ML20084Q536
| ML20084Q536 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 07/31/1982 |
| From: | BWR OWNERS GROUP |
| To: | |
| Shared Package | |
| ML20084E495 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, RTR-REGGD-01.097, RTR-REGGD-1.097 NUDOCS 8306130471 | |
| Download: ML20084Q536 (108) | |
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BWR OWNERS GROUP l
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Position on NRC Regulatory Guide 1,97, Revision 2 e
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DISCLADtER The positions reported herein are con-sensus responses to the requirements of NRC Regulatory Guide 1.97, Revision
- 2. December 1980, and as such do not necessarily express in every particu-a lar the several positions of the par-ticipating utilities.
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1 CONTENTS Page 1
1.
INTRODUCTION 3
Sponsoring Utilities 2.
BWR OWNERS GROUP POSITION STATEMENT 5
5 General Position Statement 9
Implementation of Design Changes 10 1
3.
PROPOSED TYPE A VARIABLES 11 Variables Identified as Type A 12 Potential Type A Variables i
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PLANT VARIABLES FOR ACCIDENT MONITORING 14 16 Type A Variables 17
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Type B Variables 18 Type C Variables 20 Type D Variables 23 Type E Variables i
5.
SUPPLEMENTARY ANALYSES 25 (Issues 1 - 14)
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CONCLUSIONS
$8 APPENDIX At THERMAL CONDUCTIVITY OF IN-CORE j
THERMOCOUPLES IN BOILING WATER REACTORS 63 l
APPENDIX 8:
BWR VARIABLES (TABLE 1, RG 1.97) 96 APPENDIX C:
ABBREVIATIONS 107 i
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j Changes have been made to the following pagest 1, 12, 17, 18, 19, 20.
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INTRODUCTION Following the publication of Regulatory Guide 1.97, Revision 2, by the U. S. Nuclear Regulatory Commission in December 1980, the BWR Owners Group (BWROG) established a committee to review and evaluate the regulatory positions described therein.1 The intent of RG 1.97 is to ensure that all light-water-i cooled nuclear power plants arc instrumented as necessary to measure certain prescribed variables and systems during and i
after an accident. The principal purpose of the BWROG RG 1.97 Committee was to evaluate the safety effects and the feasibil-i icy of implementing the proposed regulatory positions--particu-larly those defined in Table 1, RG 1.97.
I Twenty-four (24) domestic and two (2) foreign utilities supported the Committee's efforts.
Seventeen (17) of these s
utilities provided representatives to serve on the committee.
A subcommittee of the RG 1.97 committee was formed (Feb. 1982) to address the issue of inadequate Core cooling (ICC) detection.
I Meetings of the committee commenced in April 1981 and con-l tinued through July 1982.
The sponsoring utilities and their 1
representatives who served on the 3RROG RG 1.97 Committee are identified at the end of this section.
The committee's work was devoted primarily to discussions of specific task assignments, to presentations of committee-and contractor-generated data related to RG 1.97 requirements, and to the formulation of recommendations based on the commit-cae's reviews and analyses.
Besides conducting its own studies, the committee contracted other analytical work to Roy
& Associates. Inc.; 5. Levy, Inc.; and the General Electric Company.
IAs used throughout.this report, RG 1.97 refers to RG 1.97, Revision 2, December 1980.
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A summary statement of the Owners Group position relative to RG 1.97 requirements is presented in Sec. 2; some proposed Type A variables, which are unspecified in RG 1.97, are defined in Sec. 3; a detailed owners's position statement on a variable-by-variable basis is provided in Sec. 4; and abstracts of the supporting analyses and studies are contained in Sec. 5.
Per-tinent contractor reports, a copy of Table 1 from RG 1.97, and a list of abbreviations are presented in the appendices.
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Sponsoring Utilities The sponsoring utilities of the BWR0G RC 1.97 Committee, their assigned contacts or committee members, and consultants are identified below.
Committee Membership (Names of the working members of the committee are in italics.)
Boston Edison Company RICH ST. ONGE; JERRY K TE:WSKI Cincinnati Gas & Electric Company WILLIAN CCCFER; ROGER THONET Cleveland Electric Illuminating Company RAY TANNEY Detroit Edison Company
.iCHN GREEN Georgia Power Company
'ACL 752RMAlll! (ICC chairman) (from Southern Company Services Inc.)
Culf States Utility Company MATEE RAHMAN; FNILLITS PCRTER Iowa Electric Light and Power Company
?CS ? (?CSI) 3 ALAS (Chairman)
Jersey caneral Power & Light Company JANES C.?ARDCS; PAUL PRCCACCI; ABDUL R. BAIG Long Island Lighting Company JCHN RIGERT Mississippi Power & Light Company SAM HOBBS; RUEUS BRCh?1 Northeast Utilities X%2ZC SLANCAFLCR Northern Indiana Public Service Company ADAM SHAHBAZI Pennsylvania Power & Light Company JCHN BARTCS; DAN CARDIN0BE Philadelphia Electric Company kFS SCWERS; RICK OGITIS Power Authority of the State of New York G. RANGARAC; J. STREET 3
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E Public Service Electric and Gas Ccmpany l
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Tennessee Valley Authority KATERYN ASHLEY: ROBER: 3CLLINGER i
Washington Public Power Supply System l
ARUN JOSK1; BUD HUNTING CN i
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Supporting Utilities t
4 Carolina Power & Light Company l
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t Centrales Nucleares Del Norte (S.A.)
