fo r comparison. The transients to be illustrated include:

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- A normal reactor-turbine trip with no failures

- Transients that show the ef fects of equipment failures before trip

- Transients that show the ef fects of single and multiple equiptrent failures after trip.

These examples are used to show how reactor coolant system pressure and temperature and steam pressure change when di f ferent f ailures cause changes in heat transfer.

P-T Transient - Normal Trip Figure 10 shows the typical response of both primary and seconda ry plant parameters following a reactor trip. Individual important parameters are shown as well as the P-T diagram. The shape of the reactor coolant P-T characteristic path from power operation (above 15%) to hot zero power is always similiar to the one shown unless an abnormal transient is in pro-gress. The dip of the curve is due to cooldown of the RCS to near T sat Of

( the steam generators fo r the turbine bypass system (TBS) setpoint. The c ooldown res ul t s in coolant shrinkage wh ich causes a pres sur ize r outsurge s

and pressure reduction. After the RCS reaches a tempe ra t ure slightly above T sat of the SG's, the reactor coolant will repres sur ize and stabi-lize. Depending on prior power operating history the low point of the dip will have dif ferent values, but the ch aract e ris t ic shape will always exist. khen the plant trips, the steam pressure will initially rise to s

DATE: 8-2 0-82 PAGE 66

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BABCOCK & WILCOX NumsEn NUCLEAR POWER GENERATION DIVISION 7'+-1132 &

TECHNICAL. DOCUMENT the safety valve se t point and then quickly settle out at the post trip bine bypass valve setpoint and steam temperature will fall fr on i supe rheat ed condition to saturation temperature (if steam t empe ra t ur.

the P-T diagram is de rived from steam pressure, saturation t em pe . .i s -

will always be shown).

A similar P-T ch aract e ris t ic shape can also be seen for some ab nm~r transients, especially those that are caused by secondary side over cooling. On the other hand small LOCA's which depressurize the RCS slowly will not show the characteristic repressurization upturn (unless they are very small leak s or they are isolated). Individual pa rame t e rs are shown in Figure 10 versus time to show the approximate time for stabilization.

Since stabilization takes a certain amount of time, the overcooling charac-teristic can mask failures that would not show up wh ile the overcooling trend exists. Since overcooling can be caused by too much feedwater or low steam pre s s ure , one of the immediate post trip ope ra tor actions inc lude s a revi ew of the steam pressure, MFW fl ow , and steam generator level to assure that the trip is normal and not combined with an overcooling transient.

s Indications of a normal trip as shown by the P-T diagram inc lude :

1. Ilot and cold leg temperatures will stabilize in 2-3 minutes.

2. Reactor coolant pressure will stabilize in 5 to 6 minutes.

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BABCOCK & WILCOX NUCLEAR POWit GENE #AilON DIVI 510N I TECHNICAL DOCUMENT 74-1122058-o0 k

3. Te old will be nearly equal to saturated steam temperature, indicat-ing that reactor coolant is transferring heat to the steam ge ne ra tors .

4. Stean pressure will stabilize in 2 to 3 minutes.

( 5. Reactor coolant subcoo'.ed margin will increase, k

P-T Characteristics - Abnormal Transients - Before Trip Although many transients will go so fast that operator action before trip is unlikely, the changes in displayed parameters prior to trip can provide clues as to the type of transient (overheating, overcooling, etc.). When the reactor trips the trend of the accident can be covered up by the P-T r change caused by the cooling e f fects of the trip so the characteristics

( that occur in the short time before trip can help identify the trend.

Operator action in response to a change from the normal position in the P-T window may be possible, and trip may be avoided, but usually trans-ients will happen too fast for the operator actions to be succ es s ful .

Nevertheless, some of the indications be fo re trip will help to de termine what may be occurring.

1 i

Figures 11, 12, 13,and 14' show pre-trip movements on the P-T diagram.

Steam pressure and RC temperature and pressure will re s pond differently depending on the cause. The events represented by these curves are:

s DATE: 8-28-82 PAGE 68

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Figure 11 - Overheating Transient Figure 12 - Overcooling Transient Figure 13 - Overpressure Transient Figure 14 - Depressurization Transient f

P-T Characteristics - Abnormal Transients - After Trip Figures 15, 16, 17, 18, and 19 show examples of transients which may occur because of failures either on the primary or secondary side. These examples show transients which end as expected and also go past the expected point because of additional failures. Those transients which are corrected properly will follow the expected course and will end up in the "pos t trip window" near the normal post trip end point. When the path goes outside the window, the transient is defined as abnormal and the

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Sq direct ion reactor coolant pressure and temperature move toward can be classified as overheating or overcooling. In combination with overheating or ove rcooling the reactor coolant temperature and pressure path can also ,

move toward more or less subcooling.

These trends, ove rh e a t ing , overcooling, and loss of subcooling , are the l

l first indications to check in transient diagnosis and correction. In the

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case of overcooling, which can be masked by the normal post-trip response ,

other parame te rs such as MFW flow and SG levels, must be checked very

early in the transient using the P-T diagram.

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( NUCLEAR POWER GENERATfDN OlV15 ION 74-1122058-00 TECHNICAL DOCUMENT

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An abnormal transient will show different characteristics depending on the failures that may have occurred. Some characteristics of RC pressure and tempera ture and of steam pressure that show undesired heat transfer on the P-T diagram are:

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( l. Reactor coolant subcooled margin is lost

- The trend may be caused by overheating or overcooling.

- The trend may be caused by loss of reactor coolant.

Subcooling will be lost for all except the very smallest breaks.

2. Steam pressure is much lower than normal A value of 960 psig has been established as a low limit similar to the "po s t trip" window for the Reactor Coolant P-T. If steam pressure drops below this limit after trip, then an abnormal condition may exist. A co rres po nding value of 542F has also been chosen for saturated steam temperature.

- Stean pressure may be low because of a failure in the steam lines. Overcooling will result. Subcooling may or may not be lost.

- Stean pressure may be low because of a loss of all fe ed wa t e r . Overheating will result. Subcooling will

, be lost, s

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NUCLEAR PowtR GENERATION OlYt$10N 74-1 22038-00 TECHNICAL DOCUMENT _.

- Stean pressur e may be low because a large amount of reactor cool-ant has been lost and cannot pass core heat to the feedwa t e r h the generator to create steam. Large LOCA's can cause this or

• Inadequate Core Cooling (ICC) situation can cause this. Both LC and ICC are discussed in detail as separate topics later.

- Steam pressure may be low due to excessive EFW. Ove rc o, ie resul t and subcooling may be lost.

3. Steam generator saturation temperature and Tcold _ do not. cy, (not coupled) (Lack of primary to secondary heat t rans fer)

- When Tcold does not change when T sat -SG changes, then b trans fer from the reactor coolant to the steam generator  :

int e rru pt ed . Natural circulation has probably stopped when this occurs and the reactor coolant may heat up. The reactor coolant condition can be subcooled or saturated. If the reactor coolant is superheated, natural circulation has been lost.

The transients used as examples are:

N A

DATE: PAGE 8-20-82

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BABCOCK & WILCOX NUCLE AR POWER GENERATION Olvl5lON

( TECHNICAL DOCUMENT 74-1122058-00 Figure 15 - Loss of Main Feedwater

- 15a) Shows Loss of Main Feedwater with EFW actuated. The impo rt a r.t feature of this transient is that the main feedwater heat sink is quickly rep lac ed with an EFW heat sink; the trend looks similar to a normal reactor trip.

- 15b) Shows Loss of Main Feedwater with EFW delayed. Important features of 15b) are: 1) loss of steam pressure, and 2) the reactor coolant heats up and would eventually saturate at 2500 psi. This is an indication of lack of primary to secondary heat trans fer.

r Figure 16 - Small Steam Line Break

( - 16a) Shows an uriiso lab le break that is terminated by stopping main feedwat e r and EFW and allowing the generator to boil dry. The important feature is that the reactor coolant was overcooled be fore i so lat ion ; after isolation when the " bad" generator boiled dry it was no longer ab le to remove heat from the reactor coolant. The " good" generator, wh ich is pressurized, is the heat sink; it allows the reactor coolant k to return to stable subcooled conditions.

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BABCOCK & WILCCX NUGEAR POWit GENERATION DIVISION TECHNICAL DOCUMENT

- 16b) Shows an unisolable break that is not te #

Continued feeding' of FW and boil o f f c aus..:

coolant overcooling. Since HPI is running H overpressurized at low temperature violating f.; +; .

I Figure 17 - Excessive Feedwater

- This transient is shown to be corrected by ICS operat i'm looks similar to a normal trip. Were the transient to con tinue, water could enter the s t ean lines and discharge ti.ru the MSSV. The RCS would overcool to saturated conditionc

( i.e. , drain the pres sur ize r) by the time water entered the (

x steam lines. An example of a severe excessive feedwater transient is given in Appendix A of Volume 2.

Figure 18 - Small Break LOCA in the Pressurizer Steam Space

- The important feature of this transient is that water will i

flow into the pressurizer from the reactor coolant loops, Although the pressurizer will show a level it is not a good l

l indication of reactor coolant inventory when the reactor i j i coolant is saturated, l

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( suct:4n rowen cesenanos emsios suusta 74-1i22058-00 y TECHNICAL DOCUMENT

- 18a) Shows a LOCA with the break isolated af ter the accident starts. Refill and repressurization of the reactor coolant system allow a normal cooldown with a pressurizer bubble.

- 18b) Shows a LOCA that is not i so la t ed. Subcooling does not return as quickly although the entire reactor coolant system fills with water. Cooldown af ter this accident will be with a pressurizer full of water.

Figure 19 - Small Break LOCA in the RCS Loop Water Space 7

- This t rans ient is dif ferent from Figure 18 because the pressurizer does not fill with water from the loops as a result of the break.

- 19a) Shows a small break with EFW used to remove heat.

- 19b) Shows the same break with EFW delayed. The effect of the heat trans fe r to the steam generators can be seen by c ompa ring the RC pressures with a nd without EFW. With no EFW the RC system pressurizes to 2500 psi. At th is pressure the leak rate is highest and llPI flow is lowest; use of the steam generator helps to reduce the le ak flow and increase the HPI flow to cover the core. 19b also shows that steam pressure is lost because no steam generator inventory exists to create steam.

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i NATURR CIE' M M Q g I , I f it t , . 400 450 500 !550 600 650 700 Reactor Caolant and Steali Outlet Temperature, F EXCESSIVE MAIN FEECWATER ADDITION TO CNE STEAM GENERATOR (DURING POWER OPERATION) l Reference Time  ! Points (Seconds) Remarks ( 1 0 With the plant operating at 100% power. a failure of the MFW ptrip controller allows pump overspeed. Ex-cessive feedwater addition begins. 1-2 0-60 Slight overcooling of RCS occurs due to excessive feedwater addition. ICS pulls mds to compensate for reduction of Tave, but rod withdrawal is limited by L the high flux limiter to 103%. 2 60 Manual reactor trip. 2-3 60-200 RC P&T decreases due to loss of fission power and higher than nonnal secondary inventory. The ICS initiates a feedwater runback and the MFW addition s tops. Pressurizer level decreases because of reactor coolant contraction. 3 200 Minim:sn pressurizer level reached. . 3-4 >200 Normal system pressure restored by operation of MU system and pressurizer heaters. Primary system is lef t in a stable, hot shutdown condition. 1 f

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BWNP-20007 (6-76) BABCOCK & WILCOX " NucteAn rowen GENtaADON DM510N { 74- 22038-00 TECHNICAL DOCUMENT k CHA?TER C ABNORMAL TRANLIENT DIAGNOSIS AND MITIGATION Introduction The chapter shows how an abnormal transient can be diagnosed and mitigated b using the in fornution provided by the P-T diagram and the concepts on heat k' t rans fe r discussed in the previous ch ap t e rs . A simplified flow chart of the approach to be used to diagnose and mitigate an abnormal transient is provided in Figure 20A " General Plant Accident Mi t iga t ion" . It is broken down into a few separate steps, although these steps will blend together into one cont inuou s process in actual practice. The Abnormal Transient Operating Guidelines are implemented whenever a reactor trip occurs or a I forced shutdown is necessary. k The guidelines are provided in Part I. They list the appropriate operator actions necessary to mitigate an abnormal transient. They follow the approach outlined in Figure 20A. The guidelines incorpo rate the following features.

l. Use of the P-T diagram, wh ich provides a constant feedback to the operator on his succ ass or failure after taking each step in Part I.

This diagram should be checked frequently to make sure things are progressing as expected. It will give the opera tor early indications of sub s eque nt failures that are delayed after the initial event, or , multiple tailures that were masked by the predominant event and thus didn't appear until that one was corrected. DATE: PAGE 8-20-82 75

BWNP-20007 (6-76) BABCOCK & WILCOX NUusEn NUCLEAR POWER GENERATION DIYl510N TECHNICAL DOCUMENT 74-1122058-00

2. The guidelines are constructed such that the operator makes an attempt to correct the problem with a given piece of equipment or system (e.g.,

EFW to correct loss of main feedwat e r) . If that fails, he is ins truc t ed to go on to the next available sys ten (e.g., AFW, then HPI cooling). The failure of the EFW system is not given priority attention in the structure of Part I, protection of the core is.

3. The operator is given frequent " status" aids throughout the procedure to help him maintain proper orientation.

4. If new symptoms appear, he is instructed to rec ycle (go to the section that treats that symptom) to the appropriate part of the procedure.

Immediate Actions , The firs t block in Figure 20A is the "Immediate Actions" block. The immediate actions should be completed in the first 2-3 minutes. The first action to be made is to determine if a reactor trip has occurred or plant conditions requiring a forced shutdown exist. If a reactor trip has occurred the operator should manually trip the reactor and turbine, then

                                                             , . proceed to the next post trip step of the ATOG procedure which is " Vital Sys tems Status Ve ri fic a t ion" .                                     However, if plant conditions warrant a forced shutdown, the operator should initiate the appropriate shutdown DATE:                                                                                                   PAGE          '

8-20-82 i

BWNP-20007 (6-76) BABCOCK & WILCOX Nuuset NUCLEAR POWER GENtRAhoN DIV151oM 74- 22038-o0 TECHNICAL DOCUMENT k proc ed ure . If a reactor trip should occur during the fo rced shutdown operations, the ATOG procedures should be implement ed . If the fo rced shutdown is due to a SGTR, the operator should proceed directly to Section III.D of the guideline. ( LJ Vital Systems Status Verification The next major block on Figure 20A is the Vital Sys t ems Status Veri-fications. This section requires reviewing specific plant status items, including the P- T diagram, 'to determine if they are behav ing as they should for a normal reactor trip. If the specific plant status items F l cannot be verified as performing as expected, the operator should pe rform ( the specified remedial actions. The procedures provide s pecific remedial actions for each plant status item which cannot be ve ri fied . The plant status items which are checked first are the normal automatic post trip functions wh ich control core reactivity, primary and secondary inventory, and primary and secondary pressure. 7 During the performance of the immediate actions and status checks, certain 6 conditions require specified " standard" actions. These conditions are: DATE: 8-20-82 PAGE g

BWNP-20007 (6-76) BABCOCK & WILCOX NUctEAR POWER GENERATK)N DIV15 TON NUMBE R TECHNICAL DOCUMENT 74-1122058-00 e Reactor Trip e ESAS Actuation e SLBIC actuation e Loss of grid power These cond it iont can occur separately or in various combinations. The actions to be taken are given in Table 2. In addition, two transients require a very fast check of indications and fast corrective actions. Excessive main feedwater requires the opera tor to quickly terminate feed flow to prevent water spilling into the steam line, and steam generator tube rupture requires fast action to depressurize and begin cooldown to limit the of fsite doses. Table 3 shows t

         'the actions required for these transients.                        '

l vt, r . . w.u. Finally, the operator needs to check' the P-T diagram for " overcooling",

            " overheating", or " leas of subcooling" conditions. The P-T diagram is the foundation for transient diagnosis and for the actions to correct abnormal                              g transients.

1 i Abnormal Transient Diagnosis and Treatment Although the type of transient may have become evident during the l

                                                                                                          ~~"

DATE: PAGE l 8-20-82 78 f -.

1 1 BWEP-20007 (6-76) BABCOCK & WILCOX Nuusta NUCLEAR POWER GENERAfiON DIVISION TECHNICAL DOCUMENT 74-1122058-00 first 2 or 3 minutes after trip, plant monitoring is required to make sure that the transient is going as expected. Generally, af ter 2 or 3 minutes the plant will begin to stabilize within the " Post Trip Window" (examples ( of this were given in the P-T Diagram Chapter). Actions have already been ( ,/ taken to identify and handle the " fast" transients and the systems wh ich should be operating have been checked to make sure that they are working correctly. Further plant monitoring should begin. At this stage the e f fort should now be to make sure that the plant stabilizes as it should. To do this the P-T diagram is kept under surveillance. If reactor coolant pressure and temperature stabilize within the P-T post trip window, and f steam pressure is above the low steam pressure limit, the transient is probably not abnormal and a quick check of the following should be made to ensure system and equipment parameters are within expected values: Heat Transfer Balance Indicatcrs P-T diagram ( for AC pressure and temperature and subcooling)

                  - Pressurizer Level
                  - Steam generator level and pressure The containment temperature should be monitored if there is any indication of a primary or secordary side leak into the containment.                                                        Containment tempe ratures higher than normal can cause levels of components inside the containment (OTSG, pressurizer and CFI), to indicate erroneously high due to heating of the re fe rence legs.                                                 These errors are significant for the DATE:          8-20-82                                                                                           PAGE      79     d

BWNP-20007 (6-76) BABCOCK & WILCOX ,,,, NUCLEAR Powta GENtaATION olVl$10N TECHNICAL DOCUMENT 74-i 22058-00 OTSG 4en the RCP's are not operating and levels of 50% and 95% on the operate range are required for subcooled natural circulation and boiler-condenser cooling respectively, during a SBLOCA. Under these conditions the OTSG 1evels must be manually corrected to account for the containment temyrature. A leak into the containnent may cause the component's reference leg to be heated locally above the average containment tempe ra ture , there fore no s imple level instrument should be solely relied upon under these conditions. In addition a rapid RCS depressurization (within a few minutes) to less than 600 psis can cause the pressurizer level indication . to be in error due to of f gassing and water ejection from the reference leg. Pressurizer heaters should be manually de-energized under these conditions and not be re-energized until RCS pressure returns to 1600 psig and pressurizer level is at least 50 inches.