Commonwealth Edison Company
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Ente, Nazionale per l' Energia Elettrica f
Illinois Power Company l
'lebraska Public Power District i
l Niagara Mohawk Power Corporation l
1 Northern States Power Company l
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EPRI/NSAC i
1 C. Dan Wilkinson, program manager (replaced by Robert Kubik for
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report coordination in Feb. 1982) i I
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General Electric Company j
S. Levy, Inc.
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Roy and Associates i
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2.
BWR OWNERS GROUP POSITION STATEMENT l
The BWROG position on NRC Rogulatory Guide 1.97, Revision 2, is presented in the following statement.
The statement l
reflects the intent of the regulatory positions sut forth in l
RG 1.97 but includes alternatives and deviations that relate to specific instrumentation requirements and to the particulars of their implementation.
l The statements that follow in this section are general positions on the requirements specified in the designated para-graphs of RG 1.97.
A detailed position statement on a variable-l by-variable basis is presented in Sec. 4, and supplementary data are provided in Sec. $ and in the appendices.
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General Poeltlon Statement BVROG concurs with the intent of RG 1.97, Revision 2.
The intent of the regulatory guide is to ensure that necessary l
and sufficient instrumentation exists at each nuclear power l
station for assessing plant and environmental conditions during and following an accident, as required by 10 CFR Part 50, Appendix A and General Design Criteria 13, 19, and 64 Imple-mentation of RG 1.97 requirements is recosenended except in those instances in which deviations from the letter of the l
guide are justified technically and when they can be imple-mented without disrupting the general intent of the Guide.
In assessing RC 1.97, the owners Group has drawn upon information contained in several applicable documents, such as ANS 4.5, NUREC/CR-2100, and the BWR00 Emergency Procedures l
Cuidelines, and on data derived from other analyses and stud-iss. The Owners Group believes that literal compliance with l
the provisions of the guide, because of their specific nature, is not appropriate.
Some RC 1.97 requirements call for exces-sive ranges or inappropriate categories.
Other requirements
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For example, research by S. Levy Inc., shows that core i
thermocouples will provide ambiguous information to SWR opera-4 tors.
The Owners Group intends to follow the criteria used by j
the NRC for establishing Category 1, 2, and 3 instruments, although it should be noted that Category 2 instruments could j
vary widely between utilities, because of various plant-unique f
features.
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The following owners Group compliance statement is appli-l l
cable to the regulatory positions defined in RG 1.97 Revision
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2 (the paragraph numbers cited correspond to those in RG 1.97).
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Accident-Monitorina Instrumentation Par. 1.1 The BWR Owners Group concurs with this defini-tion.
Par. 1.2:
The BWR Owners Group concurs with this defini-l tion.
I Par. 1.3 Instruments used for accident monitoring to meet the provisions of RG 1.97 shall have the proper sensitivity, J
range, transient response, and accuracy to ensure that the con-j l
trol room operator is able to perform his role in bringing the I
plant to, and maintaining it in, a safe shutdown condition and i
in assessing actual or possible releases of radioactive mete-f rial following an accident.
Each utility shall assess its plant accident-monitoring instrumentation system.
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Accident-monitoring instruments that are required to be j
environmentally qualified will be qualified to the requirement j
of NUREG-0588 and Memorandum and Order CLI-80-21. The seismic f
qualification of instruments will be based on individual assessments performed by each utility.
Each plant will comply with the quality assurance require-monts, using its approved quality assurance program, as described in the FSAA or elsewhere. This would ensure that accident-monitoring instruments comply with the applicable requirements of Title 10 CFR 50, Appendix 3.
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Each plant program for periodic checking, testing, cali-brating, and calibration verification of accident-monitoring instrument channels (RG 1.118) shall be in accordance with the utility's commitment, as specified in the FSAR, or elsewhere.
Par. 1.3.1: A third channel of instrumentation for l
Category 1 instruments will be provided only if a failure of one accident-monitoring channel results in information ambi-guity that would lead operators to defeat or fail to accomplish a required safety function, and if one of the following meas-ures cannot provide the information:
1.
Cross-checking with an independant channel that monitors a dif ferent variable bearing a known relationship to the variable being monitored.
2.
Providing the operator with the capability of per-turbing the measured variable to determine which channel has failed by observing the response on each instrument.
3.
The use of portable instrumentation for validation.
Category 1 instrument channels, which are designated as being part of a Class IE system, will meet the more stringent j
design requirements of either the system or the regulatory guide.
The requirements for physical independence of electrical systems (RG 1.75) shall be based on each plant's conniements in the FSAR, or elsewhere.
Par. 1.3.2:
The BWR Owners Group concurs with the regu-latory position for Category 2 instrumentation, except as modified by Par. 1.3 above.
Par. 1.3.3:
The BWR owners Group concurs with the regu-1 story position for Category 3 instrumentation.
Par. 1.4 To assist the control room operator, identifi-cation of instruments designated as Categories 1 and 2 for variable types A, B, and C should be made with due considera-tion of human factors engineering.
This position is taken to clarify the intent of RG 1.97, which specified that these 7
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Each plant program for periodic checking, testing, cali-I Stating, and calibration verification of accident-monitoring inscrument channels (RG 1.118) shall be in accordance with the 1
j utility's cotanitment, as specified in the FSAR, or elsewhere.
Par. 1.3.1:
A third channel of instrumentation for Category 1 instruments will be provided only if a failure of 1
I one accident-monitoring channel results in information ambi-guity that would lead operators to defeat or, fail to accomplish a required safety function, and if one of the following meas-ures cannot provide the information:
1.
Cross-checking with an independent channel that I
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monitors a different variable bearing a known relationship to r
l the variable being monitored.
2.
Providing the operator with the capability of per-l j
j turbing the measured variable to determine which channel has failed by observing the response on each instrument.
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The use of portable instrumentation for validation.
1 Category 1 instrument channels, which are designated as t
i being part of a Class IE system, will meet the more stringent I
design requirements of either the system or the regulatory guide.
The requirements for physical independence of electrical j
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systems (RG 1.75) shall be based on each plant's casunitments r
in the FSAR, or elsewhere.
j Par. 1.3.2: The BWR Owners Group concurs with the regu-latory position for Category 2 instrumentation, except as modified by Par. 1.3 above.
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Par. 1.3.3:
The BWR Ovners Group concurs with the regu-t i
latory position for Category 3 instrumentation.
J Par. 1.4: To assist the control room operator, identifi-cation of instruments designated as Categories 1 and 2 for j
variable typee A, 5, and C should be made with due considers-tion of human factors engineering. This position is taken to clarify the intent of RC 1.97, which specified that these 1
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instruments be easily discerned for use during accident condi-tions (see Issue 1 Sec. 5).
Par. 1.5:
The BWR Owners Group concurs with the regula-tory position taken in this section, except as modified by Par. 1.3 abova.
Par. 1.6 It is the position of BWROG that in terms of accident monitoring at a BWR facility, Table 1 of RC 1.97 does not represent a minimum number of variables and does not necem-sarily represent correct variable ranges or instrumentation categories.
Each BWR facility shall assess its compliance with the intent of RG 1.97 by establishing a list of accident-monitoring variables applicable to its own plant.
The classification of instrumentation used to measure the variables as Category 1, 2, or 3 shall be in compliance with the intent and method used in RG 1.97.
The 3WR owners Group position on the implementation of each variable described in Table 1 of RG 1.97 and in other applicable documents is presented in Sec. 4 2.
Systems Operation Monitoring and Effluent Release Moni-toring Inst rumentation The BWR Owners Group position stated in Par. 1.3 above is applicable to the Type D and E variables described in RG 1.97.
Par. 2.1: The BWR owners Group concurs with these definitions.
Par. 2.2:
Thn BWR Owners Group concurs with this regula-tory position.
Par. 2.3:
The BWR Owners Group concurs with this regula-tory position.
Par. 2.4 The BWR Owners Group concurs with this regula-tory position.
Par. 2.5:
The BWR Owners Group position as stated in Par.
1.6 abova is applicable to this regulatory position.
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implementation of Design Changes j
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The BW Owners Group reconsnands that the implementation t
I into each plant design of additional design changes, as required l
by RG 1.97, be integrated with the imploraentation of othe; con-f trol roctr design improvements.
A relctio.nhip exists between identifying accident-monitoring i
variables, developing operating procedures, revieving control j
I roca human factors engineering, and incorporating design changes I
into t!ie plant.
BWOG believe1 that an integrated approach f*
precludes the use of a specific implementation date for all BWR plants.
In this regard, the Owners Group reconumends that imple-mentation dates should be scheduled on a plant-by-plant basis.
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PROPOSED TYPE A VARIABLES Regulatory Guide 1.97, Revision 2, designates all Type A variables as plant-specific, thereby defining none in particu-lar. The Guide defines Type A variables as Those variables to be monitored that provide primary information required to permit the control room operator to take specific manu-ally controlled actions for which no automatic control is provided and that are required for safety systems to accomplish their safety functions for design basis accident events.
Regulatory Guide 1.97 defines primary information as "informa-tion that is essential for the direct accomplishment of the specified safety functions." Variables associated with con-tingency actions that may be identified in written procedures are excluded from this definition of primary information.
As part of their review of RG 1.97, the 3WR owners under-took the task of developing and analyzing a group of variables that were determined to be potential candidates for inclusion in RC 1.97 as specific Type A variables.
The variables identi-fled by the owners Group are generic in nature, and the appli-cability of a given variable to a particular facility should be determined on an individual utility basis.
In the summary that follows, two groups of variables are defined (1) proposed Type A variables and (2) potential Type A variables.
The variables listed are based on the BWR Owners Group Emergency Procedure Guidelines (EPC's). Although all of the operctor actions specified below may not be required to ensure that safety systems fulfill their safety functions in terms of design-basis events, they are nonetheless included in the interest of completeness.
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Variables identified as Type A (The variables listed here are also included in the tabu-lation of Sec. 4.)
Variable Al.
RPV Pressure Operator action:
(1) Depressurize RPV and maintain safe cooldown rate by any of several systems, such as main turbine bypass valves, isolation condenser, EPCI, RCIC, and RWCU:
(2) initiate isolation condenscr; (3) manually open one SRV to reduce pressure to below SRV setpoint if any SRV is cycling.