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BWNP-20007,(6-76) BABCOCK & WILCOX ( NUCLEAR POWER GENERADON OtYlSION Hum En TECHNICAL DOCUMENT 7'-1122038-00 Equipment Status and Operation (depending on what was started);

               - Makeup /HPI flow rates and pump status                                        ,
              - Main or emergency feedwater flow rates and pump status
              - RC pump operation including cooling water and seal injection service
              - Position of important valves (letdown, ERV, feedwater isolation
 /               and control valves, pressurizer spray valve)
              - Containment isolation and cooling systems
              - Power supplies (AC and DC)

Once these reviews are completed, a more thorough check can be conducted and a decision made to determine if the plant is stable. ( (Refer to Chapter F " Post Transient Stability Determination".) k But if the first review of the P-T indicates that the reactor coolant pres sur e and tempe rature are not going to remain within the post-trip window (or return to it), or that steam pressure is below the steam 9 pres sur e limit, then something is wrong with heat trans fe r and cor-rective actions are required to bring the heat transfer into balance. s k w DATE: 8-20-82 PAGE 81 v

I BWNP-20007 (6-76) BABCOCK & WILCOX ,,, NUCLEAR POWER GENERATION oivi51oM TECHNICAL DOCUMENT 7'- 22058-00 Diagnosis There are two general abnormal transient types: e Excessive Primary to Secondary Heat Trans fer " overcooling". e Not enough Primary to Secondary Heat Transfer " overheating". A loss of reactor coolant subcooling margin can also occur and can be ( combined with or caused by either " overheating" or " overcooling". The characteristics of an " overcooling" type transient are shown on a P-T diagram in Figure 20B. The figure shows Thot and Tcold coming together as the reactor coolant reaches an isothermal condition fol-lowing reactor trip because the reactor coolant pumps are running. If no RC pumps are running, Thot and Tcold will not come together. A temperature difference will develop across the core which creates

                                              ,     ..- >:.-    u ..            -

the thermal driving force for natural circulation of the reactor coolant. l The exc es sive heat removal by the stean gene rators will cause the 1 average reactor coolant temperature to go down. As the temperature l( goes down, the reactor coolant will contract cau s ing the pressurizer level to go down. If the ef fect cannot be offset by increased makeup flow to the RCS, the pressurizer level will continue to go down which will cause the RCS pressure to also go down. If the pressurizer  ; empties, the RC pressure will decrease toward the saturation pressure causing a " loss of subcooling margin". DATE: 6-20-82 PAGE ~ ' ' _. 82

BWNP-20007 (6-76) BABCOCK & WILCOX Numen NUCLEAR POWf t GENERATION DIVl510N I 74- 22058-00 TECHNICAL DOCUMENT L The overcooling is caused by a temperature decrease on the secondary side of the stean generators. Since the secondary steam is saturated after reactor trip (no superheat), the steam pressure must also be decreasing. Figure 20B shows this decrease in secondary pressure and f temperature. The steam pressure must go below 960 psig af ter RC trip for the RC temperature to go out of the post trip window on the low temperature side. The steam pressure be fore reactor trip would have been around 900 psig but supe rh ea t ed . Following reactor trip, the steam pressure will probably go up to the sa fe ty valve setpoint and then decrease down to the turbine bypass valve setpoint. r The characteristics of an " overheating" type transient are shown in k Figure 20C. The figure shows the Th ot - RC pressure trace. Initially the RC pressure and temperature decrease after a reactor s 2, trip. However, as the primary to secondary heat trans fer is lost the RC average temperature increases. As the tempe rature increases the RC expands causing the pressurizer level to increase and RC pressure l 0 to go up. This pressure increase will continue until stopped by the l pres sur ize r ERV or safety valves ope ning . However, the RC tempera-L t ture will continue to increase. If uncorrected, this will eventually lead to a " loss of subcooling margin" at high pressure. t',e

                                                           ^

I b=- DATE: 8-20-82 PAGE ' 83 } ;.v., N

BWNP-20007 (6-76) BABCOCK & WILCOX NUMRER NUCLEAR POWER GENERATION Division r, TECHNICAL. DOCUMENT "74-1122058-00 {Cl. Without heat being transferred to the secondary side, the secondary side stean will gradually cool which will also cause the SG pressure to decrease. A direct " loss of RC Subcooling" without a simultaneous " overcooling" or " overheating" caused by a secondary system malfunction is shown in Figure 20D. This type loss of subcooling margin could be caused by a loss of RC inventory. This loss in inventory will cause the RC pres-sure to fall but without the large decrease in RC temperature asso-ciated with the " overcooling" type transient. Mitigation The path for correction is charted and shown on Figure 21, " Accident Mitigation Approach". The chart keys on the three general charac-teristics displayed on the P-T diagram: overcooling (too much steam generator heat trans fer) and overheating (insufficient steam genera-tor heat t rans fe r) and loss of subcooling. The chart is a reference that ties toge ther a wide variety of information for corrective v a. actions. With the exception of LOCA, correct ive actions for all ( abnormal transients are provided in this section. LOCA is discussed lk separately in considerable detail in Appendix F of these guidelines. Specific information for mitigation of overcooling and overheating transients are provided in Figures 22 and 23 respectively. i DATE: 8-2 0-82

• PAGE .!O g

BWNP-20007 (6-76) BABCOCK & WILCOX " NUCitAR Powin GENERATION DIYlSloN C TECHNICAL DOCUMENT 74-1 22058-00 Corrective Actions for Overcooling (too much stean generator heat transfer) Figure 22 shows the corrective actions to be taken for overcooling. The chart is largely self-explanatory so only a brief discussion will Cj be given. Information provided by the chart will not be repeated. Overcooling is always caused by failures on the secondary side. The usual sources of failure are low steam pres sur e or excessive main or emergency feedwater or by combinations of high feedwater and low pres-sure. The P-T diagram shown is typical for a more severe case of overcooling; usually excessive feedwater alone (unless severe and not ( t ermina ted within 2-4 minutes) or small reductions in steam pressure will not cause loss of subcooling. But the general trend shown by the P-T diagram is characteristic of ove rcooling . Some LOCA's can also cause a loss of steam pressure because the RCS will depr e s s ur ize , cool and draw heat away from the steam generators ; this will be temporary for small breaks. Once this ove rcooling trend is exhibited, checks should be made on stean pre s s ur es , s tean generator levels, loop Teoid temperatures, and main or emergency feedwater flow. If the c ause is obvious, then actions to isolate the cause should be taken. If the subcooling margin is lost during an overcooling transient, the sub cooling rule should be followed: two HPI pumps should be turned DATE: 8-20-82 PAGE 85

BWNP-20007 (6-76) BABCOCK & WILCOX NyctEAR POWER CENERATioN DIVI 5 ION TECHNICAL DOCUMENT 74- 122058-00 on and run at full capacity until the subcooling margin is restored. When the subcooling margin is lost the RC pumps should be tripped and not restarted until subcooling is restored. Overcooling transients induced by steam pressure and/or feedwater control failures on only one SG may be obvious when the Tcoid temperatures are compared. If the magnitude of the overcooling is f significant, Tcold in the af fected loop will always lead Tcold in the loop with the good SG (i.e., Tcold in the af fected loop will be lower). Detection of overcooling by low steam pres sur e and de tenninat ion of which generator is overcooling can be done by two methods. The first way is to stop all feedwater when a_ level, exists in both generators (if level exists only in one generator the one without level is likely to be overcooling). When feedwater is isolated

• s Mth genera-tors, the level should be lower in the overcooling generator if iso-lated by the SLBIC or should fall at a faster rate in the overcooling

( generator if not isolated by the SLBIC. Detection h possible before both generators boil dry and feedwater should be restored to the

 .         " good" generator before it dries out.        A characteristic fe ature of steam leaks is that the steam generator with the low pressure will t rans fe r the heat from the RCS and lower the RCS temperature; the               ;

DATE: 8-20-82 PAGE 86 /t

BWNP-20007 (6-76) BABCOCK & WILCOX Numin NuctrAn ROWER GENERATION Dtvi$loN 74-1122058-00 TECHNICAL. DOCUMENT

                       " good" generator will not.                                 Consequently the RCS temperature can f all below the temperature of the " good" generator.                                                           When this occurs the pres sur e in the good generator will drop below the TBS setpoint, they l

will close, and steam generator level will drop slowly or not at all. f Consequently, one steam generator will retain level, so stopping all Li feedwater to both generators is not dangerous. However, when one stem generator boils dry, then the remaining generator will begin to transfer heat and level will drop. Feedwater must be restored before it is dry. The second (but less reliable) way to identify an overcooling generator is to compare the rate of drop of steam pressure in both

 '                     ge ne ra to rs .                             The overcooling generator will pe rmit steam pressure to fall faster than the good generator will if the SLBIC has not actuated or if the failure is upstream of the MSBV.                                                                       A dif ferential pressure between the two steam generators of about 100 psi, with the overcooling ge ne rator lower, will show the correct one to isolate.

The 100 psi dif ferential will show up rapidly for large leaks and slower for small leaks. A steam leak of about 5% total flow (about equal to one main steam safety valve stuck open) will show this trend within 3 to 5 minutes. However, this magnitude of pressure di f fe r-ential may exist only for a short duration. The r e fo re , comparison of level change s in isolated SG's is prefe rred , if the affected SG is DATE: pAGE . o' 8-20-82 87 __. _ _ _ _ _ _ _ _ __ _ _ _ _ __ _ _ ___._ - - - __ _ - - --J

BWNP-20007 (6-76) BABCOCK & WILCox NUCLEAR POWER GENERATON OlVl$loN 00EI TECHNICAL DOCUMENT 74-1122058-00 not obvious. 4 Correct ive actions for exces sive feedwater are shown on the over-

          ,      cooling diagnosis chart (Figure 22) and discussed in Appendix A.

Correct ive actions for low feedwater tenperature are also shown or. l[k Figure 22.

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BWNP-20007 (6-76) BABCOCK & WILCOX Numsen NucteAn rowen GeNenATION DIVISION - TECHNICAL DOCUMENT 74-1122058-00 k Corrective Actions for Overheating (not enough steam gene rato r heat trans fer) _ Figure 23 shows the correct ive actions to take when the reactor coolant cannot transfer heat to the steam generators. f React or-t o-s t ean generator heat trans fe r is not coupled; Te and SG

  /               T sat   do not track together.       in general there are three causes of insufficient heat transfer:

e There is no inventory in the steam generator to receive the heat (loss of all feedwater) e The reactor coolant cannot trans port the heat to the genera tor because there is insuf ficient inventory (LOCA) , I e Circulation has stopped (forced and natural) k Natural circulation can be temporarily interrupted because of reactor coolant contraction after a severe overcooling transient. A long interrupt ion would not be expected since HPI will refill the system and na tur al circulation will normally restart. Loss of natural cir- - culation would be expected for most LOCA's or for an extended loss of feedwater. The refo re, to restore natural circulation for either of L ' these, the failure must be corrected ( feedwater restored) and sub-cooling should be restored (to ensure the best natural circulation). Since loss of natural circulation heat transfer is the most probable cause of the overheating conditions, the " overheating" correct ive actions include restoration of heat transport as an integral part of the action, w DATE: 8-20-82 PAGE '# 89

BWNP-20007 (6-76) BABCOCK & WILCOX NUMBER NUCLEAR POWER GENERATION DIV15 TON TECHNICAL DOCUMENT 74-1122058-00 Loss of all Feedwater , Ove rheating when all feedwater is lost can take different paths de-pending on the decay heat level, when feedwater was lost and whether HPI was operating before it was lost. The P-T diagram illustrated shows a total loss of all feedwater immediately after reactor trip from full powe r , with HPI cooling started when the operator recognized the loss of primary to secondary heat transfer and loss of all fe edwa ter. Regardless of the path, the loss of all feedwater from power operation will exhib. two clear characteristics on the P-T diagram: e Af ter the normal post-trip cooldown the RCS will begin to reheat and repressurize beyond the normal post-trip " window" (point 2 on Figure 23) as the SG's boil dry. e Steam pre ssure and steam temperature will drop because there is no feedwater, i l The correct ive actions for this transient are . to attempt to restore i r l feedwater; failing to do so,'HPI cooling should be started when prima ry te secondary heat trans fer is lost. Two HPI pumps should be (l started and run at full capacity and the ERV manually opened. l( l Although the subcooling rule requires that HP1 be started when the

          ' ' subcooling margin is lost, the expected path for this transient (if HPI were not started and the ERV opened) is that high pressure is                        !

reached be fore the subcooling margin is lost. This will result in losing primary inventory out of the ERV for abou t 30 or 40 minutes DATE: 8-20-82 PAGE  : . I, G 90

BWNP-20007 (6-76) BABCOCK & WILCOX Nument NUCLEAR POWER GENERATION OlVl$10N TECHNICAL DOCUMENT 7'- 22038-oo be fore subcooling margin is lost. This could lead to conditions of core uncovery. Therefore, the operator should start HPI and open the ERV when primary to secondary heat transfer is lost to assure core protection rather than waiting until the subcooling margin is lost and implementing the subcooling rule. When HPI cooling (with the ERV open) is started unde r these circum-stances, all but one RC pump should be tripped. This will reduce the heat input to the RCS. One RC pump should continue to run as long as possible to maintain forced core cooling. When the subcooling margin is lost all the RC pumps must be tripped, f L Continued operation without feedwater and with HPI cooling will allow s ub cooling to be restored when the heat removed by the HP1 flow matches the decay heat. When the subcooling margin is restored the HPI flow may be throttled. A reactor coolant pump should also be restarted at this time. Control of HPI flow to keep the minimum subcooling margin is important to . minimize reacto r vessel thermal shock. Thermal shock occurs when the reactor coolant is subcooled and no circulation exists because the cold HPI water will slowly flow into the downcomer and flow next to the hot reactor vessel wall. Restart of a reactor coolant pump will thus help prevent exceeding the brittle fracture limits because it mixes the HPI water and the reactor coolant. (See Figure 25 and the "Best Methods" chapter for a u discussion of HPI throttling and RC pump restart.) DATE: PAGE 8-20-82 g

l l BUNP-20007 (6-76) l BABCOCK & WILCOX suu En NUCLEAR POWER GENERADON DIVl$10N TECHNICAL DOCUMENT 7 - 22o58-o0 q k LOCA The other condition in which heat trans fer to the steam generators can be inter rupted is during a LOCA. LOCA is discussed in detail in Appendix F and will not be covered here in de t a il . However, this section will show how LOCA's are to be identified and will show how to locate those that can be isolated. Although some small breaks will allow the reactor coolant to transfer heat to the steau generators, some will not. The most significant characteristic of poor heat transfer is an increase in incore the rmocou ple indication along the saturation line when a steam gene ra tor level exists. The incore T/C is increasing because the reactor coolant is absorbing the core heat and not passing it to the generators. S tean pressure and s t ean generator satur at ion temperature will gradu-ally drop because litifu or no heat is being ab sorb ed . Figure 13 of Appendix F (LOCA) shows these P-T characteristics. 1 1 DATE: 8-20-82 PAGE 92

BW14P-20007 (6-76) BABCOCK & WILCOX Nua:ER NUCLEAR POWER GENERATION DIVISION TECHNICAL. DOCUMENT 74-1122058-00 ( Figure 23 indicates that LOCA's can cause poor heat transfer and includes three references for supporting actions: (1) Table 4a shows how to distinguish LOCA's from other transients. ( _j (2) Table 4b shows symptoms for LOCA's that can be located and shows wh ich equipment to use for isolation for those that can be'~ iso lated. (3) Appendix F shows the corrective actions for LOCA's. f ( l t l Y DATE: AE 8-20-82 93

BWNP-20007 (6-76) BABCOCK & WILCOX ( NUCLEAR POWER GENERATION DIVl5 TON TECHNICAL DOCUMENT 74- 122058-00 Table 4a HOW TO DISTINGUISH LOCA'S FROM OTHER TRANSIENTS Unique Characteristics of LOCA's e Rapid system depressurization to saturated conditions with l I little or no change of reactor coolant temperature (characteristic of all but the very smallest breaks) s Sustained saturation (HPI does not return the reactor to a subcooled state within 5-10 minutes af ter actuation) e Contaiment radiation (only for breaks in contaiment) NOTE: A stem or feed line leak inside contaiment will cause high pressure, temperature and humidity but will not cause high radiation, unless there is a SGTR. e Stem pres sure, feed flow and stem generator level do not indicate overcooling (this helps to dif ferentiate LOCA's from overcooling transients) l l e High steam line radiation alarms (tube leaks only) l e Low makeup tank level (in the absence of all of the ! l l above, this indicates a leak outside the containment) l l 1 1 NOTE: LOC A's CAN BE DIFFICULT TO DETECT, ESPECIALLY IF THE BREAKS ARE SMALL. THEY CAN OCCUR INSIDE THE CONTAINMENT AND STEAM i , GENERATOR TUBE LEAKS ARE LOCA'S. IF THERE IS ANY DOUBT THAT 1 AN ACCIDENT IS A LOCA, ASSUME THAT IT IS AND TAKE l l APPROPRIATE LOCA ACTIONS UNTIL CLEARLY PROVEN OTHERWISE. l l , THE GENERAL ACTIONS INCLUDE HPI COOLING, RC PUMP TRIP, AND COOLDOWN TO COLD CONDITIONS. 1 l { DATE: PAGE 8-20-82 94 l

BWNP-20007 (6-76) BABCOCK & WILCOX Numien Nuctexa rowen GENERADON DON 510N TECHNICAL DOCUMENT 74- 122058-oo L Pressurizer Control System Failures Two failures of the pressurizer controls can occur that can change RC pr e s sur e. These are not serious events because they are slow, but if they are left without correction plant control can become more j di f ficult. Fa ilure of pr es sur ize r heaters (on) with no spray operation will cause the RC pressure to increase to the ERV setpoint at a constant reactor coolant t empe ra tur e. (If the spray is operating it will stop the heater pressure increase.) Steam will be released to the quench tank until the heaters are turned off. The nonnal makeup control will continue to add reactor coolant until the makeup tank icvel is lost at wh ich time the pressurizer level will begin to drop. Although this is a very slow transient and should be easy to correct (manual cutoff or power disconnect) if it is left un a t tended , the following equipment damage can result: Quench Tank Rupture Disk Failure i Makeup Pump Failure on Loss of Suction Heater Burnout when they Uncover A spray failure (on) will cause a pressure decrease at a constant RC temperature until the reactor coolant becomes saturated. This may be corrected by blocking spray flow. s I DATE: PAGE 8-20-82 ' 95 TM j a -

BWNP-20007 (6-76) BABCOCK & WILCOX NUMBER NUCLEAR POWER GENERATION DIVISION TECHNICAL DOCUMENT 74-1122038-00 Neither failure is considered serious because there is ample time for correct ion. Pressure and pressurizer level alarms will sound far in advance of the time when rapid action is required. 1 1 1 a t .- lC l l DATE: 8-20-82 PAGE g' ' 4

l Figure 20a GENERAL PLANT ACCIDENT MITIGATION l l I IMMEDI ATE ACTIONS (2-3 MINUTES)" I ' REACTOR TRIP (MANUALLY TRIP REACTOR AND TURBINE) l l

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BWNP-20007 (6-76) BABCOCK & WILCOX ( HUCLEAR POwta GENERATION OlVI$10N NuustR TECHNICAL DOCUMENT 7'-i 22058-oo CHAPTER D BACKUP COOLING METHODS The normal method of core cooling is by trans ferring heat from the I core to the stem generators using subcooled reactor coolant. This (; is the preferred method and is the one the opera tor is most familiar with. However, if this mode of heat trans fe r is lost other means of core cooling are available. This section will discuss these backup cooling me thods and explain their uses and limitations. Four instances will be covered: - ( l. HPI Cooling

2. Boiler-Condenser Cooling

3. Restoration of Natural Circulation

4. Inadequate Core Cooling (i.e., cooling methods after ICC has starts 3)

These methods will not be necessary if the normal method of cooling r using the steam generators is working. L HPI Cooling (for Loss of All Feedwater) r A complete loss of feedwater is not a likely event , but it can occur because of mult iple equipment failures or personnel error. If pri-mary to secondary heat removal is lost because of the loss of fe ed-water, the core energy is removed by the reactor coolant (HPI) and DATE: PAGE 8- & 82 97

BWNP-20007 (6-76) BABCOCK & WILCOX wumen 74-1122058-00 TECHNICAL DOCUMENT released to the reactor building, which serves as the heat sink instead of the stean generator. The core is kept covered and cooled by HPI. A total loss of all feedwater without operator action is illustrated and discussed in Figure 24a. l I A total loss of all feedwater with anticipatory trip and appropriate operator action is discussed below. The P-T response is shown in Figure 24b. . With the plant at power, a loss of main feedwater results in a reactor anticipatory trip, with post-trip cooldown and depressuri-zation (Points 1-2). NOTE: If the cause of the loss of main feedwater does not actuate the anticipatory trip, then the reactor pressure will initially rise to cause a high RCS pressure trip. i

                                                                                                           ]

If emergency feedwater also fails, the secondary side of the steam generators will boil dry and the RCS will then start to heat up due

       .to decay heat.       If AFW is not available this heating will continue.                           q l

RC pres sur e will increase as the steam space in the pressurtzer is compres sed due to the insurge of reactor coolant (Points 2-3). 1 DATE: 8-20-82 PAGE -4 98 I

                                                                                                           )
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l l BWNP-20007 (6-76) BABCOCK & WILCOX Numsta NUCitAR POWER GENERATION DIV1510N 76-1122058-00 C TECHNICAL. DOCUMENT Steam / water relief out of the ERV or the pressurizer safety valves will then occur. Subcoooling may initially increase due to the increase pressure, but it will later decrease towards saturation. NOTE: The rate at wh ich the above occurs will depend upon the initial inventory in the same generators and the core decay heat level. For example, the RCS heatup rate may be as high as 4F/ min with high decay heat or as low as IF/ min with low decay heat following boil off of the SG inventory. The event can be recognized by observation of gene ra tor level and equipment status checks or through use of the P-T diagram (Figure 24b). The operator should make every attempt to regain feedwater to at least one steam generator. This includes main fe ed wa t e r , emergency feed wa te r , auxiliary feedwater, condensate and booster pumps (if steam generator pressure is low enou gh) . If feedwa t er cannot be regained before primary to secondary heat transfer is lost, he should manually start two HPI pumps and open and leave open the ERV (Points 3-4). HPI flow should be balanc ed to give the maximum u flow possible. 5 When HPI is started the RCS will eventually go to a water solid con-dition ( subcooled) with RC pressure controlled by a combination cf the HPI pump head rise and the relief capability of the ERV. The v number of running reactor coolant pumps should be red uced to one to reduce the heat load. The P-T res ponse depends 'o n the type of l DATE: PAGE 8-20-82 99

                                                                                                                                 ,   1

BABCOCK & WILCOX NumsER NUCLEAR POWER GENERAfloN DIYt$10N TECHNICAL. DOCUMENT 74-ii22o58-oo reactor trip, core decay heat level, numbe r of operating HPI pumps and how quickly the operator diagnoses the situation and takes correct ive action. The initial res ponse is the same as a loss of main feed water until the EFW control se t point is reached on the OTSG 1evel and the generator begins to dry out. Following OTSG dryout, the RCS will begin to heat up and this will cause the RCS inventory to swell and pressure will increase. A high decay heat will cause the pressure and temperature to increase faster than a lower initial decay heat level. Pressure will cont inue to increase to the ERV setpoint unless decay heat is low and the operator starts to mitigate the transient soon after OTSG dryout (that is, starts two HPI pumps and opens the ERV). ( lk Two HPI pumps provide more t ime (af ter the ERV is opened) be fo re the RCS reaches saturation as compared to one HPI pum p. The sooner the operator acts, the less severe the early RCS systen tempe rature and pressure re s ponse s . The reactor coolant will usually saturate (Points 4-5) and RCS pressure will rise along the saturation curve (Points 5-6 on Figure 24b). The running RCP should be tripped when subcooling margin is lost. The water inventory in the RCS will drop because of core boiling and relief out the ERV, until the amount of water added by HPI can take away all the decay heat of the core. Until that time water from the RCS and HPI water together are needed to take out core heat. When the heat removal of the HPI water can take out all the decay heat, HPI is said to " match" decay heat. When DATE: PAGE 8-20-82 100 1

l BWNP-20007 (6-76) BABCOCK & WILCOX Num Ea NUCLEAR POWER GENERAfeON olVl510N 74-n 22038-00 C TECHNICAL. DOCUMENT HPI matches decay heat the liquid inventory in the RCS will start to increase, steam will be condensed and the system will slowly go to a water-solid ( sub cooled ) state (Points 6-7 on Figure 24b). Figure 24b is typical and is not necessarily the exact sequence of events during all HPI cooling transients. If the core decay heat level is low at the time feed water is lost, HPI may be enough to take out all the heat and the RCS may remain subcooled (water solid) until feedwater is restored. When all feedwater is lost it is very important that two HPI pumps be run until s ubcooling exists. One HPI pump is adequate for core heat ( removal, but the time required for one HPI pump to match decay heat is mu-h longer than for two pumps. The time to match 100% decay heat level with one HPI pump is approximately 70 minutes and approximately 8 minutes with two HPI pumps. When subcooled conditions (based on both incore thermocouples and hot leg RTD's) are reached, the operator should start one reactor coolant pump and throt tle HPI flow to maintain the reactor coolant subcooled s but within equipment design limits such as the brittle fracture limit of Figure 25, "RCS Pressure / Temperature Limi t s" . If a reactor coolant pump cannot be restarted the operator should s t ill throttle HPI to maintain an adequate subcooling margin and avoid exceeding NDT limits of the reactor vessel. The intent is to run a RC pump to m improve the nnal mixing and minimize the rmal shock to the reactor 1 DATE: 8-20-82 PAGE . l 101 i

BWNP-20007 (6-76) BABCOCK & WILCOX ,,,,, NUCttAt POwtt GENesATON Olvl510N TECHNICAL DOCUMENT 74- 22o38-oo (k vessel. However, if the pump is not ready in all respects to be run it should not be run. Core protection is assured by the HPI cooling. In summary, HPI cooling should be initiated if secondary heat removal is lost. It is not a normal operating mode for many reasons; three examples are:

1. The ERV will pass large amounts of saturated and two phase flow. Should the ERV fail to close when feedwater is re-instated, the ERV isolation valve must be closed.

2. Long-term operation (subcooled solid water operation) must be closely monitored to prevent exceeding equipment design limits (NDT and RV Brittle Fracture).

3. The degraded containnent environnent may cause failure or bad readings of instrumentation.

Conseque ntly, secondary cooling should be restored as quickly ( as I k possible so that normal primary to secondary heat transfer can be resumed. ( 1 i DATE: 8-20-82 PAGE 4 102

BWNP-20007 (6-76) BABCOCK & WILCOX ( NUcitAt POWER GtNERAfloN DIVI 510N Nuuset TECHNICAL DOCUMENT 7'- 22o58-oo Boiler-Condenser Cooling A subcooled reactor coolant system is the desired state, however, core heat can be removed when the RCS is saturated. The problem with saturated natural circulation is that the operator doesn't know how

   ./

much of the reactor coolant is sheam and how much is water (see discussion of saturation in Addendum A of Chapter A). If the RCS is losing inventory, steam will form in the hot legs and eventually stop l natural circulation flow (this is a viola t ion of the su'ucooled natural circulation requirement that a flow path exists connecting the hot water and the cold water. .This could also be violated by a large collection of non condensable gases in top of the hot legs, f however, such a collection could only exist following a core ( uacovery. At that point the operator would be using inadequate core cooling procedures). Another form of core heat removal could still exist under these conditions called core boiler-condenser cooling (boiling in the core and condensing in the steam generator) but it requires a higher steam generator level (95% on operate range). w Figure 27 illu s trates boile r-condenser cooling. In this mode of 4 cooling, wa ter is boiled in the core. The resulting steam flows through the hot leg pipe to the steam generato r where the steam is condensed in the cool steam generator tubes. The condensed water flows back to the reactor core. In order to flow back to the core the elevation of the RC water level in the steam generator must be DATE: PAGE 8-20-82

BWNP-20007 (6-76) BABCOCK & WILCOX NUCLEAR POWER GENERATION DIVl510N NuuseR TECHNICAL DOCUMENT 74- 22058-Oe above the e1.evation of the RC pump discharge pipe. This will allow the water in the cold leg pipe to flow up and over the RC pump discharge into the core. The RC steau entering the SG is condensed on the inside tube surface l[k between the RC and SG water level. This tube surface has to be large enough to remove all the latent heat of the s teau at the expected RC steam flow rate. The amount of condensing surface is determined by the seconda ry s ide water level. The s tean generator tubes will condense the RC steam if the cooler feedwater is on the outside of the tub e s. To make the condensing surface above the required RC water level high enough the steam generator water level must be at ( 95% on the operating range. lk The problem with boiler-condenser cooling is the ope rato r does not know the RC water level in the steam generator. The re fo re , to assure enou gh water exists the operator should have both HPI pumps on at a high capacity. If a LOCA occurs and the size is such that both stean generator and HPI cooling are needed to remove the core heat but subcooled natural circulation is lost, the RC will heat up and repressurize causing the pre s s urizer sa fe ty valves to open and relieve RC to the reactor building. This will continue until the RC water level drops below the steam genera tor feedwater level to expose su f ficient condensing surface to the RC stean. With the feedwat er level 'at 95%, the RCS DATE: PAGE is - 8-20-82 104

i l BWNP-20007 (6-76) BABCOCK & WILCOX ( NUCitAt POWf t GENERAfsoN DIVISION my,f, TECHNICAL DOCUMENT 74-1122058-00 will inherently go into boiler-condenser cooling as the RC level in the s tean generators boils down below the feedwa ter level to expose the condensing tube surface. HPI flow will be needed to makeup for RC lost out the break. ( . 1 (/ If eme rge ncy feedwater is sprayed into the stean generator the effective condensing surface of the steam generator tubes is much higher than the 95% level because the EFW spray will be cooling the tube surface above this level. However, if the main feedwa ter is used to ad d wa te r to the steam generators, the feed wa ter enters the bottom of the steam generator so that the only condensing surface is ( at or below this 95%. k If boiler-c ondense r cooling exists Thot should be equal to primary T sat and the incore thermoucouple t empe ra ture , and Tcold will be equal to the SG saturation temperature. r The point to remember is that primary inventory (mass) is unknown under saturated conditions and there fore, every effort should be made C to keep the RCS subcooled. ,i-. k e ,, v DATE: 8-20-82 PAGE  ;; _g

                                                      .                                                            105 a!

BWNP-20007 (6-76) BABCOCK & WILCOX NUCitAt POWit GENteATION DIYl$loN - 74- 122038-00 TECHNICAL DGCUMENT

~'

Restoration of Natural Circulation l When RC pumps are off, heat is removed from the reactor core by natural circulation as discussed in Addendum B. Some abnormal tran-sients can lead to a loss of natural circulation but methods exist to restore it if it is lost. The intent of this section is to highlight the recovery measures and to give an understanding of why certain actions are recomme nded and when they are to be taken. Brief discussions of other issues on natural circulation are also provided.

               ' A loss of natural circulation can occur for two rear,ons, which are:                                     l Reason 1. Insuf ficient secondary inventory control (i.e. , not enough feedwater).
 , : un ,                        c m        :>        Reason 2. Fonnation of steam voids within the hot leg which are of sufficient volume to block water flow to the steam generator (i.e., not enough reactor coolant).                                            l
     .-   :u The previous section addressed system operation when natural circula-                                l(

k tion is lost due to insufficient feedwater (Reason 1). The only way I to recover natural circulation under that condition is to restore feedwa te r. Void formation (Reason 2) is more complicated because the reactor coolant system can operate dif ferently depending on what has < l ( DATE: 8-20-82  ; PAGE 106 Ul

l BWNP-20007 (6-76) BABCOCK & WILCOX ( HUCLEAR POWEa GENERAfloN DIVI $loN TECHNICAL DOCUMENT 7'- 122058-00 happe ned . The two principal events which lead to void formation are overcooling transients and loss of coolant accidents. For these transients, voids are formed in the following manner: (/ j Overcooling: Too much primary to secondary heat trans fer c auses a drop of RCS temperature which causes a contraction of fluid inventory, a decrease in reactor coolant pres-sure, and a loss of pressurizer liquid. Some of the steam in the pressurizer flows into the RC piping and collects in the hot legs. Because the RC pressure drops, some of the reactor coolant may flash and cause ( void formation in the hot legs. k LOCA: A LOCA results in a loss of RC inventory and a reduced RC pres sur e. Void s are formed directly as a result of loss of RC inventory and also because of flashing of the reactor coolant as RC pressure drops. The RC temperature does not drop as much as it would for an overcooling event. r L Figure 26 illustrates the buildup of stean voids and the formation of

                 - a steam bubble in the upper hot leg piping.
                                                                        )  \

The size of the steam bubble vill depend on the rate of system over-cooling or loss of inventory versus the rate at which HPI adds wr.ter v DATE: 8-20-82 PAGE . 107 _ _ - - _ _ - _ l

BWNP-20007 (6-76) BABCOCX & WILCOX Numsen NUCLEAR Powta GENtaAfloN DIV111oM TECHNICAL DOCUMENT 74- 122058-o0 to the RCS to refill it. If HPI flow is large compared to the contraction and inventory loss no steam bubble will form at all and natural circulation will not be lost. If a steam bubble does form its size has a direct effect on primary to seconda ry heat t rans fe r. If the bubble is big enough such that the hot leg level is at or below the secondary side feedwater level then stem can be condensed within the stem generator tubes and the steam generators can still remove a large amount of decay heat. This is a boiling mode of natural circulation (boiler-condenser cooling) and is illustrated in Figure 27. Boiler-condenser cooling is an expected small break LOCA condition. If the stem bubble is smaller and steam cannot be condensed in the steam generator tubes (see Figure 28) then primary to secondary heat trans fe r will be much lower. In this condition the RCS may heat up and might repressurize. Several examples of transient conditions that could get into this mode of operation are:

1. Small LOCA's where HPI can match the leak rate (at reduced RCS pressures) and refill the RCS.

2. A severe overcooling event (e.g., major stem line break) in combination with delayed actuation of HPI.

3. A total los s of feedwater, where feedwater is restarted after the itCS is in a highly voided condition and the HPI is refilling the RCS.