Safety function:
(1) Core cooling; (2) maintain reactor coolant system integrity.
Variable A2.
RPV 'Jacer Level Operator action:
Restore and maintain RPV water level.
Safety function:
Core cooling Variable A3.
Suppression Pool Water Temperature Operator action:
(1) Operate available suppression pool cooling system when pool temperature exceeds normal operating limits; (2) scram reactor if temperature reaches limit for scram; (3) if suppression pool temperature cannot be maintained below the heat capacity temperature limit, maintain RPV pressure below the corresponding limit; and (4) attempt to close any stuck-open relief valve.
Safety function:
(1) Maintain containment facegrity and (2) maintain reactor coolant system integrity.
Variable A4.
Suppression Pool Water Level Operator action:
Maintain suppression pool water 1evel
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within normal operating limits:
(1) transfer RCIC suction from the condensate storage tank (CST) to the suppression pool in the event of high suppression-pool level; and (2) if suppres-sion pool water level cannot' be maintained' below-the suppression pool load limit, maintain RPV' pressure below corresponding limit.
Safety function:
daintaincontainmentintegrity.
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Variable AS.
Drywell Pressure Operator action:
Control primary containment pressure by any of several systems, such as containment pressure con-trol systems, suppression pool sprays, drywell sprays.
Safety function:
(1) Maintain containment integrity and (2) maintain reactor coolant system integrity.
Potential Type A Variables (The following is a list of possible Type A variables to be determined at each plant; they are not included in Sec. 4.)
Variable 1.
Condensate Storage Tank Level Operator action: Transfer HPCI or RCIC suction or both from CST to suppression pool.
Discussion:
NRC has recommended automatic suction trans-fer for RPCI and RCIC. This variable is not a Type A variable if the automatic suction transfer is installed.
l Variable 2.
Emergency Diesel Generator (EDG) Load Operator action:
Control loading of the EDG's.
Discussion:
Some plants have a planned manual action to verify the loading on the EDG's before any other safety-related loads are added.
If no planned action is necessary, this vari-able is not type A.
Variable 3.
Reactor Building Flood Level Operator action:
Initiate pump-back of sump to suppression pool.
Discussion: Water can accumulate in the reactor building during long-term cooling with any postulated leakage.
The flood-level indication would alert the operator to a problem, but this indication is an, aid to and not the accomplishment of a safety function.
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Variable 4.
Drywell Tempe:rature Opecater action:
Ir.itiate sprays, reactor water level compersation.
Discussion:
This variable may be needed for reactor-water-level compensation.
Note: Although the EPG's mention drywell temperature, the drywell pressure is the key variable for con-tainment integrity; drywell temperature is a secondary consid-eration. This issue will be addressed by the ICC subcommittee.
Variable 5.
Suppression Pool Pressure Operator action:
Initiate suppression pool sprays.
Discussion:
The suppression pool sprays are not used in safety analysis. Although the EPG's use suppression pool pres-sure to initiate suppression pool spray, containment pressure may be used to approximate the suppression pool pressure.
Variable 6.
Oxygen or Hydrogen Concentration Operator action:
If containment atmosphere approaches the combustible limits, initiate combustible gas control systems.
Oxygen for inerted and hydrogen for non-inerted containments.
Safety function:
Maintain containment integrity.
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PLANT VARIABLES i:OR ACCIDENT MONITORING i
l BUROG positions on the implementation of the variables listed in Table 1 of RC 1.97 and on the assignment of design and l
qualification criteria for the instrumentation proposed for their measurement is summarized in the tabulation that follows.
I In brief, the measurement of the five variable types provides the following kinds of information to plant operators during and after an accident:
(1) Type A--primary information, j
on the basis of which operators take planned specified manually controlled actions; (2) Type B--information about the accom-plishment of plant safety functions; (3) Type C--information about the breaching of barriers to fission product release; (4) Type D--information about the operation of individual safety 1
systems; and (5) Type E--information about the magnitude of the release of radioactive materials.
The three categories shown for the variables define the design and qualification criteria for the instrumentation that-is to be used for their measurement.
Category 1 imposes the most stringent requirements; Categories 2 and 3 impose pro-gressively less stringent requirements.
The categories are also related (in RG 1.97) to " key variables." Key variables are defined differently for the different variable types. For Type B and Type C variables, the key variables are those variables that most directly iniiaate :he acc:mplishment of a safa y f:maticn; instrumenta-tion for these key variables is designated Category 1.
Key variables that are Type D variables are defined as those vari-ables that most directly indicara he operation of a safety system; instrumentation for these key variables is usually Category 2.
And key variables that are Type E variables are defined as those variables that most directly inaicate the release of radioactive material; instrumentation for these key 14
variables is also usually Category 2.
A complete discussion of the variable types and instrumentation design criteria is presented in RG 1.97.
It should be noted that the Type A variables listed below are being proposed for inclusion in RG 1.97 on the basis of analyses conducted by the Owners Group (Sec. 3).
Table 1 of RG 1.97 designates all Type A variables as plant specific and thus defines none in particular.