                                      ~

BWP-20007 (6-76) BABCOCK & WILCOX Numen NUCLEAR POWit GENERATION DIVISION 74-1122058-00 TECHNICAL DOCUMENT Figure 27 shows boiler-condenser cooling (boiling in the reactor vessel and condensing in the steam generator tubes) with a saturated hot leg and RCS pressure near the stean generator pressure. For this condition, it is important to ensure that 1) SG level is at 95% on the ope rat ing range (to allow the condensed reactor coolant to flow

  /

over the cold leg pump elevation and into the core) and, 2) HPI is on at a high capacity (two pumps) . A check of containuent pressure and temperature conditions should also be made to see if the cause is a LOCA. If LOCA conditions are indic a t ed , an immediate plant cooldown at design rates (100F/hr) should be inititated. The P-T diagram should be monitored to see if subcooled natural circulation returns ( or boiler-condenser cooling is lost. If natural circulation has been lost and steam cannot be condensed in the steam genera tors (that is, the steam bubble is in the top of the hot leg pipe, (" candy cane"), but not low enou gh to be in the steam generator tube region) the RCS will repressurize. This mode of opera-tion will be indicated (see Figure 28) by satur a ted hot leg condi-tions with Reactor Coolant pressure above the steam generator s pres sure (SG pressure may be dropping due to lack of primary to secondary heat transfer). As indicated in Figure 28 the same actions identified for boiler-condenser cooling apply to this operating mode. In this mode, the HPI is refilling the RCS. During refill, steam in the upper region of the hot leg piping will be compressed and/or con-

%               densed as the water level in the loops and steam generator rises.                                                          In DATE:           8-20-82                                                                                              PAGE         109   a
                    .:                                                                                                                          \

BWNP-20007 (6-76) BABCOCK & WILCOX Nuuien NuctEAR POWER GENERATION olVISION TECHNICAL DOCUMENT 7eti22038-00 some cases (i.e., low decay heat with both HPI pumps on) subcooling and natural circulation will occur with minor increases in RC pressure. Under other circumstances, it may be dif ficult to fully condens e the stean in the hot leg and restore natural circulation. Figure 28 shows the actions to take to restart natural circulation if the e t ean generator can be used as a heat sink and the RC pumps are available for restart (see the RC pump restart guidelines in the "Best Methods for Equipment Operation" chapter) . If the RC pumps are available, pump bumps (short run times of 10 seconds duration) are allowed. This momentary use of forced circulation t r ie.3 to force reactor coolant steam condensation by mixing it with liquid reactor coolant and by moving the steam into the generator tubes where it can condense. Use of the ERV to limit RCS pressure rise and to inctease HPI flow is also allowed (separatly or in conj unct ion with RCP ope ra tion) . To be effective the steam generator must be a heat sink; the steau generator saturation temperature selected is somewhat arbitrary; it was chosen to ensure a strong temperature gradient for condensation. khen the pumps are bumped and steam is condensed the RCS pressure will drop as much as several hundred psi. HPI flow will increase to help refill of the voids. If natural circulation starts

           ~

the RC pressure will stay low; if natural circulation does not start the RCS will repressurize and another bump can be used about 15 minutes later (see the pump restart guidelines). DATE: 8-20-82 PAGE 110

l l BWNP-20007 (6-76) BABCOCK & WILCOX ( NUCitAR POWER GENERATION DIVISION TECHNICAL DOCUMENT 74-1 22058-00 Finally, a LOCA of a certain size could depressurize the RCS below the steam generator pressure before it settles to an equilibrium with HPI (HPI will automatically start because this size LOCA will drop pressure below the ESAS setpoint). If this happens the operator should lower the steam generator pres sur e (using the TBS or ADV

    /

valves) until the saturation temperature on the secondary side is 50F below the primary saturation temperature. This will ensure the steam generators are heat sinks. Other actions are the same as discussed above for boiler-condenser cooling (Figure 27). f ( w 4 DATE: 8-20-82 111 ')

BWNP-20007 (6-76) BABCOCK & WILCOX Nuuset NUCLEAR POWER GENERAT6oN DIVI $ ION TECHNICAL DOCUMENT 74- 122038-00 Inadequate Core Cooling (ICC) The first object ive of the operator during any abnormal transient is to keep the core cooled. As discussed in Addendum A, core cooling is t aking place wheneve r the reactor coolant is in a subcooled or saturated state and the core is covered. If the reactor coolant becomes supe rh e a t ed , the core has been uncovered and is not being adequately cooled; that is, decay heat is not being removed fast enough and the tempe ra ture of the fuel and cladding are increasing. This, in turn, causes the reactor coolant to heat up, flash to steam, and become superheated. Inadequate core cooling is not expected. However, any transient can become an inadequate core cooling event if enough equipment failures hap pe n. These events have a low probability of occurrence. Some examples where ICC conditions could develop are:

1. Small LOCA with a total failure of the HPI system.

2. Total loss of feedwater (Main, EFW and AFW) with a total failure of the HPI system.

3. A total loss of power (including a failure of both emergency generators to start) with a failure of the steam turbine-driven EFW pump to run.

e DATE: PAGE +1 8-20-82

BWNP-20007 (6-76) BABCOCK & WILCOX ( NUCLEAR POWER GENfRATION OlVl$loN 7'- 22058-oo TECHNICAL DOCUMENT

4. During a small break, tripping the RC pumps at a time period when the RC void fraction is about 70% or greater.

l The intent of the Inadequate Core Cooling (ICC) guidelines is:

1. To allow the operator to identify when core cooling is inadequate.

2. To provide the operator with a way to es t imate the severity of the accident.

3. To identify those systems which are vital so that the operator's attention will be focused on these items in his attempts to re-establish core cooling.

4. To identify some known alte rnative actions to try to correct or minimize the consequences of the accident until normal cooling can be re-established. These actions are , based on the severity of the accident.

s

          ,                 ICC is indicated when the reactor coolant pres sur e and temperature (incore thermocouples) enter the superheat region.                                                                                                  This condition can occur with or without forced circulation.                                                                                                If the RC pumps are operating superhea ted conditions imply that the reactor coolant is u                         nearly all s t ean (see Figure 24a-Time IV).                                                                                              That is, the liquid in DATE:

PAGE 8-20-82 113 " "~' { 1

BWNP-20007 (6-76) BABCOCK & WILCOX wounta NUCLEAR POWER GENERAfsON DIVI 510N TECHNICAL DOCUMENT 74- 22038-00 the RCS hac been lost, due to a leak in the primary system or boiled off out the safety valves or ERV by decay heat, and the steam mass left within the system is not enough to remove core heat even though it is circulated by the RC pumps. When the RC pumps are off, core cooling is accomplished by keeping the core covered with a s t e an-wa te r mixture. If not enough cooling water (HPI) is supplied to make up for losses, the core will become uncovered and the core exit fluid temperature will become supe rhe ated (see Figure 24a - Time IV). Superheated t em pe ra ture s , as indicated by the core exit the rmo-( couples, are ICC symptoms. (NOTE: Incore Thermocouples are the only valid temperature measurement when the RC is not circulating.) These indicators can also be used to estimate the extent of inadequate core cooling. Analyses have been performed which show the rela t ionship between core exit steam temperature and fuel cladding temperature for various RC pressures (see Figure 29). This figure gives the following information:

1. When the RCS P-T conditions are supe rh eated but to the left of curve 1 on Figure 29, an ICC condition exists but it is

                                 ' not severe enough to cause core damage.

DATE: i PAGE 8-20-82 114

l BWNP-20007 (6-76) I BABCOCK & WILCOX NUcttAt Powet GENttAtlON DIYl$10N lC TECHNICAL DOCUMENT 7'-t122058-o0

2. If the RCS P-T conditions reach or exceed Curve 1 on Figure 29, the cladding temperature in the high power regions of the core may be 1400F or highe r . Above this temperature, there is a chance for rupture of the fuel rod cladding material . A chemical reaction between the cladding and the water at high temperatures also occurs and will add heat to the fuel rods increasing the chances of fuel failure. The clad-water reaction also causes free hydrogen formation which collects in the reactor loops and may escape to the building. The accumulation of hydrogen in the RCS can also block natural circulation when water is added to the RCS.

( (

3. If RCS P-T conditions reach or exceed Curve 2 of Figure 29, the cladding tempera tures in the high power regions of the core may be 1800F or higher. This is a very se riou s condition. At this level of ICC, significant amounts of hydrogen are being formed, and core damage may be unavoidable. Extreme measures are wa r-

 ,                                      ranted to prevent major core damage, s

If an ICC condition develops, the operators should try to get equip-ment working to supply water to the reactor and/or steam generator. The general strategy during ICC should be as follows: v DATE: 8-20-82 PAGE 115 .

                                .                                                                                              )

l BWNP-20007 (6-76) BABCOCK & WILCOX NUCttAt Powta GENERAflON DIVI $10N 74- 122038-00 TECHNICAL DOCUMENT

1. To check vital equipment e All available HPI should be on with flow into RCS. For a total loss of feedwater, the HPI must be manually started.

ESAS will not be actuated automatically since RCS pressure does not decrease. e FW should be flowing to at least one steam generator with level at 95% on operating range level instrumentation.

2. Start any backup equipment to correct for problems found in vital equipment check.

e Start standby MU/HPI pumps, e Take suction from any available borated water source. e Start AFW pumps if EFW or MFW is not operating. e Start any backup pumps which can supply oater to the steam l(( generator if MFW, EFW, and AFW are not operating.

           '          s q   t

3. Minimize the consequences of the event if conditions degrade, a -

e Start a RC pump to circulate primary system fluid (water or steam) through the core. This action will make available water trapped in the lower region of the reactor vessel and

                                                                               ;, o        e the loops for core cooling (see Figure 24a                             -

TIME IV) and l( e provide improved heat transfer due to forced convection which k I will provide additional time to restore emergency injection.

               =:       r               --
                                                                           .v, u

8 U G l <* ^ ji l I 1

                                                                                                                .                           l DATE:                                                                                                PAGE               m 8-20-82                                                                                '116           .
                                   .:                                                                                                    ,i
 .-___-__                                                                                                                                   l

BWNP-20007 (6-76) BABCOCK & WILCOX l Numsta HUCLtAR PoWit GENERAftoN Olvi510N 7'*- n 220ss-oo C TECHNICAL DOCUMENT e Attempt to decrease RC pressure by opening the ERV in order to increase the rate of available high pressure injection. e If secondary cooling is available, decrease primary pressure by decreasing SG pressure. This action is directed at making i the core flood tanks and LPI system available to restore core cooling. In general, the ICC strategy depends on operator action to locate and correct the cause of low RCS inventory or to take alternate actions to make backup sources of cooling water available. Some of the actions identified above can be detrimental to major componen t s , and others carry a certain amount of risk, but keeping the core cooled is the first priority. For example, an eme rgency cooldown/depressuri-zation of the system may impose high thermal stresses on the SG internals; this action can be shown to be acceptable but it ch alle nge s the design to its limit. A second example would be the restart of one or more RC pumps. This action carries some risk be- , cause later on a pump trip may leave the RCS with less water than be fore . These risks are small compared to those which could happen s with extensive core damage. .Because the severity of the ICC condi-

     +i ', " tion can be es ti nated (by using Figure 29), the appropriate actions mC      '

have been picked so that the risk of the action is small compared to the consequences if the action is not taken. These actions are v DATE: 8-20-82 PAGE i to g

BWNP-20007 (6-76) BABCOCK & WILCOX . . , NUcttAR POwta GENteATON DIVISCN 7'- 122058-On TECHNICAL DOCUMENT outlined below and are based on where the RC pressure-incore the rmocouple tempera ture (P-T/C) combination corresponds to the curves of Figure 29. If the P-T/C combination is between the saturation curve and Curve 1 superheated conditions exist and the operator should: 1

1. Verify emergency cooling water is being inj ected through all HPI '

l

                     -nozzles into the RCS.

2. Initiate any additional sources of cooling water available such as the standby makeup pump.

3. Verify the stean generator level is being maintained at 95% on the operate range. If steam generator level is not at 95% of operating range, raise level to the 95% level.

4. If the desired steam generator level cannot be achieved, actuate any additional available sources of feedwater.

5. Establish 100F/hr. cooldown of RCS via steam generator presstire control unt il seconda ry steam saturation tempe rature is 100F

                                                                                                                                                       \

below the incore thermocouple temperature. l(b f

6. Open core flooding line isolation valves if previously isolated.

o: m. .7.. If. RC pressure increases to 2300 psig, open the ERV to reduce RC m; mo:, 5 pres sure and reclose the ERV when RC pressure falls to 100 psi above the secondary pressure. O DATE: 8-20-82  ; PAGE Ud 118

l BWNP-20007 (6-76) BABCOCK & WILCOX my,,, NUcttAt POWER GfNitATION DIVI $10N C TECHNICAL DOCUMENT 74- 122058-00 These actions are directed toward depressurization of the RCS to a pressure at which the ECCS water input exceeds core steam generation. The alignment of other sources of cooling water is the recognition 1 that the inject ion of the HPI system alone is not su f ficient to i exceed core boil off. If the P-T/C combination is between Curve 1 and Curve 2 of Figure 29, the operator should do the following: l

1. Start one RC pump in each loop; do not defeat RC pump interlocks.

2. Depressurize the steam generator as rapidly as possible to 400 ps ig or as far as necessary to achieve a 100F decrease in se-condary saturation temperature, but not below the steam pressure l

necessary for the EFW pump turbine to deliver EFW.

3. Immediately continue the plant cooldown by maintaining a 100F/hr cooldown rate until the secondary sa tur a t ion temperature is low enough to achieve a 150 psig RC pressure.

e

4. Open the ERV , as necessary, to relieve RCS pressure and vent non-condensible gases.

L The operator action in starting the RC pumps will provide forc ed flow core cooling and will reduce the fuel cladding temperatures, v l DATE: 8-20-82 PAGE , g9

BWNP-20007 (6-76) BABCOCK & WILCOX Numset HUcitAR PowtR GENERATION DIVIStoN ' 74- 22058-00 TECHNICAL DOCUMENT 4( The rapid depressurization of the stean pressures will help to depres-surize the primary system to the point where the core flood tanks will actuate. Stopping the depressurization at 400 psig (or as far as necessary to achieve a reduction in secondary saturation temperature of 100F) will maintain the OTSG tube to shell temperature l(. k difference within the design limit. The continued cooldown to 150 psig will reduce the primary systen pres sur e to the point where the Low Pressure Injection System can supply cooling. The opening of the !- ERV will also help to depressurize the primary system. The ERV should be closed when the primary pressure is within 50 psi of the secondary pressure and then should be used only as necessary to maintain the primary system pressure at no greater than 50 psi above the secondary system pressure. This method of operation will minimize the loss of water from the primary system through the ERV. l

                                                                                                                    ?         <

If the P-T/C combination is to the right of Curve 2 of Figure 29, the operator should: ~.

1. Depressurit.a the stem generators as rapidly as possible down to I(V

                                           o.                     Iow pressure while ensuring sufficient steam pressure remains in 5

the stean generators to operate the turbine driven EFW pump. (If 1 AFL' is available, then depressurize the steam generators to as low a pressure as possible.) DATE: i PAGE g I T/,ti i __ _ _ . - . _ . _ _ _ _ _ _ _ _ _ _ _ _ - - - - - - - - - ' - ' - - - - - - - ' ' - - - ~ - ' - - - - - - - - '

I ' Tanle 4n SYuPTORS FOR LOCA'S VHAV CAN BE LOCAVED OR IS08.ATED This chart will alj in locating some breaks; all breaks cannot be located. Some breaks which can be located can also be isolated and the LOCA can be stopped. It may be difficult to distinguish small steam line leaks inside containment from LOCAs; building environment will change for both and the steam pressure will not always be low. However, a LOCA will change building radiation levels. SYMPTOMS FOR LOCA'S THAT CAN RE IS01ATFD SYMPT 0MS FOR LOCA'S THAT CANNOT RF TR0fATFD (Symptoms or alarms most likely to show location are underlined) (Symptoms or alarms most likely to show location are underlined) FAff tPF l0CATING SYMPTOMS f50 FATING W RnUARE FAff Mr LOCATING SYMPTOMS Nakeup and purification - Low makeup tank level LetdownvalveupI8) Steam Generator Tube (s) - High steam line radiation system outside containment - liigh ICW radiat. ion (for let- stream of coolers (for - High steam generator Tevel and letdown coolers down cooler on.lyl letdown cooler only)

                                        - High ICW su_rge tank level

{for break's in letdown cooler) Pressurizer Safety Valves - Acoustic Monitor Alann

                                                                                                                                           - High quench tank level
                                         - Local sump levels, radiation
                                                                                                                                           - Ifigh quench tank temperature alarms

{The last two will only be good while the quench tank rupture Seal return line and seal - Low makeup tank level Seal return isola-(a) disk is good) return cooler outside con- - iiiqE TCW radiation tion valve

                                        - High !CU surge tank level                                                                        - Flow imbalance between injection (C}
                                                    ^

tainment HPI Injection Line Break Tfor breaks in seal return lines fl w will be through broken

                                        -             ump levels, radiation                                                                         )

alarms - High seal return temperature (s3500F)

                                         - High seal return flow                                       RC Pump Seal Failure combined with:

Low stage and upper stage pressures Pressurizer electromatic - Acoustic Monitor Alarm ERi isolation valve are equal and high relief valve - IIIgh quench tank. lev'eT

                                        - High_ quench tank temp-erature TThese will only be good                                   RCS Instrumentation Lines
                                                                                                         - Pressurizer Level              - False low level reading u u d              d)                                      - Pressures                       - False low pressure
                                                                                                         - RC Flow                         - False high or low flow compared with Makeup-letdown imbalance             - Hinh makeup tank level             letdown control valve (a)                                        Fnown pump operation (this is not a break, but            -B~lMIToTduptanklevel is a loss of coolant)                - Makeup flow rate (+) seal injection flow (-) letdown flow Decay heat removal line              - H.igh or low decay heat removal    Decay heat letdown (b)    Footnotes break outside containment                flow                             drop line valve (decay heat removal system           - E i pump suction press.                                      (a)Do not allow makeup cank to drain or operating makeup pump will lose in operation-plant is cooled - IFcal sump and local radiation                                           suction and fall.

down) alarms (b) inadequate Core Cooling Guidelines for l'oss of decay heat removal Decay heat cooler tube leak - Radiation above nonnal in the Cooler isolation valves should be implemented. (decay heat removal sys. SW discharge to the Lake or in operation-plant is cooled Emergency Pond. (c) Break cannot be isolated to prevent loss of reactor coolant, but down) the HPI line can be closed to prevent loss of injection water. d i &\ p

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BWNP-20007 (6-76) 8ABCOCK & WILCOX ( NUCLEAR Powta GENtaAflON Divi $lON TECHNICAL DOCUMENT 74-1122038-00

2. Start the remaining RC pumps. Defeat starting interlocks; do not

                                                                                                                                               ~

defeat the overload trip circuit.

3. Open the ERV and leave it open.

fNJ') The goal of these actions is to depressurize the RCS to a level where the core flooding tank s will fully discharge and the LPI system can be actuated, thus providing prompt core recovery. After reaching ' Curve 2, significant core damage may have occurred which will add significant radioactive contaminants to the reactor coolant and the contairunent (via the ERV). f. L Special cooldown precautions need to be followed to contain these contaninants, such as isolating pu rooms in the auxiliary building. J l l L A. 5 l-P l l l DATE: PAGE ^, 8-20-82 121

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Figure 24b BACKUP COOLING BY HP1 FOR LOSS OF ALL FEEDWATER (WITH OPERATOR ACTION) 2500 POST TRIP 3 24H - 91ND0s 2200 - _ 7 j L_ __ f SUIC00 LED i j Gf0 REGION 2 I 1800 - E l,

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                                                                                       /6 2                          END POINT-POST TRIP tith 1200   -

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           -                                                                                     NORM AL OPER AilNG POINT P0BER

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  ,                                                                                  'F~]    END POINT POST TRIP WITH 500   -                        i            !                           t ,, j NATURAL CIRCUL Ail 0N

• TH0T'

                                             - SUIC00 LEO 400                                MARGIN LINE I               I                 I                     I                  i 450             500               550                   600                650            TOO 400 Reactor Coolant ana Steam Outlet Temperature F
       ~

Reference . Time  ; Points (Minutes) Remarks 1-2 0-1 Reactor tripped on anticipatory loss of feedwater. Hormal post-trip cooldown and depressurization in progress. EFW doeson_ot initiate. 2 1-2 Steam generators dry. RCS begins to reheat and repressurize due to loss of secondary cooling. EFW cannot be started. 3 3-4 Operator diagnoses loss of heat transfer, opens ERV, starts two HPI pumps and balances HPI flow. ERV release rate exceeds HPI capacity initially and RCS begins to depressurize. Operator trips all but one RC pump to reduce heat input.

                  ' 4                   S-6       Subcooiedmarginislost. Operator trips remaining

• RC pump.

5 6-7 RCS reaches saturation. 6 7-8 Pressurizer in solid or near solid condition. HPI flow " matches" decay heat and begins to repressurize RCS to subcooled conditions. 7 8-10 RCS subcooled margin restored and RCS is beginning to cool due to HPI flow and ERV release. Operator throttles HPI flow to maintain subcooled conditions at a pressure lower than the safety valve setpoint and restarts an RC pump to promote themal mixing 4-1122058 ,00 _ ,; of HPI to minimize themal shock.

Figure 25 RC PRESSURE / TEMPERATURE LIMITS 2400 ADJUSTMENT FOR POSSIBLE INSTRUMENTATl0N ERROR f 2200 HAS BEEN CONSIDERED FOR THESE P T LIMIT CURVES. f, OPERATING CON 0lil0N ACCEPTABLE REGION 2000 - NO FORCED FL0s ---- ------ 11 ONLY / FORCED FLOW------- -- - -- l & il I [ 1800 REGION I REGION 11 / f _ 1600 - - . 1400 .

             -5 I                                        /

f f 1200 THERNAL / 1000 u5 NOT LlulTS

                                                         \[                                             /          ADEQUATE "600 UNACCEPTABLE
                                           -                                                )

[ R UNACCEPTABLE 400 - 200 I / j ' REFER TO THE CURRENT AND-l 100 200 300 400 500 600 700 TECHNICAL SPECIFICAil0NS FOR THESE NOT LIMITS. RC Temperature (*FJ l l e l i ,4-1122058-00 l l -

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       =a                                                                                                                         NOTES ON P-T DIAGRAtl s             "'."i.""

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i ""*'" 'u'a ! 1. RC pressure is slightly i

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pressure. 3 . 1 v,

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OPERATOR ACTION REQUIRED

l. Turn HP1 on to highest flow ra,te.

I

2. Verify EFW flowing through upper nozzles and raise steam generator level to 95% on operate range.

3. Start plant cooldown at 100F/hr.

t

4. Monitor plant conditions for a loss of core boiling /SG condensing or 4

a return to normal natural circulation (subcooling). 4-1122058-00 f m . .

i Figure 28 LOSS OF NATURAL CIRCULATION - SYSTEM REFILL BY HPI

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1. Thot is-equal to Tsat for existing RC pressure.

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2. RC pressure will increase

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3. Steam pressure may drop LJ * '* "'" because heat transfer from

            ,                   y                  ;           ,,            ,',,               ,',                  ,,,                            reactor Coolant is low.                                      .
                                                         ,,,...v.......,

t i OPERATOR ACTION REQUIRED

1. Same as boiler-condenser cooling.

I

2. Establish the steam generators' as a heat sink (SG T should be about 50F less than the incore thermocouple temperature). sat e Open ERV e Bump one RC pump -

5-1122058-00 ,

                                - . . . a - n .-                  atua.aumaa

Figure 29 CORE EXIT FLUID TEMPERATURE F0F' INADEQUATE CORE COOLING

                                                                            ~

I 2600 2C 2400 - SUPERHEATED RC ' SU8C00 LED 2200 , TCL AD > 1400F f 1800 - 2 REGION 1 REGION 2 REGION 3 [ 1600 - 2 5 1400 - D l - y, 1200 - T CLAD M 8 1000 - 8 REGION 4 800 - E s I 5 l 1 600 - 8 400 - 1 200 400 500 600 700 800 900 1000 1100 1200 1300 i Core Exit inermocouple Temperature (F) f4-1122058-00

1 BWNP-20007 (6-76) BABCOCK & WILCOX NUCLEAR POWER GENERATCH DIVISION C TECHNICAL DOCUMENT 74- 22038-00 CHAPTER E l 3EST METHODS FOR EQUIPMENT OPERATION During an abnormal transient the operator has to perform several actions to control dif ferent systems. This section will discuss the bast methods for operation of equipment for the following situations: e Start end Stop RC Pumps e Throttle or Stop HPI e Throttle or Stop Emergency Feedwater e Stop Main Feedwater e Use the Incore Thermocouples e Cooldown with One Generator out of Service . M - - RC Pumps -" - m -d During the course of an abnormal transient the RC pumps may need to ed> r-be stopped and at a later ' time may be restarted depending on the kind Ii- of transient and 'the conditions of the reactor coolant system. i;.w  ?: , ni;, I h In general the reasons for stopping the pumps are: I - - e To prevent pump damage -

• k e To prevent possible core damage if a small break LOCA occurs

    'J! af              '-      'e To decrease the heat input into the RCS 1.n
      .          L~     : s :,3                     .. i   .i  -:     us i.<           -

In general the reasons a pump should be restarted are: 1' e To start natural circulation if it has stopped u o To allow a faster rate of cooldown and RCS depressurization 7 , aa

DATE

'PAGE ifM 8-20-82 . , 122 -

_: .L - _. c X a:JJ

BWNP-20007 (6-76) BABCOCK & Wil.COX NumeEn NUctEAR POWER GENER ADON DIVl$lON TECHNICAL DOCUMENT 74- 22o58-oo e To provide core cooling if the core has become uncovered (inadequate core cooling) e Prevent brittle fracture of the reac. tor vessel when the reactor coolant is subcooled without forced circulation. This section will show the rules and guidelines for stopping and ( restarting RC pumps. I RC Pump Trip RC pumps must be tripped during a small break LOCA if the subcooling margin is lost to prevent core damage. If the pumps are kept running 1 they will force stean and water by the break; because the water is forced by the break more reactor coolant mass will be lost out the a mg s break , than if the pumps were not running. If the pumps are tripped t ., j ,. H -later in the transient time, when insufficient liquid remains in the RCS, .the steam and water remaining in the vessel and loops will separate, (steam will collect in the high points and water will collect in the low points). If enough water does not collect in the vessel the core will be uncovered. and will not be adequately cooled. l(

             .n  . Core damage can result.         Analyses show that a later pump trip can be dangerous, but an early pump trip is safe.                  However, as long as the                              l pumps continue to run the core will be cooled by the steam and water mixture circulating through the core.

ri ei. ,a- - e The RC pumps must be tripped upon loss of subcooling margin. A loss of coolant accident will nearly always cause a loss of subcooling DATE: 8-20-82 f PAGE,, EAG-u -

E'JNP-20007 (6-76) BABCOCK & WILCOX NUMBER NUCLEAR POWER GENERAfloN ofVl5foN 74-1122058-00 C TECHNICAL DOCUMENT margin. Other transients, such as severe overcooling or loss of all j J feedwa ter can also cause loss of subcooling margin. Because the effects of failure to immediately trip RC pumps during a LOCA can be ve ry se riou s, the operator should trip the pumps on the loss of sub-cooling margin without trying to find out the cause first. Cj To avoid failures which may cause the pumps to trip late (with core damage), the following rule is given: RC PUMP TRIP RULE 2 . f The RC pumps shall be tripped k immediately whenever the subcooling margin is lost. NOTE: IT IS ABSOLUTELY MANDATORY TO TRIP THE RC PUMPS IMMEDIATELY BUT IF THE PUMP ARE NOT TRIPPED IMMEDIATELY (I.E., WITHIN TWO MINUTES) WHEN THE SUBC00 LING MARGIN IS LOST IT IS MANDATORY THAT THEY SHOULD NOT BE TRIPPED AT A LATER TIME. THE OPERATOR MUST MAKE SURE E THAT COOLING WATER AND ' SEAL ^ INJEC ION ARE WORKING TO PREVENT PUMP 3 DAMAGE. THESE SERVICES MUST BE MAINTAINED FOR SEVERAL HOURS. IF -

n i! ,

u e MECHANICAL DAMAGE TO THE PUMPS IS LIKELY THEN TWO PUMPS (ONE IN EACH 9 LOOP ) SHOULD BE STOPPED. THE TWO REMAINING PUMPS MUST BE KEPT

                                                  . 3, RUNNING.      IF THEY 7 AIL THE TWO PUMPS WHICH WERE STOPPED SHOULD BE STARTED EVEN IF MECHANICAL DAMAGE IS LIKELY.          THE OPERATOR MUST ALSO e

TRY TO GET AS MUCH HPI FLOW INTO THE RCS AS POSSIBLE. r DATE: 8-20-82 PAGE  ;;q

                 .:                                                                               . + : z :1.s

BWNP-20007 (6-76) BABCOCK & WILCOX NUCLEAR POWER GENERAflON Olvt31oM I TECHNICAL DOCUMENT 74-1122058-00 The RC pumps can be tripped to prevent mechanical damage in all cases except the one noted above and during severe ICC. Mechanical damage is not expected to cause safety problems unless total seal failure occurs . It is desirable to trip the pumps to prevent mechanic al damage in ( case they must be restarted at a later time. Preserving the pumps for long-term cooling or cooldown is desirable, and it is recommended l that they be shut down if high vibration or loss of cooling services occurs. Limit s on continued pump operation are given in the " Plant ? Limits and Precautions". These limits apply to normal and emergency services. Table 5, " Rules for RC Pump Trips" summarizes these requirements. Included in this table are the limits on pump operation due to l l f ailures of cooling water and seal injection. L When the RC pumps are tripped to prevent mechanical damage, emergency ( feedwater will be automatically started and the stean generator level setpoint will be changed to 50% on the operating range. The operator 1 t should make sure that natural circulation starts. If intermediate l cooling water is lost, time exists to raise the water level before l . the pumps are tripped. If the pumps are tripped on loss of l l l l DATE: PAGE 8-20-82 ,

                          -                                                             125

BWNP-20007 (6-76) BABCOCK & WILCOX . . , NUCLEAR POWER GEHERADON DIVIS80N C TECHNICAL DOCUMENT - 7'- 22058-00 subcooling margin, natural circulation may or may not start depending ' on the amount of steam in the RCS. Nevertheless a check on natural circulation is desired. Actions to establish natural circulation when the pumps are tripped because of subcooling margin are given in f) the pump restart guidelines which follews. k f k ( F L

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e w u _ l.. DATE: 8-20-82 PAGE 126 /"

                                     .                                                                                                                         .                              . 4

1 BWNP-20007 (6-76) l l BABCOCK & WILCOX NUGEAR POWER GENERATION Dn/tslON su m ER r-TECHNICAL DOCUMENT (( TABLE 5 - RULES FOR RC PUMP TRIPS RULE REASON

1. The RC pumps shall be tripped Precludes the potential for un-immediately whenever subcooling covering the core (ICC) during a margin is lost. small loss of coolant accident due to a pump trip when the amount of water in the RCS is low.

l

2. *1f cooling water to the RC pump Pump trip precludes motor failure motor is lost and the pumps are and minimizes the chance of a fire running, cooling water must be inside containment due to lack of restored within 10 minutes or the cooling water to the RC pump motors.

RC pumps must be tripped.

3. *If seal injection and cool- Pump trip reduces damage to the ing water are lost to a RC pump for pump seals. Injection and/or ICW a period longer than 60 seconds, the can be reinitiated by following pump (s) must be tripped within the pump manufacturer's instructions.

next 30 seconds and the seal raturn If possible, an engineering assess-line closed 90 seconds later, ment should be performed before restarting since seal failure could i 1 occur due to a high temperature in the seal cavity.

4. *If seal bleedoff flow is lost on The RCP seals may be damaged by a an RC pump, the bleedof f flow must loss of bleedoff. The RC pump trip be quickly reestablished or the RCP minimizes possible seal damage.

t rip ped . Seal bleedof f can be reinitiated by following B-J instructions. I These rules do not apply if.the 1 pumps were not tripped immediately af ter the subcooling margin was l lost. The operator should try to restore the RCP service which is lost. I l DATE: PAGE ^ a.i i 8-2 0-82 ,

                       .                                                .       .            127

BWNP-20007 (6-76) BABCOCK & WILCOX NumsER NUCLEAR POWER GENERATION DIVISION 7'.-i 22038-00 C TECHNICAL DOCUMENT RC Pump Restart Core cooling and plant control are best if the RC pumps are running. Pumps can te restarted after trip if the reactor coolant conditions are righ t. Therefore, to complement the RC Pump Trip Rule given previously, conditions when the pumps can be restarted are given. These conditions I cover both LOCA and non-LOCA events and have been carefully chosen so that

              .a      pump restart followed shortly afterwards by an inadvertent trip will prevent fuel damage for small breaks.

Restart of the RC pumps is desirable for several reasons: m ( e It prevents brittle fracture of the RV when the reactor coolant is ( subcooled with HPI flow but no forced circulation exists. e If natural circulation was lost, the pumps can be used to restart

                          " circulation.

e If the plant , must be cooled down and . depressurized , the RC pumps will permit use of the pressurizer spray. e Cooldown will be faster with forced circula tion and the decay heat removal system can be placed in operation be fore the BWST is depleted. e If severe Inadequate Core Cooling (ICC) conditions exist the RC l pumps must be restarted. k , a v , The major reason for restarting the RC pumps is to increase the rate of

i _

n ' -- , . , heat trans fer from the core to the steam generators; or if natural cir-l r- . , culation has stopped and there is no heat trans fe r from the core to the steam generators then a pump bump will help to restart natural circula-L tion. Because the purpose of restarting the pumps is to increase core-to-l l steam generator heat transfer, it is necessary that the steam generator DATE: 8-20-82 PAGE ^ 128 d' ^

- . ~ , ~

BWNP-20007 (6-76) BABCOCK & WILCOX NUCitAR POWER GENERATION OlVi$loN TECHNICAL DOCUMENT 7'+-1122o58-o0 be available for heat removal. The steam generator will remove heat if:

1) the stem generator saturation temperature is lower than'the RCS incore thermocouple temperature; a 50F temperature difference is a good rule of thumb to use, and 2) the steam generator is fed with main or emergency fe ed wa te r . It is desirable to start the pumps for cooldown in the loop with the operating stem generator if only one is in service, however, it is best to start the pumps in the loop with the pressurizer spray if po s s ib le . Since it is pre fe rable to keep the pumps operable, a pump restart is not desired if mechanical damage can result.

One RC pump may be restarted and run to prevent brittle fracture when the reactor coolant is subcoold and the core is being cooled by HPI cooling and no circulation exists. For this unusual situation, which can be caused by a prolonged loss of all feedwater, one RC pump may be run even though there is no stem generator cooling. However, it should not be run if mechanical damage can occur. If subcooling is lost the RC pump should be stopped. . l ' Inadequate Core Cooling is, a condition where the reactor coolant is super-heated. This is a condition when core damage could occur. For this l( condition, exceptions are taken: 1) RC pumps can be restarted even if the stem generators are not available , and 2) If severe ICC conditions exist, RC pumps must be restarted even if mechanical damage can occur. For all other cases of pump restart, mechanical damage should be avoided, f l 9 s DATE: 8-20-82 ,PAGE u

BWNP-20007 (6-76) BABCOCK & WILCOX NUCLEAR POWER GENERATION DIYl51oM C TECHNICAL DOCUMENT 7'-t 22058-00 When the RC pumps are restarted the operator should expect to see pressure _ changes in the RCS as follows: e If the reactor coolant is subcooled and the pressurizer is filled solid, an abrupt rise in pressure could occur. e If the reactor coolsnt is subcooled with a near normal pressurizer level, almost no change should occur. e If the reactor coolant is two phase and saturated, a pressure drop could occur when the heat removal rate of the steam generator increases. f Table 6, "RC Pump Restart Guidelines", shows the conditions when the pumps can be restarted. The table is divided into three parts: subcooled, satu-rated, and supe rh ea ted . Guidelines for restart of the pumps in the sub-cooled and saturated conditions are dependent on the existence of liquid or two phase natural circulation. Generally, if natural circulation does not exist the RC pumps are " bumped" to try to start natural circulation;

• if natural circulation does start then that is a good indication that a

[ ' 'large amount of water is in'the RCS. " Bump" means to start a pump and run N it for 10 seconds, then turn it off. When an RC pump is " bumped" it will cause hot reactor coolant in the vessel and hot leg to move into the steam generato r; and will cause cold water in the steam generator to move into the reactor vessel. This P l l DATE: PAGE 8-20-82 130

BWNP-20007 (6-76) BABCOCK & WILCOX NUCLEAR POWER GENERATION DIYl$ TON 74-1122058-00 TECHNICAL DOCUMENT will estab lish communication between the thermal centers and initiate natur al circulat ion (if enough water is . in the RCS). When the RCS is saturated the " bump" may or may not start circulation, but it will help to depres sur ize the RCS by condensing reactor coolant steam in the generators and allow more HPI to flow into the system. The " bumps" are used only every 15 minutes because: 1) that will limit the liquid flow out of the break and 2) it will take some time for natural i circulation to develop and stabilize. Between " bumps" the development of natural circulation can be checked. l Table 6 shows two columns when the RCS is saturated - one with natural l circulation and one without. Both show that HPI is on. l(( i l

   ,,,   ,   3 When natural circulation exists the steam generator .Tsat will control the

y. .incore thermocouple temperature; if Tsat. is changed the incore thermo-

_, couple temperature will follow. If the incore thermocouple temperature <

             . does not change when Tsat changes, the stean generators are not coupled to 1

the reactor coolant system. Extended saturation with the steam generators I( ' available as a heat sink can exist only because of a LOCA. ( I ! ,e For the condition with no natural circulation, the operator is directed to perform several " bumps". If after four bumps natural circulation does not  ! start, and one hour has elapsed since the reactor trip, then one RC pump l l DATE: 8-2 0-82 PAGE - -

g3g -

[

BWNP-20007 (6-76) BABCOCK & WILCOX ,,,, NUCLEAR POWER GENERATON DIYl$ ton 74-1122058-00 C TECHNICAL DOCUMENT should be run for cooldown as long as at least one OTSG is available as a heat sink. Natural circulation will not start when there is not enough wa':er in the RCS. The reasons for allowing RC pump operation in this case, which goes against other requirements that do not pe rmit RC pump operation when the s ubcooled margin is lost, are that the RCS should be l' C depres sur ized and placed on the decay heat removal system before the BWST runs dry (to avoid HPI recirculation from the sump) and that the several

               " bumps" have consumed appreciable time.                    The one hour time limit has allowed the decay heat load to drop sufficiently so that the HPI system is now capable of adding enough water to make up the flow out of the break and still remove all of the heat.                    There is no chance for the core to became uncovered when the RC pumps are run at this time when the HPI

( system is working.