The variables are listed here in the same sequence used in Table 1, RG 1.97; however, for convenience in cross-referencing entries and supporting data, the variables are designated by letter and number.
For example, the sixth B-type variable listed in RG 1.97 is denoted here as variable B6.
(A copy of Table 1 from RG 1.97 is provided in Appendix C.)
BWROG's position is shown for each variable and for its instrumentation design criteria and category.
(The letters CG and RG preceding the category numbers identify the Owners Group and RG 1.97, respectively.)
In general, there are three kinds of responses or recommendations:
(1) implement the variable and required instrumentation in accordance with the regulatory position stated in Table 1, RG 1.97 (2) implement, with quali-fying exceptions or revisions; and (3) do not implement.
As necessary, the positions of BWROG are elaborated or substantiated in the Supplementary Analyses section (Sec. 5) or in supplementary documents provided in the appendixes..7ote that references to the data in Sec. 5 are made by ci:ing the issue numbers tha: appear in the upper corner of :he pages in SJc. 5.
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Type A Variables The following Type A variables are recommended by the Owners Group (OG) for inclusion in RG 1.97 as type A.
(See Sec. 3.)
Al.
Reactor pressure (OG Category 1)
REC 0FDIENDATION:
Implement.
See B6, C4, and C9.
A2.
Coolant level in reactor (OG Category 1)
REC 0501ENDATION:
Implement.
Sea B4.
A3.
Suppression pool water temperature (OG Category 1)
REC 0!DIENDATION:
Implement.
See D6.
A4.
Suppression pool water level (OG Category 1)
RECOMMENDATION:
Implement.
See C7 and DS.
AS.
Drywell pressure (OG Category 1)
RECOMMENDATION:
Implement. Type A for plants without autostarting drywell spray.
See B7, B9, CS, C10, and D4 16
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Type B Variables Reactivity Control Bl.
Neutron Flux (OG Category 2; RG Category 1)
RECOMMENDATION:
Implement, but as Category 2 with alarm and reduced range, in accordance with data in Issue 2.
B2.
Control Rod Position (OG Category 3; RG Category 3)
RECOMMENDATION:
Implement B3.
RCS Soluble Boron Concentration (sample) (OG Category 3; RG Category 3)
RECOMMENDATION:
Implement Core Cooling B4.
Coolant Level in Reactor (OG Category 1; RG Category 1)
RECOMMENDATION: Implement.
See A2, C3, and l
Issue 3.
35.
3WR Core Thermocouples (RG Category 1)
RECOMMENDATION: Do not implement.
See C3 and Appendix A.
.'!aintaining Reac:or Coolant Syster: Enregrity B6.
RCS Pressure (OG Category 1; RG Category 1)
RECOMMENDATION:
Implement.
See A1, C4, C9, and Issue 3.
37.
Drywell Pressure (OG Category 1; RG Category.1)
RECOMMENDATION:
Implement. See B9, C8, C10, and D4.
l B8.
Drywell Sump Level (OG Category 3; RG Category 1)
RECOMMENDATION:
Implement as Category 3.
See C6 and Issue 4.
Maintaining Containment Integrity B9.
Primary Containment Pressure (OG Category 1; RG Category 1) l RECOMMENDATION:
Implement.
See B7, CS, C10, and D4 B10. Primary Containment Isolation Valve Position (excluding check valves) (OG Category 1; RG Category 1)
RECOMMENDATION:
Implement. Redundant indication is not required on each redundant isolation valve.
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I Type C Variables
?uel Cladding Cl.
Radioactivity Concentration or Radiation Level in Circu-lacing Primary Coolant (RG Category 1)
RECOMMENDATION: Do not implement.
See Issue 5.
C2.
Analysis of Primary Coolant (gamma spectrum) (OG Category 3; RG Category 3)
RECOMMENDATION:
Implement C3.
BWR Core Thermocouples (RG Category 1) i RECOMMENDATION:
Do not implement.
See 35 and Appendix A.
Racator Coolant Prescure Scundary C4.
RCS Pressure (OG Category 1; RG Category 1)
RECOMMENDATION:
Implement.
See A1. B6, and C9.
l C5.
Primary Containment Area Radiation (OG Category 3; RG Category 3)
RECOMMENDATION:
Implement.
See El.
C6.
Drywell Drain Sumps Level (identified and unidentified leakage) (OG Category 3; RG Category 1)
RECOMMENDATION:
Implement as Category 3.
See 38 and Issue 4.
C7.
Supprest ion Pool Water Level (OG Category 1; RG Category 1)
RECOMMENUATION:
Implement.
See A4 and DS.
g C8.
Drywell Pressure (OG Category 1; RG Category 1)
RECOMMENDATION:
Implement.
See B7, B9, C10, and D4.
Containnent C9.
RCS Pressure (OG Category 1; RG Category 1) g RECOMMENDATION:
Implement.
See AL, B6, and C4.
C10. Primary Containment Pressure (OG Category 1; RG Category 1)
RECOMMENDATION:
Implement.,See B7, B9, CS, and D4.
l Concentration (OG Category 1; C11. Containment and Drywell H2 RG Category 1)
RECOMMENDATION:
Implement 18
C12. Containment and Drywell Oxygen Concentration (for inerted containment plants) (OG Category 1; RG Category 1) l RECOMMENDATION:
Implement.