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                                                              ,? ' I*    ,

1 l f l DATE: PAGE 8-20-82 _ 132 >/6

BWNP-20007 (6-76) BABCOCK & WILCox NUMSER NUCLEAR POWER GENERATION DIVI $lON 74- 122o584 0 - TECHNICAL DOCUMENT { HPI Control The HPI system is used for emergency injection of borated water to make up for lost inventory from a small break. It may also be actuated for other reasons. The operator will have to control the flow rate in different l ways depending on the cause of its actuation. The general control actions are:

1. Maximize the flow for ECC during small breaks

2. Balance the flow between the injection lines Control the flow to prevent runout and cavitation of the HPI pumps 3.

at low pressure V 4. Throttle or stop the flow to prevent filling the pres surizer ' solid when the RCS is subcooled (except during HPI cooling as described in

                                  " Backup Cooling Methods") .

5. Stop the HPI system when the LPI system is operating

       .       ,             6. Throt tle the HPI to prevent exceeding RV thennal shock limits when 5.; g,                           the RCS is stbcooled.

4 :~

 $,                        Each one of these topics will be addressed and the best ways for handling HPI will be shown.            The discussion will be divided into two sections:

[ Maximizing HPI flow, and Throttling HPI. 3

 .o l

DATE: PAGE .atAu 8-20-82 133 r n, s j

                 ,     ,_-        .   . . , _        ~--  _ . . .

BWNP-20007 (6-76) BABCOCK & WILCOX EI NUCLEAR POWER GENERATON DIVI 5loN [ ( TECHNICAL DOCUMENT 7'- 22o58-oo NOTE: Manual actuation of HPI should be accomplished on a component

                                    , level as opposed to a system level actuation by the ESAS.                                                    System level actuation may also result in other actions that may not be desired.           There fore, the operator should manually actuate HPI by f,                                     opening the BWST suction valves, starting two HPI pumps (one pump k./                           ,

supplying each train) and opening the injection line isolation valves. Maximizing HPI Flow HPI SUBC00 LING RULE: Two HPI pumps should be run at full ( capacity when: ( e 'Ihe ESAS is actuated and the HPI is automatically started. e The reactor coolant subcooling margin is lost and the HPI is m .t .. o manually started.

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lt-- 4 id a. -y; DATE:  :. . . PAGE - 8-20-82 ( 134 2t -e u.r :. .i

BWNP-20007 (6-76) BABCOCK & WILCOX NumsER NUCLEAR POWER GENERADoM DIVI 5loN TECHNICAL DOCUMENT 74-1122058-00 l(r When the HPI system is started for either of these two conditions, its pur-pose is to remove decay heat either by "once 'through cooling" or by allow-ing the reactor coolant to transfer heat to the steam generator. "Once through cooling" or HPI cooling occurs when the injection water passes through the core, picks up heat, and exits through a break or_ the ERV. In order to be most effective the RPI flow to the core must be the greatest 1 i amount pos s ible. One HPI pump will satisfy core cooling requirements, but I two HPI pumps are preferred. Balancing the HPI flow is required to ensure that the greatest amount of pumped flow enters the core. When the system is , automatically actuated the operator should check the flow indicators on all four injections lines. Since the valves on the inj ection lines are l preset to give a maximum flow, each line should read very nearly the same. If they do not and one line is obviously high, then it is probable that l that line is broken. It should be isolated and the valves in' the remain-

  ,'        ing lines should be opened and balanced to give the maximum flow possible.

l Balancing will permit the most flow to enter the core from four quadrants I to provide cooling. If four injection lines are operating, this will be l about 250 gpm per line; if only three lines and two pumps are operating, the flow per line will be more than 250 gpm. These actions, if required , must be completed within ten minutes of ESAS actuation to ensure adequate [k _ inventory in the RCS and avoid an ICC condition. HPI Throttling After it is started the HPI must be run at full capacity until the reactor coolant system conditions allow it to be terminated or throttled. Guidelines for throttling or termination and the reasons are given below: DATE: ' PAGE 4

                                                                                                 .Pl 8-20-82                                                      -

135

BWNP-20007 (6-76) BABCOCK & WILCOX ( NUCLEAR POWER GENERATION DIVISloN I TECHNICAL DOCUMENT 74- 122058-00 Guideline 1 for HPI termination or throttling: HPI operation may be terminated if the LPI system has been started and has been flowing at a rate in excess of 2630 gpm in either injection line (3020 gpm if only one LPI pump is operating) for 20 minutes, f, U This condi tion is applicable to a large LOCA when the RCS depressurizes enough to allow the LPI to flow into the reactor vessel. Since LPI will provide emergency injection at a much greater flow rate than the HPI, HPI can be stopped. The 20-minute delay is used to make sure that the primary systen will not repressurize and result in a loss of LPI flow. The 23Ii=: minimum flow requirement of 2630 gpm (3020 gpm with only one pump) is used ( "3

                 ' ~ to make sure that the injection flow can remove decay heat with no loss of

( D' reactor vessel water inventory after HPI is stopped. 2630 gpm flow to S

                   -either inj ection line (3020 gpm with one one pump) is required to make
            ' misure at least 1000 gpm gets into the RCS.            A possible break in one of the
               '"' ' two LPI/CFT lines would allow LPI water to be lost out the break and not "

} reach the reactor vessel. - "

                                                             .c   ->

Guideline 2 for HPI termination or throttling: k ' e HPI may be throttled any time the reactor coolant u subcooling margin is restored. g, ,

ows e HPI may be stopped any time the reactor coolant subcooling margin is restored and pressurizer level is on scale " low" (> 50") and increasing.

               ' " Normal makeup should be restarted. The one exception to this guideline is the case where core cooling is provided solely by HPI. In this case HPI can be throttled when the subcooling margin is restored but should c

not be stopped until secondary heat removal is es tab lished , even though the pressurizer will be solid. DATE: PAGE 8-20-82 .JrAq 136

                           .:                                                                          < x u..

BWNF-20007 (6-76) 1 BABCOCK & WILCOX NumsER NUCLEAR POWER GENERAfloN DIVISICN N- 22o58-oo TECHNICAL DOCUMENT These guidelines apply to both LOCA and non-LOCA transients and are f( intended to limit the amount of water going into the RCS so that the pressurizer will not fill solid and let water discharge through the pressurizer valves. The pressurizer can fill for two reasons:

               - Continued HPI injection
               - Reheat and swell of the reactor coolant af ter an overcooling transient has been stopped.                                                                  ;

Although the core will be covered and safe if HPI is not throttled , it is desirable to do so. If there is any doubt about throttling HPI then don't do it. If water were allowed to flow through the pressurizer relief valves, the plant conditions could get worse. Continued flow through the valve s could fill the quench tank and cause the rupture disc to fail, releasing water to the containment, or the pressurizer valves could fail to reclose and a LOCA would result. .One case which requires throttling is HPI cooling when the PORV is -intentionally opened to provide a once-through cooling path for HPI water. The repressurization could cause a violation of the NDT limits as discussed in Guideline 5.

                                                                          .: e .              . .

An overcooling transient causes the reactor coolant to shrink. If HPI is started additional water is added to' the RCS.

                                                                     ~

When "the overcooling is

                 ,    x. m  ,     u  'o s topped the core heat will cause the reactor coolant and the added water

n. .

m , , to swell. It can expand enough to fill the pressurizer. In order to

                                ~

limit the amount of filling the HPI can be throttled when the reactor

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DATE: PAGE, ,g37 8-20-82 j

                                                                                                                           -l 1

I BWNP-20007 (6-76) BABCOCK & WILCOX suusER NUctfAR POWER GENERATION DIVl$1oM C TECHNICAL DOCUMENT 7'- 22058-00 coolant subcooling margin is restored and the HPI can be stopped when the subcooling margin is restored and a pressurizer level indication of 50" is shown. The 50 inch pressurizer level indication was chosen because it is just above the pressurizer heater cut-off level at 40". f k If the overcooling was severe throttling HPI alone may not be enough to prevent the pressurizer filling; therefore, the reheat of reactor coolant must also be limited. This can be done by lowering steam saturation tempirature below the RC cold leg temperature. The operator can monitor

             ,    the ef fect s of s tean pressure by monitoring Tcold and pressurizer level and control steam pressure as necessary.          The operator should be careful I_               not to lower stean pressure too          muc*. or the pr es surize r will drain.

Throttling or termination of HPI and lowering steam pressure will keep the P-T from re turning to the " post trip window". This is an acceptable end point if the system is stable. , For many reactor events that use the HPI sys tem, subcooled reactor coolant conditions will be returned in the first several minutes. When the f' reactor coolant subcooling margin is es tablished the following general procedure to control RCS inventory should be followed:

       ,m:     ,,

HPI Control Af ter RC Subcooling is Regained _

l. Avoid too much subcooling (high RCS pressure). There is a tendency

, to think that if " adequate" subcooling margin is good, then 200F sub-C cooling must be better. The easiest way to get this subcooling DATE: 8-20-82 PAGE 138 - t

BWNP-20007 (6-76) BABCOCK & WILCOX I NUCLEAR POWER GENERATION DIYl$10N TECHNICAL DOCUMENT 7'-n22038-00 is to allow HPI to run unthrottled and raise RCS pressure. This may lead to unnecessary lifting of the primary safety valves (the time between 2200 psig and 250G psig with two HPI pumps running un-throttled is abou t 60 seconds) or in some cases, violation of NDT and tharmal shock. Also, there are transients such as a steam generator tub e rupture where the higher RCS pressure ackes the I r outcome worse (large leak rates). Therefore, the operator should throt tle HPI and begin to ' stabilize RCS pres sure as soon as the subcooling margin is regained.

2. If pressurizer level is less than 50 inches, maintain HPI but reduce the amount of flow that is being added to the RCS.

e If two or more HPI pumps are running, stop all but one pump. NOTE: Run the HPI pump which normally supplies seal _,,, inj ect ion. 4 . i

3. If pressurizer level is on scale, throttle HPI using HPI injection valves and attempt to stabilize pressurizer level.

NOTE: Do not decrease HPI flow below low flow limits, (50 gpm per pump including recirculation' flow). e Maintain HPI at the reduced ' flow rate if pressurizer level and subcooling margin stabilizes '(i.e..HPI is matching a leak). l e If pres surizer level continues to increase above 50 inches, control HPI per I' tem 4 below -(except during HPI cooling as described in " Backup Cooling Methods"). 4

                                                                               .,.   .),

DATE: 8-20-82 . PAGE. g39 q ,

                         "                                                                                     j

BWNP-20007 (6-76) BABCOCK & WILCOX OII NuctEAR P0wtR otNORATION DiviseON C TECHNICAL DOCUMENT 74-1122058-00

4. If pressurizer level is increasing and greater 'than 50 inches (indicat ed) , realign the .HPI s) stem'into the normal makeup and letdown mode.

e Monitor reactor coolant subcooling; restart HPI if subconting I margin or pressurizer level decreases below 50 inches. e Reset ESAS after HPI has been s top ped (if RCS pres sure is high enough).

5. If the pres surize r level is increasing rapidly, it may also be necessary to open the turbine bypass valves to decrease steam pressure to prevent the RCS from going water solid.

f Guideline 3 for HPI termination or throttling k e The HPI must be throttled to prevent pump runout and cavitation damage. The maximum allowable flow per pump is 525 gpm. n' _. m2 .

                                                                                       , ,_ .; [.                         .

This guideline is implemented' hor pbp protection so that core cooling will continue. Generally the RCS pressure will be below 600 psi before

• runout becomes a prob!.em.

p ,, , o n, ,

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J~ # - '). e DATE: PAGE - A0 8-20-82 140 .,

                                                                                                                                                                      - +~

BWNP-20007 (6-76) BABCOCK & WILCOX " '" wucteAt rowee oeweaAnow omsion , g TECHNICAL DOCUMENT Cuideline 4 for HPI termination or throttling e The HPI low flow limit is about 50 gpm. Total pump flow should not be throttled below this limit. Pump overheating and damage can occur at very low flows. The total flow is a combination of the recirculation flow and the injected flow. Guideline 5 for HPI termination or throttling: e HPI must be throttled to prevent exceeding the thermal shock limits of the reactor vessel when the reactor coolant is subcooled and RCP's are not running. The RCS pres sur e/ temperature combination must be kept within certain limits to assure reactor vessel integrity. These limits are dependent on

    .. whether there is forced flow, or NO            forced flow:

14C'- """" L.,; _j ,e pj o .

                                                      . :p <

, Forced Flow l i: i I As long as at least one reactor coolant pump (RCP) is running, the RCS l l pressure and temperature must be kept within the normal technical speci- l fication NDT limits (Region I & II of Figure 25). l l With at least one RCP running, any cold leg RTD can be used to determine j the tempe rature for comparison to the NDT limit. However, due to back flow in the cold leg pipes without an operating pump, the cold leg RTD in I DATE: PAGE . er 8-20-82  !

                                                                                      .y _p - y     141
           - - - -            y --

BWNP-20007 (6-76) BABCOCK & WILCOX NUcitAt POWER GENERAfloN DIY1580N Numeen C TECHNICAL DOCUMENT 74-1122058-00 these loops will indicate temperatures slightly lower ( ** 2 F) than in the

                    .ccid leg pipes with running RC pumps due to the relatively cold HPI and me;al injection water added to the back flow, f                   No Forced Flow                               ,;,                 -

b If the RC pumps are NOT running, the RC pressure / temperature combination must be kept within the no forced flow region of Figure 25 (Region II). The reactar vessel downcomer temperature will be colder during no flow conditions than during Forced Flow conditions. The " Thermal Shock Limit" of Figure 25 is designed to account for these colder temperatures. These colder temperatures o_ccur because the HPI flow entering the RCS does not n - ( completely mix with the reactor coolant as would happen if the RC pump k , were operating. The HPI water, will enter the cold leg pipe tnen flow

                  'into the RV downcomer to cool' the reacto'r ' vessel walls.                                      2 These colder RV o     ,,ac:          .,nd-      , > w ,!   r,        u;         ne temperatures will cause the allowable RV pressure to be lower.
              .i.                                   ..       , , ,             a : w:n >          nwat a              -
                                                           ,uf.         <
                                                                          , a r,-:3      e     . !:    Lav
                                                                 ~

The "The rmal Shock Limit" may require throttling the HPI flow. This will - i m m c,. svr u : , '_ first reduce the RV pressure and then .. reduce the HPI cooling of the RV.

                                                                                        ,a a rn
                                                            . w. i n                                           ,

f 1

         .i                                            ,,:     , , ':      ~:      nine         -

k If the "The rmal Shock Limit" is " exi:eeded , ' the RCS pressure should be red uced to regain the no forced flow operating region as quickly as - possible. t DATE: j PAGE 8-20-82 - M AG - 142 -

                                                                                                                                     .e  ,wdau

BWNP-20007 (6-76) BABCOCK & WILCOX . , , , NuctEAR POWER GENERAfloN DIVl510N TECHNICAL DOCUMENT 74-u 22o58-oo , a) Monitoring Thermocouple Temperatures With no RCPs running, the average of the five highest thermocouple j (TC's) temperature readings should be used to determine the RC temp-eratur e for Figure 25. This will as sure that the subcooling margin is maintained and that the brittle fracture limit is not exceeded.

                                                         .'    m, i

The use of the 5 highest TC's is preferred for the following l reasons: u

1) The operator monitors the five highest TC's for other reasons

     ,,                  (ICC),     i.e.,  the data is available. and the operator need not perform additional data reduction.

2) The conservatisms in the thermal shock analysis are more than adequate to support the slightly higher system pressures and

           ,,           slightly lower downcomer temperatures by , using the five highest rather than five lowest thermocouple readings.
  #                                                       ~

3) The allowable temperature span between the subcooling margin  !

limit and the RV thermal shock limit for RCS operation is l relatively narrow. Consequently, the operator should use the l same ins trument for avoiding both limits. If the subcooling I n~ . margin is determined by averaging the five highest thermocouple i j readings, the margin to the thermal shock limit should be I l m,g , determined with the same readings to avoid overlapping limits. l( l n ghalup . - u ;n m -- 1 i 1 i l 4 I l

                                                                          . - -                                 1 DATE:           8-20-82       -

PAGE '/ U - t - 143 - l _. .. .

BWNP-20007 (6-76) BABCOCK & WILCOX m ,, NUCitAt Powet GfNEAAfloM OfVi$lON C TECHNICAL DOCUMENT 7'- n22o58-oo Without an RC pump on and with HPI on, (with or without natural cir-culation) the cold leg temperature detectors cannot measure the RV downcomer tempe rature because the RC loop flow and HPI flow mix downstrean of the temperature detector. The ratio of the HPI flow f to RC loop flow is substantial. . Consequently, the resulting mixed k- tanperature of the two fluids will be substantially lower than the cold leg t emperature indication. .For SBLOCA, the ratio of the two flows will vary with the size of break in the reactor coolant pressure boundary. The larger the break the more the HPI flow and t!.e less the reactor coolant flow, w-l u '. , ( During natural circulation, the hot leg tempe rature detector with k loop flow can be used to . indicate core outlet tempe ra tur e. However, to simplify the operating instruction the same thermocouples are to

            ,             be read, whether or not natural circulation exists.                                  Therefore, the
        ,                 operator does not have to determine if natural circulacion exists or to switch from one measuring device              ,.e to another.>        , ,.
                                                          . > . . , .                . w l
                                                                .,*,      %'     nt.

l If HPI flow does not exist, the operator , should use the normal P-T 5 limit curve during natural circulation

                                                              .        .u.

and the cold leg temperature

       , ,              detector in the loop (s) with natural circulation flow.                                                    -

ui a ,n , -- e - -

                                                    . > \ , r.w. , y       w         .r:

' + DATE: 8-20-82 I PAGE ' - 144 q; . l

                        .              ;                                                       .                            m ..a.~  -

BWNP-20007 (6-76) BABCOCK & WILCOX l ( NUCLEAR POWER GENERAfiON olvi$lON ER i TECHNICAL DOCUMENT 74-1122058-o0 b) RCS Pressure Control

               ~ With no RCPs running, throttling the HPI flow is the only method for gradually reducing RCS pressure.      Also, without primary to secondary heat trans fe r,    the rate of cooldown is depende nt on HPI cooling through the break (opening the ERV is necessary only if the break is so small that RCS pressure begins increas ing ) .       Therefore, careful and consistent throttling of HPI flow is the only available means to ensure that the RC pressure / temperature combina cion remains within the no forced flow operating region of Figure 25.

c) Restoring Natural Circulation

  !+
   '~ '

If a RCP cannot be started, natural circulation should be obtained to provide some HPI mixing as well as providing good heat transfer

     ,    ,s from the primary to secondary coolant.           With natural circulation,
                'the cold HPI water will mix with cold leg flow and reduce the thennal       shock   to   the    reactor    vessel. However,     the                     RC pressure / temperature should still be maintained within the no forced l

flow operating region of Figure 25. The thermal shock concern is

 ' n 1.sn m eliminated entirely when RCPs ' are running"and RCS P/T is maintained l

{f ( 1 m:au ce - - within Tech Spec NDT limits. The refo re , as soon as subcooling ( margin is obtained in the RCS, a ' RCP should be restarted. Then the reactor vessel downcomer pres sure/ tempe rature should be kept within 1 the normal NDT limit. l i l DATE: 8-20-82 ,I PAGE 145  ;

                               '                                      i
                   ~,

c

BWNP-20007 (6-76) BABCOCK & WILCOX - NucteAn Powet oENERADON DMSf0N [( TECHNICAL DOCUMENT 74- 122058g0 HPI VALVE CONTROL The HPI valves will be used to rciace HPI flow until the RC system pres-sure becomes low enough to initiate the LPI or DHR system. If a small break exists, the RC pressure will have to be reduced to the LPI operating pressure. If only a loss of feedwater exists then the RC pressure need l((_, only be reduced to the DHRS operating pres sure (unless secondary cooling

             . is re-established) and then the ERV should be closed.

P Without feedwater the time to depressurize will depend on the size of the break. The HPI flow will be performing tw functions. It will be main-taining systen pressure which will be a function of the IFI pump head and the choked flow out the break. It will also be removing decay heat from the core. The amount of decay heat will determine the amount of IFI flow needed and the HPI flow will establish the RC pressure. Consequently, as the decay heat level decreases _the HPI flow can be throttled back which

            . will cause the RC pressure to reduce.

With feedwa ter and either forced or natural circulation, the HPI flow to i f_ the core is needed only to control pressure. The steam generator will 4 remove heat. Consequently, the RCS can be depressurized much quic ke r . The steam generator can be used to cool the core as quickly as possible up . to the 100F/hr. limit. Simultaneously, the HPI flow will be throttled to maintain the RC pressure within the acceptable P-T limits. 4 b DATE: 8-20-82 PAGE [q' a -

BWNP-20007 (6-76) SABCOCK & WILCOX pe# CLEAR POWts GENERAfloH oiVISION NUMSER TECHNICAL DOCUMENT 74-1122058-00 The HPI flow rate should be balanced among all injection nozzles to { distribute the HPI flow around the reactor vessel downcomer as auch as pos s ible. This will limit localized cooling' of the RV. ! During plant cooldown a situatien may occur' where the RC pressure cannot be reduced by throttling HPI flow. 'This can be caused by hot water flashing to stean in either of the RC hot leg'180 degree elbows (due to no flow in one or both loops) or in the pressurizer (ERV closed). The operator should attenpt to remove the RC loop steam and hot water by bumping a RC pump in the loop with natural circulation flow. If no natu-ral circulation flow exists any RC pump can be bumped. c . ,,-

       With a small break, the HPI can cool the core enough to make the RCS
       ' subcooled with choked flow out the break.

Then the RCS pressure can be I reduced by throttling back HPI flow. However, if the ' break is not in the pres sur ize r stean space, a steam bubble could form in the pressurizer which will also need to be controlled in order to' reduce RC pressure, either by opening the ERV or using pressurizer spray.

                              .                                      ~

l((

  " ' 'fhese guidelines 'are summarized in Figure 30.              '

Im i ne :d1 od 1::= va!: - ,

~1  :

4 4 i+1 - , , .-- a r- -- - - - - DATE: PAGE W 8-20-82 1 147 -

                                                                                                                > a:4 :

BWNP-20007 (6-76) BABCOCK & WlLCOX NUCLEAR Powta otNaRAflON otVisiON Numeen TECHNICAL DOCUMENT 74- u 220584 0 _- l Feedwater Control Abnormal transient operation with main or emergency feed water requires special attention to feedwater control. Failures can cause too much water to be added. Excessive main feedwater addition can fill the steam Cj lines with water and cause water release from the MSSV and undesirable ove rcooling , especially if feedwater her. ting is lost and cold water is 4 added to the steam generator. Excessive emergency feedwa ter can have the sane general effects, but it will cause a more severe cooldown (for the same flowrate) because of the greater steam pressure red uct ion e f fect due to the high injection point and colder water. Both excessive

i. , -

main and eme rgency feedwater may require thct quick actions be taken to ( stop it. Emergency feedwater may also ceuse overcooling whe the steam Q , .- c generator level is being raised even though no failuret have occurred.

                                                        , ,m          .s.a     :.

4

In order to limit overcooling, emergency feedwater should be throttled. m .o. n, This section will recommend the best methods for manual control, n :, s t 3,' J ' ;11 '

                                                                                                                                =

Main Feedwater Overfill

w. , :s

     ~r             The procedural guidelines in;..,,             Part I considers various (very rapid) MFW m

3 , i overfill conditions including a very rapid overfill for which the q 1 a ,- . . , , , . operator is instructed to immediately trip both MFW pumps. This section, however, presents less severe actions that can be taken in the 4-event of slower overfill transients. b To regain control and stop main feedwater overfilling when a failure of g the controls oc cu rs , the following gives a series of increasingly more severe actions: DATE: 8-20-82 PAGE  : IM - 2 - ,,

l BWNP-20007 (6-76) BA8 COCK & WILCOX " " ' ' wucteAs powea oenenAriow oivision 74-1122058-00 , TECHNICAL DOCUMENT e At tenpt to manually control the fe edwat er pumps with the hand / auto station; this may not work if the controls to the pumps have failed, so be prepared to quickly take the next step. e Close the feedwater isolation valve to the high flow generator. This action is preferred to closing the control valves or running back feedwater with the ICS feedwater demand hand station because 1 those controls may have failed and could have been the reason for l the exc es s ive fe edwa te r. Closing the isola tion valve cuts off feed water to only one generator and does not cause a total loss of main feedwater.

                                                               ><         n.

e Trip the main feedwa ter pumps. This is the quickes t and surest method of stopping the overfill. It is also the preferred method if the OTSG is ovet filling rapidly. This will stop all feedwater to both generators (it will be a loss of feedwater, but since the

. u !a:n m;                                                  .            a      .1.      ;

genc rators have a large inventory the heatup ef fects will be

                                                                        >     4-  : f; ,             o delayed). This action can be taken if both generators have                                                       l l

excessive feedwater or the other actions do not work. 1 Flow should be monitored in all cases; it will show ' the effects of

( :A,,, , , .,- 4-correct ive action faster than level. The corrective actions must be

        ..u a       .
                                                                                          .                                             lg
 .c taken within 2-3 minutes to prevent steam generator overfill (water
                  .                               .                            3         r       .                -

( l 1evel at the top of the shroud) with large excessive MFW flow rates. I

. 1.; ni b 'ti4       %                                                              \'-             >

o , . . . l l l DATE: PAGE., 8-20-82 , u , _ i

BWNP-20007 (6-76) SABCOCK & WILCOX Numsta NUcttAs Powet GENEGAfloN DIYl5 ION [( TECHNICAL DOCUMENT 74- 122058-00 If all main feedwate r has been stopped, the operator should make sure emergency feedwa t e r starts so it can start to inject when the generator water level boils down to the automatic setpoint. Emergency Feedwater Overfill To stop emergency feedwater froia filling one steam generator: e Attempt to close the control valve and the bypass valve to high level /high flow stean generator. This may not work if the valve controls have failed. e Trip one EFW pump (select the pump supplying flow to the high level /high flow generator) and close the cross connect valve to prevent the remaining pump from supplying flow to the bad generator. To restore emergency feedwa ter operation the failed control valve may be closed manually and the bypass valve around the control valve may be opened. 1: r: 2 . o i To stop emergency feedwa ter from filling both stean generators (this ' condition may happen if power supplies or station air are lost to the

                                                   .   .n          ,;      ' t ..

i control valves): i >,. 1-e When stean generator level is high , stop pumps, allow the steam - } generator level to drop and restart one pump. Use that one pump to

                        " batch" feed the generator by starting and stopping the pump.

k DATE: PAGE - ' /. C ' 8-20-82 - 150

BWNP-20007 (6-76) BABCOCK & WILCOX NUCLEAR PoWEt oENEAAtloM OtVISION II TECHNICAL DOCUMENT 74-1122058-00 Infrequent starts and stops of the pump are expected because the steam generator level will take about 5 to 10 minutes to boil the inventory to a low level, e If no control of EFW can be obtained the pumps can be stopped and HPI cooling can be used. This method is not desirable, but it will keep the core cool. Every attempt should be made to maintain EFW to at least one generator, even if the operation is not steady. 'l i EFW Throttling Anytime EFW is actuated and automatically increases steam generator level to 50% on the operating range, it can cause significant ove rcooling . The 50% level is required to establish natural circulation

any time all RC pumps are tripped.

Steam generator level must also be manually increased from 50% to 95% on the operating range when the subcooled maagin is lost. The 95% level

r. - , ,

will permit primary coolant steam condensation during boiler-condenser l cooling in case a small break LOCA has occurred. Anytime the subcooled margin is lost the level should be raised to 95%; if the subcooling

                                                                                                        ]

margin is regained while the level is increasing then the level increase

                      ~
         = r ;: 2   .

does not need to be continued to the 95% level, but must be raised to 1

   /      o :c vc          8.u i     6                             .

50% if the RC pumps are not running. ) 1 I DATE: 8-20-82  ; PAGE - 151

BWNP-20007 (6-76)

                 ' ~ BABCOCK & WILCOX                                                                  NUMSER NUCLEAR POWit G4NORAfloN DIVI $loN TECHNICA'.   . DOCUMENT
                                                                                                            , 74-1122058-00 3

j. Steam Generator Level Rule . [ Anytime the subcooling margin is lost, levels in the operable steam genera tors must be raised to 95% on the operating range using EW in accordance with the EFW throttling guidelines. I Exception: If the loss of subcooling margin was due to a loss of secondary s t ean pressure control, or SG overfill do not at tempt to x raise level in the affected steam generator (s) until steam pressure and level control is regained.

                                                                . c l D,       .    ,

n Overcooling can resul t because EW flow injects water into the stean ( space of the generator. As the flow sprays into the steam space it k causes stean condensation and a reduction of stean pressure; when the

                  't

level increases the inventory accumulation is a colder heat sink than is needed to balance decay hest. The combination of the steam pressure reduction and the colder heat sink causes the overcooling.

                                                                               -d.'. U L.J .' - ..-             .

Automatic level centrol will provide essentially full W fl u until

  ~~
                                                                      .. , ; 4 . ,,       . ,

, level approaches the setpoint7 ' When the natural circulation setpoint ! . i , . , . m; r L-', .; k is in effect this maximum flowrate can .cause significant overcooling. Addition of EW at the maximum rate is not needed to achieve stable - natural circulation; it is also not necessary to raise the level from fl 50% to 95% at the highest possible rate. EW can be throttled to con-E trol the level and limit the overcooling. Full flow of EW is not h l l i DATE: 8-20-82 PAGE ;yi M, , , ,

BWNP-20007 0-76) BABCOCK & WILCOX Numsen

                                                                                                         ~

NUCLEAa PoWit GENERAfloN DIVISION TECHNICAL DOCUMENT m 2205840 needed, but continuous flow is. 'A continuous addition of EFW will cause the thermal center for natural circulation to be high in the generator, and continuous addition will cause primary steam conde ns a-tion. However, if natural circulation is lost ( for example, due to a delay in EFW actuation), then EFW flow should not be throttled until natural circulation starts. It is not mandatory to limit the rate of EFW addition to prevent over-cooling, but throttling is preferred to control the plant better. For example , if a severe overcooling trans ient caused loss of the sub-

   .   >:'        J' cooling margin and the RC pumps were tripped, the addition of EFW at full flow would cause the overcooling transient .to be much worse.

Throttling is desirable to control the severity of this type of trans ient. The guidleines, and rules on EFW throttling are summarized below, along with SG 1evel setpoints. . , - l Guidelines for EFW Throttling: I

v. e EFW may be throttled any time it is started immediately af ter loss of main FW, if it is injecting into both steam generators.

e EFW may be throttled any time af ter it is started and natural cir-

         ,~~ . _ ,

culation exists in one or both steam generators. {(f

                         -                                    c, y-4           . ~n               ,      .
              +               .4                      a          ,

c DATE: 8-20-82 ' PAGE :g53

1 BWNP-20007 (6-76) l I BABCOCK & WILCOX Nu m en NucteAn powea oeNenAnoN DMSiON I TECHNICAL DOCUMENT  ! k 3 Rules on AFW Throttling: (Applicable When No RC Pumps Are Running) e EFW must be turned on full if natural circulation stops and the stean generator level is below the se t po int. It can be throttled when natural circulation starts. e EFW must be turned on full if its actuation was delayed. It can be

            ,                   throttled when natural circulation' starts.

e EFW must be turned on full if it is only injecting into one genera-tor. It can be throttled when natural circulation starts. e e Stean generator level must be continually raised to the applicable setpoint; the steam generator level must never be allowed to decrease if level is still below "the applicable se tpoint (see

                                                              ;-        ,                          a   I     e setpoints below).

[- ( e Flow into the s tean generator should be continu'ous at all times until the setpoint is reached.

t ., c

                                                                            .        . n.          *   ,   ?   ?s:,,
      *                                                               ' " ~ "               "             ~  ' '

Steam Generator Level Setpoints: ' 30" on the startup range when one 'or more RC pumps are operating. , 50% on the operating range with two steam genera toru (it may be necessary to raise the level higher than 50% if only one steam i _ ,. generator is working) when no RC pumps are operating.

                                                                   , , . , , . . . ,     ,, , a 95% on the operate range when' the subcooling margin is ' lost.

i- . . ;, ni r: n -

        '                               ^                                     ^

The amount that ' EFW can be throttled " depends on the decay heat load which can ' vary depending on the prior operating power his to ry. To increase level the flow must be gre'ater 'th'a'n that required to remove the decay heat. t l DATE: 8-20-82 PAGE 150 :J {

                             .:                                                                          .         , .                 +
                                                                                                                                           . =i

1 BWNP-20007 (6-76) BABCOCK & WILCOX NUCLEAR POWit GENERADON DIVISION TECHNICAL DOCUMENT 74- 122058-00 Because the decay heat can be different, the amount of flow needed to remove decay heat and increase level is different; therefo re, no fixed flow rate can be established. However, the maximum flow rate can be gauged by its ef fects. Generally, the flow rate should not drop steau pressure by more than about 100 psi below the pressure se t poin t. For example , after a trip the turbine bypass set pressure is 1010 psi so the EFW flow should not cause steam pressure to drop below around 900 psi. If the operator has adjusted stean pres sure to a dif ferent set-ting the steam pressure dro;s should stay within 100 psi of that set-ting. The 100 psi change in stean pressure is a rule of thumb for _. limiting the cooling of the RC system. The ef fects of EFW throttling can also be seen in pressurizer level (if the reactor coolant is subcooled and is circulating). Pressurizer level , , indication should be visible and not be alkowed to dr[p out of range l because of EFW. , , t - 33 . - An important object ive is to maintain natural circulation. If natural circulation has been previously established and the EFW flow rate is {(k enough to maintain natural circulation, then it is the right flow (if a,...., , pressurizer level and steam pressure are about right)., Generally, l . natur al circula tion is established and maintained when Thot and the incore thermocouples track together. ' l i. -J t i DATE: PAGE - c' 8-20-82 155"

1 I BWNP-20007 (6-76) SABCOCK & WILCOX l NDCLEAR POwlt otNEAATION OfvlSloN NUM8Et l TECHNICAL DOCUMENT 74-1122058-00

  ;a .