Cl3. Containment Effluent Radioactivity--Noble Gases (from identified release points including Standby Gas Treatment System Vent) (OG Category 3; RG Category 3)
RECOMMENDATION:
Implement C14. Radiation Exposure Rate (inside buildings or areas, e.g.,
auxiliary building, fuel handling building, secondary containment, which are in direct contact with primary containment where penetrations and hatches are located)
(RG Category 2)
RECOMMENDATION:
Do not implement.
See E2, E3, and Issue 6.
C15. Effluent Radioactivity--Noble Cases (from buildings as indicated above) (OG Category 2; RG Category 2)
RECOMMENDATION:
Implement a
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e Type D Variables Condensate and Feed:0ater System Dl.
Main Feedwater Flow (OG Category 3; RG Category 3)
RECOMMENDATION:
Implement D2.
Condensate Storage Tank Level (OG Category 3; RG Category 3)
RECOMMENDATION:
Implement Primry Containment-Related System D3.
Suppression Spray Flow (RG Category 2)
RECOMMENDATION: Do not implement.
See Issue 7.
D4.
Drywell Pressure (OG Category 2; RG Category 2)
RECOMMENDATION:
Implement.
See B7, B9, C8, and C10.,
l D5.
Suppression Pool Water Level (OG Category 2; RG Category 2) l RECOMMENDATION:
Implement.
See A4 and C7.
D6.
Suppression Pool Water Temperature (OG Category 2; RG Category 2)
RECOMMENDATION:
Implement.
Both local and bulk temperature.
See A3.
D7.
Drywell Atmosphere Temperature (OG Category 2; RG Cate-gory 2)
RECOMMENDATION:
Implement.
See Issue 8.
D8.
Drywell Spray Flow (RG Category 2)
RECOMMENDATION: Do not implement.
See Issue 7.
Main Steam System D9.
Main Steamline Isolation Valves' Leakage Control System l
Pressure (OG Category 2; RG Category 2) l RECOMMENDATION:
Implement if system is part of plant design.
l l
D10. Primary System Safety Relief Valve Position, Including
~
ADS or Flow Through or Pressure in Valve Lines l
(OG Category 2; RG Category 2)
RECOMMENDATION:
Implement 20
Safery Systems D11. Isolation Condenser System Shell-Side Water Level (0G Category 2; RG Category 2)
RECOMMENDATION:
Implement if system is part of plant design.
D12. Isolation Condenser System Valve Position (OG Category 2; RG Category 2)
RECOMMENDATION:
Implement if system is part of plant design.
D13. RCIC Flow (OG Category 2; RG Category 2)
RECOMMENDATION:
Implement.
See Issue 9.
D14. HPCI Flow (0G Category 2; RG Category 2)
RECOMMENDATION:
Implement.
See Issue 9.
D15. Core Spray System Flow (OG Category 2; RG Category 2)
RECOMMENDATION:
Implement.
See Issue 9.
D16. LPCI System Flow (OG Category 2; RG Category 2)
RECOMMENDATION:
Implement.
See Issue 9.
D17. SLCS Flow (OG Category 3; RG Category 2)
RECOMMENDATION:
Implement as Category 3.
Await ATWS resolution.
See Issue 9.
D18. SLCS Storage Tank Level (OG Category 3; RG Category 2)
RECOMMENDATION:
Implement as Category 3.
Await ATWS resolution.
See Issue 10.
Residual Heat Removal (?HR) systems D19. RHR System Flow (OG Category 2; RG Category 2)
RECOMMENDATION:
Implement D20. RHR Heat Exchanger Outlet Temperature (OG Category 2; RG Category 2)
RECOMMENDATION:
Implement Cooling Water Syarem D21. Cooling Water Temperature to ESF System Components (CG Category 2; RG Category 2)
RECOMMENDATION:
Interpret as main system flow and implement.
21 e
0 4
D22. Cooling Uater Flow to ESF System Components (OG Category 2; RG Category 2)
REC 0mfENDATION:
Interpret as main system flow and implement.
Raduaste Syctems D23. High Radioactivity Liquid Tank Level (OG Category 3; RG Category 3)
REC 0!c!ENDATION:
Implement Ventilation Systems D24. Emergency Ventilation Damper Position (OG Category 2; RG Category 2)
REC 0!!MENDATION:
Interpret as meaning dampers actuated under accident conditions and whose failure could result in radioactive discharge to the environment.
Control room damper position should be indicated.
Implement.
Pouer Supplica D25. Status of Standby Power and Other Energy Sources Important to Safety (hydraulic, pneumatic) (OG Category 2; RG Category 2)
REC 0m!ENDATION:
Implement; on-site sources only.
(Note: The addition of the follouin.] D-type variables is reccrmended by BWRCG; see Daue ll, Sec. S.)
D26. Turbine Bypass Valve Position (OG Category 3)
RECOMMENDATION: Add to RG 1.97.
See Issue 11.
D27. Condenser Hoewell Level (OG Category 3)
RECOMMENDATION: Add to RG 1.97.
See Issue 11.
D28. Condenser Vacuum (OG Category 3)
RECOMMENDATION: Add to RG 1.97.
See Issue 11.
D29. Condenser Cooling Water Flow (OG Category 3)
RECOMMENDATION: Add to RG 1.97.