EFW should not be throttled if it's automatic start is delayed after I all RC pumps trip. It also should not be throttled if only one genera tor is available for heat removal. For either of these c ondi t ions natur al circulation could be stopped or not started. Small break LOCA primary steam condensation might also be restricted for either situation. .,.c; EFW throttling is not mandatory, but is desirable to limit overcooling and possible pressurizer draining. If there is doubt about throttling

      ;                       EFW, then don't do it.                                 c v.

( ( E ' a .:, .

                                                                        . c : = t r. , . ,
,~                 ..                                         , w           >-          ,..
          .                                                      . n .d n                e,'      'e~<-   +-

V 4,

                                                                   ,            J 'l *,

c- r. T; :, .. o + b i t l DATE: 8-20-82 PAGE 156 ,; g . . .

                                                                                                                                          **m   sww

BWNP-20007 (6-76) BABCOCK & WILCOX NUCLEAR POWER GENERAfloM Olvi$loN 00EE TECHICAL DOCUMENT 7'-i 22a584 0 Use of the Incore Thermocouples ' The incore thermocouples can be used for a variety of purposes. Info rma tion about the incores is given in dif ferent ch ap te rs . The following summarizes that information:

1. They are used to detect core uncovery. They are the most valid indication of core cooling. If the incore thermocouples clearly indicate supe rheated conditions, then the actions to counter Inadequate Core Cooling should be taken.

2. They provide indication of natural circulation. Incore the rmocouples decreasing as secondary pres s ure is lowered is a pos it ive indication of natural circulation. Wen the plant is s ub cooled and solid water natural circulation is occuring, then That should read within 10F of the incore thermocouples. Wen the reactor coolant is saturated, however, the RTD's do not provide an indication of natural circulation.

3. They provide an indication of margin to the brittle fracture limit when no forced circulation exists. The reading of the five highest thermocouples displayed should be averaged, and compared to the Region II limits on Figure 25, "RC Pres sure/ Temperature Limits."

If that number is beyond the brittle fracture limit the HPI flow should be throttled or an AC pemp started.

4. They are the only valid indication of core outlet conditions when no circulation exists. -

DATE: 8-20-82 PAGE l$jM

I BWNP-20007 (6-76) BABCOCK & WILCOX . NUcttAa POwtt otNERAfloM DIYl510N Numsee C TECHNICAL DOCUMENT 74-1122058-00 g '

                                                                             ~

Cooldown with One Steam Generator 0ut of Service - Attempting to cool ' the plant down using one " good" steam generator can cause excessive thermal stresses in the other " bad" steam generator if it is dry and the cooldown rate is 1crge. Although one steam generator can remove the decay heat and the stored heat needed to cooldown, the dry steam generator is not" properly cooled because the shell stays hot. ut: During normal cooldown the' shell of each generator is cooled by liquid r in the lower part and by steam in the upper part. When the shell is not cooled and the tubes are cooled by reactor coolant, the tubes can

   '"          "~

get much colder than the shell causing them to contract relative to the

                                                                           ~           ~

shell. But because the tubesheets hold the tubes in a fixed position and the shell does not shrink the tubes go into tension. If they get g, cold enough the tension stresses will be greater than the yield stress and they will permanently st' retch. 'If t'he tubes are cracked, flawed, 9 y or thinned they may fail. "Conseq'ueritly, ' limits are placed on the J .

,-                       tube-t o-sh el l A T.       For      ' n' orm'al 7cooldown           this     limit      has    been conservatively ' set at      100F' ~ ' Howevei[in 'ait einergency situation when cooldown is absolutely required the limit has been relaxed to 150F AT, o                       with the unde rs t and tng that any transient which results in exceeding                                 ,

the design AT limit of ' 100F' requires specific stress evaluation to b determine SG tube integrity.' ' ' ' 2 v , , v .n : .

                                   '    I
                                                        .a-            .'t        .

l DATE: PAGE " 82 , iSE' i

                             ,                                                                                                 .. . ~

BWNP-20007 (6-76) BABCOCK & WILCOX Muassa Powea oeNMATON omSION OII TECHNICAL DOCUMENT 74-1122058-00 Cooldown with one generator at the highest rate of cooldown should not be done unless it is absolutely necessary. The choices to be made prior to cooldown are:  :,, e Stay at stable hot conditions until the generator is repaired and returned to service. , e Cooldown at a slow rate so that the tube-to-shell temperature limit does not exceed the " normal" AT of 100F. e Cooldown at a more rapid rate, but do not allow the tube-to-shell temperature limit to exceed the " emergency" AT of 150F. The need to cooldown can be established only af ter a review of the plant status. .There are a limited number of reasons why cooldown may be

required; these include

, _

l

                                                                 .:2 7ix .i.         a s     ,
                                                                                                                             ]

LOCA - small or intermediate break LOCA's . will . require cooldown so l ( 1 that the primary system can be depressurized. Depressurization I l

        .y               will sl ow down or stop the leak rate.                             Tube leaks or ruptures l

_, especially require depressurization to stop the leakage into the stean generator. (

     , r f,     ,,

{k

     . a i1 ?>            <

ny; .

                                                                                                                              \

l l l -s m G., !: BW3T Drainig - in conjunction with LOCA, . it is desirable to have the plant comple tely cooled down . to avoid recirculation from the sump using the HPI system. For tube leaks which do not return water to the sump it is absolutely required to have the plant de-  ! pressurized before the BWST drains. l DATE: 8-2 0-82 ,' PAGE .,1

                        .:                                                                i      .                         ,

l

BWNP-20007 (6-76) BABCOCK & WILCOX .,3, NUCLEAa POWER GENESADoM olVISCN 74- 22058-00 C TECHNICAL DOCUMENT

                 -     Condensate tank draining - to avoid using backup service water with poor water chemistry in the steam generator, it is desirable to have    th e plant on the decay heat removal              system before the l                      condensate       tank is  drained       ( for  the unlikely case that                      the condenser beccanes unavailable).

g , Accidents other than LOCA - mo s t accidents will not require cool-down fe- mitigation, so the plant can be placed in hot shutdown while the " bad" stean generator is repaired.

                                                   ,o      .       ,

lloweve r , some situations, such as fires, may have left the plant so badly damaged that a decision to cool down is necessary to avoid un-known side effects.

 .                    In order to cool the plant down rapidly with one generator out of service it will be necessary to add water to the " bad" generator so the shell can be cooled.        If the generator is completely dry, the shell will cool only by heat loss through the insulation to the re-actor building; the average shell cooldown rate will be low (around 3-5F per hour).       Water addition to the generator will allow the shell to cool faster and the rate will depend on whether a water le-vel can be maintained. -If water can accumulate and cover the lower part of the shell, the average rate of shell cooldown will be about 20F/hr. But if a water level cannot be built and the shell is u

t DATE: PAGE . i NJ 8-20-82

                    ,                                                                                   16 0               4

BWNP-20007 (6-76) BABCOCK & WILCOX l NUCLEAR POwta GENERAflON OtVISION NU"8II TECHNICAL DOCUMENT ,74-1122058-00 mostly cooled by steam, then the average rate of shell cooldown will be around 10F/hr. Since the rate of shell cooldown is greatest when water is in contact with it, the preferred way to add water is with the main feedwater systen. However, the main feedwa ter flow rate must be care-fully controlled so the tubes do not "ove rcoo l" . The cooldown rate of the plant will be limited by the cooldown rate of the shell and the l' cooldown limit is based on the tube-to-shell AT limit. The tub e-to-shell limit can be calculated by averaging the five shell thermocouples and subtracting the reactor coolant average temperature (However, in some rare cases T av might not represent the average tube temperature; these cases can occur if the hot leg is steam bound and no circulation is oc cu rring . If Th ot is increasing but Teoid is fixed,

then Teoid should be used rather than Tay . )

To illustrate a plant cooldown, two examples are given. .Both of the examples as stane that a tube leak has occurred. Therefore, the plant j .. .must be cooled down; it cannot stay at hot conditions. ,The first l 3 example shows a tube leak with a generator that can hold pressure but j cannot be steamed. In this case a water level can be built to cool the lower part of the shell. (b The second example shows a , tube leak with a l generator that cannot hold pressure (a failed steam safety valve could do ' this). aIn .this case a water level cannot be built,,because of constant steaming (in fact, a water level could ,. b e built if na i DATE: PAGE 8-20-82 .g

                                                                              . :: x                 ,

BWNP-20007 (6-76) BABCOCK & WILCOX , , , , NUCitAR POWER GENERATION Div!SION 76-112329-00 C _ TECHNICAL DOCUMENT the main feedwater system were allowed to operate at high capacity, but 4 the tub es would cool down extremely fast and the tube-to-shell temperature limit would be violated). The examples are illustrated in Figure 31a and 31b. ( (- Both examples follow the recommended procedure for tube leaks. That is, the plant is runback, depressurized and cooled rapidly from 550F (Tav} to N500F (Tav) at a rate 240F/hr. After that the RCS is cooled down and depressurized at 100F/hr until the " emergency" tube-to-shell limit of 150F is approached. At that time the cooldown is slowed and follows the cooldown rate of the shell and the tube-to-shell A T is the ( controlling limit. When the plant firs t reaches the " emergency" tube-to-shell tempera ture limit of 150F the RCS pressure will be around 400 to 450 psig and the tube leak rate will be lowered. L The procedure shown in Figure 31a with a generator that can hold pres-sure, is to add water to the generator when the firs t stage of cooldown is completed (i.e., at 500F RCS Tay). :A water level should be maintained at the appropriate level so the lower portion of the shell is L i

    ~

cooled by water. . Steam will be created in the generator and will help E cool the upper shell. Main feedwater is preferred, but EW will also be

    +-             adequate; both must be controlled to prevent overcooling.                   The cooldown after 150F emergency tube-to-shell limit is reached will be about 7                  20F/hr.

1 L DATE: PAGE ' 8-20-82 , 162 A a

1 BWNP-20007 (6-76) SABCOCK & WILCOX , NUCLEAR POWts GENIAAnoN OlVISION NUM$tt i TECHNICAL DOCUMENT 74-1122058-00 The procedure to be used when steam pressure cannot be maintained is shown in Figure 31b. 'Ih e RCS should be cooled down at 100F/hr while slowly adding main feedwater (if possible) or emergency Sedwater until the " emergency" tube-to-shell temperature limit is reach ed . When that limit is ap proached the cooldown rate should be slowed so as not to exceed the emergency tube-to-shell temperature limit. The rate of I feed wa ter flow should be around 100 gpm, but actual flow rate will be ' dictated by the circumstances. A continuous low flow rate is desired rather than an interrupted " batch" feeding rate. Main feedwater will be dif ficult to control at this low flow rate and it may be necessary to use the " bypass" flow valve around the control valves. If the reactor coolant pumps are not ope rating or have been shut off sometime during the cooldown sequence, natural circulation will not , occur in the loop with the generator out of se rv ic e. If the reactor coolant in that loop is at a high temperature when the RCS depres-l surization begins, it may flash to steam. The steam will collect in the candy cane and that loop will "become a pressurizer". The system pres sure will " hang up" at that pressure, preventing further depres- (

        ' f    s urization. In some cases not much can be done to prevent this except lk l
            . : slowing the rate of cooldown. If possible, one or more RC pumps should             l l

be run, at least periodically, ' to preclude steam voids collecting in ' l I j the idle loop. If steau does form, and any reactor coolant pump ' l l DATE: PAGE l 8-20-82 e -.., 16.,a o-

                                                                                                     .j

BWNP-20007 (6-76) BABCOCK & WILCOX NUMB ER NUCitAR POWER GENteATaoN DIYlSloN 74-1122o58-oo C TECHNICAL DOCUMENT can be " bumped", it will help to mix the fluid so cooldown can con-tinue. If a reactor coolant pump cannot be started, then an alternate method to stimulate circulation and cool the stagnant water can be obtained by spraying EFW on the tubes. If neither EW nor RC pumps can be used the cooldown rate will have to be slowed. These actions should be performed only fo r situations, such as tube ru p tur e s , where it is necessary to continue the cooldown. If continued cooldown isn't required, the plant should be held stable with continued natural circu-lation in the one loop to remove decay heat until the voids in the idle k loop are collapsed due to losses to ambient and/or HPI or until the idle steam generator is returned to service (i.e., the problem requir-ing single stean generator cooldown is corrected). u DATE: PAGE 164 J 8-20-82

Figure 30 HPl CCNTPOL LCGIC l rPI 'ON' AT nlGHEST  ! FLCs RATE. NOTES 1) PRE VENT PLUP RUNCUT AND C AWIT ATIC% 014 ACE 9 Bf Llulil%^ THE TOTAL FLCs FR[w CNr ptyp TO $25 Gru (S REACICR CCOLANT SLBCCOLED WARGIN 2) PREVENT PUWP CA41GE AT LC# FLCe CCNDITICsS sg SATISFIED' LluiTING THE vlN14LA TOTAL PLUD FLC8 TO WJEE THAN $0 CFw PLvP

3) IF CORE C00 LING 15 PR0vl0E0 SCLELY BY HPl.  ;

I I HPI vJST BE LEFT CN A%D B AL ANCED TO uAl%T AIN y RCS PRESSURE #1 THIN LlulTS #1TH THE ERV CPEN {

                                                                                                                                            '                           M REEP HPi   'ON' AT                                          IS PRESSURilE R L EVEL l

GRE A TE R Tr AN 50" AND THE PRESSURilER is EATER SOLIC CCOLi%; IN THIS ji MICHEST FLCe RATE 1%CREAS NG L CF FOR V:0E WJST CCNTINut UNTIL EITHER SECCND ARY CCOLING jl vlCLAil0s IF TaE REACTOR 15 RE-EST ABLISHED CR tee PLA%I C AN BE P! ACED IN .! u CC6L ING 15 SLS:CCLEO AND ,'l ' NCRw AL CECAY HE AT REv0 vat CFER ATICN HAS LPI BEEN 'CN' FCR NO CIRCULATICS EdlSTS . 20 MIN #1TH FLC# GREATER T.iAN 2530 CFW . - FLCs TO E ITHER TR AIN 3 l (3020 GF4 alTH DNLY '. i CNE PLwP CPERATING) v- l NO YES t'-l NO TES l  !

          !             l                                9                                                               U                                     \

PEEP HPI 'CN' BUT PLIT HPl BACM TO N0EWAL I THROTTLE HPI TO LlulT 4J MCOE LCeER STEAw SU9CCOLING MARGIN >L*i 37cp gpg-PRESSURE IF NEEDED-(SEE NOTE 3i .D 4 ~ C05 S A PRE SSURil[R 9 LEVEL EXIST 7 CCNTRCL HPi TO 4 t- i I MATCH TEA (. WONITOR RE ACTOR CCOL AN' [' YES NO SUBC00 LED WARGIN AND 6 l PRESSURilER LEbEL IIF l;, . l I = s' IT EXISTS) i; ,

                                                                                                                                                                  ?,

i 74-1122058-00 ' e ( 4 '

- - - - - - = Figure 31a C00LD0WN ON ONE STEAM GENERATOR (STEN 1 PRESSURE CONTROLLED) ' l 2000 1600 E 1200 - J E 800 -

                                                                                                                     ~'

M 400 - I I ' I i t_ i i t 0 3 i

                                                                                                                #1                           ,

550 - - w f$P I'""'~-------- g 450 WATER ADDED TO SG AND GRADUALLY INCREASED,

                                                                                                              """ ---- 4
             ,=_                                      TO ABOUT 505 ON THE OPERATE RANGE 350   -
                                                                                                ~20 F/HR                                                 '
              =             ~ 100*F/HR                            ;

UNTIL EMERGENCY TUBE TO i

             ** 250         SHELL AT LIMIT IS REACHED             l            COOLDOWN St0WED TO STM                    '*      - -       -

M , WITHIN TUBE TO SHELL di LIMIT . O I Io e i i e i e i i ,' ' 0 1 2" 3 4 5 6 7 8 9 10 11 Time, Hours CONDiT10NS: , RC PUMPS ON OR OFF (PROBABLY ON)  ;

                       -STEAM DENERATOR "lSOLATE0" BUT HAS, INVENTORY OF WATER ADDED                                            -
                       -STEAM PRESSURE MAY SLOWLY DECREASE DUE TO LEAKS AS COOLDOWN PROCEEDS                                      -

IF IT CANNOT BE VENTED J' p 74-1122058-00 '

                           ,'                                                                                      /

s . Figure 31b C00LDOWN ON ONE STEAM GENERATOR (STEAM PRESSURE NOT CONTROLLED) 2000 5a 1600 l' 1200

                    -)

E B00 -

• I 400 -

I g i i e i i i e i i e i i in i 550 __ WATER IS CON U SL[ ~ '"-- - 38[f 0 SHELL' TEMP p 450 - ADDEDATALOWFLOWRATE(b 100 GPM) ---- 3 350

                       ~ 100F/HR 55              UNTIL EMERGENCY TUBE TO
       **                                                             .-10F/HR 250 . SHfLL AT LIMIT IS REACHED o                                                              COOLDOWN SLOWE0 TO STAY WITHIN                          ~~

TUBE TO SHELL AT LIMIT 0 I '" I 8 '8 I ' ' ' ' ' ' ' ' 0 1 2" 3 4 ;5 6 7 8 9 to 11 12 13 14 Time, Hours CONDIT10NS: " l RC PUMPS ON OR OFF (PROBABLY ON)

                  - STEAM LEAK IN GENERATOR; STEAM PRESSURE IS AMBIENT
                 - SLOW FEEDING OF GENERATOR BEGINS AT ~ 1/4HR.                li IS DOUBTFUL THAT LEVEL WILL Bull 0 FOR SEVERAL HOURS: LOWER SHELL WILL NOT BE C,0VERED FOR SOME TIME; SHELL COOLING IS BY STEAM CONDENSATIO t

3-1122058-00 I

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