See Issue 11.
i D30. Primary Loop Recirculation Flow (OG Category 3)
~
RECOMMENDATION:
Add to RG 1.97.
See Issue 11.
66A I
22 L
J
=
r Type E Variables Ccntainment Radiation El.
Primary Containment Area Radiation--High Range (OG Category 1; RG Category 1)
RECOMMENDATION:
Implement in accordance with NUREG-0737 commitment.
See C5.
E2.
Reactor Building or Secondary Containment Area Radiation (RG Category 2 for Mark I and II containments; OG Category 1 and RG Category 1 for Mark III containments)
RECOMMENDATION:
Do not implement for Mark I and II con-tainments.
Implement for Mark III containments.
See C14 E3, and Issue 12.
Area Radia:icn E3.
Radiation Exposure Race (inside buildings or areas where access is required to service equipment important to safety) (OG Category 3; RG Category 2)
RECOMMENDATION:
Implement as Category 3, using existing instrumentation.
See C14, E2, and Issue 13.
Airborne Radicactive Materiata Released frcm ?lant E4.
Noble Gases and Vent Flow Rate (OG Category 2; RG Cate-gory 2)
RECOMMENDATION:
Implement ES.
Particulates and Ralogens (OG Category 3; RG Category 3)
RECOMMENDATION:
Implement Environa Radiation and Radioactivity E6.
Radiation Exposure Meters (continuous indication at fixed locations)
RECOMMENDATION:
Deleted.
See NRC arrata of July 1981.
E7.
Airborne Radiohalogens and Particulates (portable sampling with on-site analysis capability) (OG Category 3; RG Cate-gory 3)
RECOMMENDATION:
Implement E8.
Plant Environs Radiation (portable instrumentation)
(OG Category 3; RG Category 3)
RECOMMENDATION:
Implement (portable equipment)
E9.
Plant and Environs Radioactivity (portable instrumenta-tion) (OG Category 3; RG Category 3)
RECOMMENDATION:
Implement (portable equipment) 23
Meteorology E10. Wind Direction (OG Category 3; RG Category 3)
REC 0deiENDATION:
Implement Ell. Wind Speed (OG Category 3; RG Category 3)
REC 050tENDATION:
Implement E12. Estimation of Atmospheric Stability (OG Category 3; RG Category 3)
REC 050tENDATION:
Implement Accident-sqting Capability Unatyaia Capability Cn-sica)
E13. Primary coolant and Sump (OG Category 3--Primary Coolant only; RG Category 3)
REC 0101ENDATION:
Implement Primary Coolant.
Do not implement Sump.
See Issue 14.
E14. Containment Air (OG Category 3; RG Category 3)
RECOMMENDATION:
Implement t
Ge m
A.m O d' iga l
24 6
9 5.
SUPPLEMENTARY ANALYSES These supplementary analyses support positions cited in Sec. 2 (Issue 1) and Sec. 4 (Issues 2-14).
Contents Issue 1.
Ins trument Identification Issue 2.
Variable B1 Issue 3.
Trend Recording Issue 4.
Variables B8 and C6 Issue 5.
Variable.C1 Issue 6.
Variable C14 Issue 7.
Variables D3 and D8 Issue 8.
Variable D7 Issue 9.
Variables D13-D17 Issue 10. Variable D18 Issue 11. Variables D26-D30 Issue 12. Variable E2 Issue 13. Variable E3 Issue 14. Variable E13 25
O i]:1 ISSUE 1.
INSTRUMENT IDENTIFICATION lasue Definition Regulatory Guide 1.97 specifies, in par.1.4.b, the following:
"The instruments designated as Types A, B, and C and Categories 1 and 2 should be specifically identified on the control panels so that the operator can easily discern that they are intended for use under accident conditions."
Discussion i
The objective of this regulatory position is the achieve-ment of good human factors engineering in the presentation of information to the control room operator. This objective is best achieved by evaluating current practices and procedures that provide for identifying instruments in a manner that aids the operator; redundant labels would tend to distract the oper-ator and cause confusion. The Control Room Design Review of the BWR Owners Group has the charter to provide a basis for assuring proper identification of accident instrumentation with consideration for current information for safe plant shutdown, operational training, and procedures.
Conclusion' Instruments designated as Categories 1 and 2 for monitor-ing variable types A, B, and C should be identified in such a manner as to optimize applicable human factors engineering and presentation of information to the control room operator.
This position is taken to clarify the intent of RG 1.97, which specifies that these instruments be easily discerned for use during accident conditions, l
i 26 j
W s' ake L
ISSUE 2.
val 91ABLE B1 Bl: Neutron Flux lasue Definition The measurement of neutron flux is specified as the key variable in monitoring the status of reactivity. Neutron flux is classified as a Type B variable, Category 1.
The specified range is 10-6 percent to 100 percent full power (SRM, APRM). The stated purpose is " Function detection; accomplishment of mitigation."
s Discussion The lower end of the specified range, 10-6 percent full power, is intended to allow detection of an approach to criti-cality by some undefined and noncontrollable mechanism after shutdown.
In attempting to analyze the performance of the neutron-flux monitoring systems, a scenario was postulated to obtain the required approach to criticality. Basically, it assumes an increase in reactivity from loss of boron in the reactor water.
The accident scenario incorporates the following factors:
1.
The control rods fail (completely or partially) to I
insert, and the operator actuates the standby liquid control system (SLCS).
2.
The SLCS shuts the reactor down.
3.
A leak in the primary system results in an outgo of borated water and its replacement by water that contains no Doron.
4 A range of leak rates up to 20 gpm was considered (see Table 1).
4 27
E Calculations were made to evaluate the rise in neutron population as a function of different leak rates. The cal-culations were made for a shutdown neutron level of 5 x 10-8 percent of full power. The choice of 5 x 10-8 is based on measurements at two nuclear plants. The shutdown level was assumed to have a negative reactivity of 10 dollars, an assumption that is representative of a shutdown with all rods inserted. The results of the calculations are presented in Table 1.
The numbers in the table refer to the time in hours required to increase the flux by 1 decade. For example, with a leak of 5 gpm, it takes 100 hr to increase the power from 5x 10-8 percent to 5 x 10-7 percent, and 10 hr to increase it from 5 x 10-7 percent to 5 x 10 6 percent.
The reactor is suberitical and the neutron level is given by Neutron level = S x M, where S is the source strength and M is the multiplication, which is given by M = 1/(1 - k).
For k = 0.9, M is 10; for k = 0.99, M is 100 and so forth.
For criticality, the denominator approaches 0, as k approaches 1.0.
Thus, the calculation model used the above equation to calculate relative neutron flux levels for.a subcritical reac-tor until the reactor was near critical; then the critical equation of power with excess reactivity was used. Reactor power is directly proportional to neutron level.
The increase in reactivity toward criticality can be turned around by actuating the SLCS. It is ass:mred that oper-atingprocedzwes provide for refitting the SLCS tank soon after its actuation. A second actuation of the SLCS would cause a decrease in reactivity because of the high concentration of baron in the injected SLCS fluid relative to that in the leak-I f
ing fluid (nominally 400 ppe). The sensitivity of the detector must allow adequate time for the operator to act. Ten minutes
i i"*'
' ')
l l
is considered sufficient time for operator action for accident prevention and mitigation.
- Table 1 shows that the detector sensitivity (i.e., icwer range) requirement is a function of leak rate and therefore of reactivity-addition rate. On the basis of a 20-gpm leak l
4 rate, Table i shows that a detector that is on scale within 3 decades of the shutdown power would allow 0.18 hr (10.8 min) i for operator action before reactor power increased another j
i decade. A total of 0.36 he (21.6 min) would be available for operator action from th'e time the indicator comes on scale to the time reactor power reaches 0.5 percent of full power. An 1
i alarm would be provided to warn the operator when the neutron i
flux starts to increase beyond a plant-specific set-point.
The 20-gpm leak rate, which was assumed to continue for 27.75 hr, was used to define the sensitivity of the detector.
it should be noted that the assumed leak rate, extended over the 27.75-hr period, would result in a loss of inventory so f
large that it could not in reality go undetected by the oper-ator. Moreover, reactivity-addition caused by this gradual boron depletion is unlikely, since baron concentration is sampled and measured periodically. Again, the improbable 20-gpa leak rate was used only to obtain a mechanistic and j
i conservative approach for selection of instrument sensitivity.
)
An absolute ciriterion for the lower range must include consideration of the neutron source level. The use of the i
neutron level 100 days after shutdown is conservative. There 1
is high probability that conditions would be stable and con-tro11able 2 daya after the emergency shutdown, for the core-decay heat is at a low level and the boron monitoring system should be functioning by that time. The actual neutron level will vary with fuel design, ' fuel history, and shutdown con-trol strength. Measurements of shutdown neutron flux (with all rods inserted) at two BWK reactors show readings of 30 to 80 counts /sec (1000 counts /sec corresponds to 10-8 of full
^
29 -
4 m,
m v-
power). Measurements on other BWR reactors and for different fuel histories would show some variation, but those variations would be small compared with a criterion that is concerned with units of decades.
Regulatory Guide 1.97 classifies the instrumentation for measuring a variable as Category 1 on the basis of-(1) whether it is a key variable (defined in Sec. 4), and (2) its importance to safety. Neutron flux is the key variable for measuring reactivity control, thus meeting the requirement of criterion (1). The degree to which this variable is important to safety is another consideration. The large number of detectors (i.e.,
source-range monitors and intermediate-range monitors) that are driven into the core soon after shutdown makes it highly probable that one or more of the existing NMS detectors will be inserted. On the other hand, there is little probability that there would be, simultaneously, a need for this measure-ment (in terms of operator action to be taken),and an acci-dent environment in which the NMS would be rendered inoperable.
Further, the operator can always actuate the SLCS on loss of instrumentation.
Although some upgrading of the current NMS may be appro-priate to improve system reliability and its ability to survive a spectrum of accidents, a rigorous Category 1 requirement is not justified when the purpose and use of the measurement are analyzed as they relate to the criterion of "importance to safety." A Category 2 classification of this variable fully n.eets the intent of RG 1.97.
i Four alternative design approaches to meeting the neutron flux requirements of RG 1.97 have been identified. All four i
alternatives would provide indication over the range recom-mended by BWROG, using state-of-the-art' electronics for dis-playing the detector reading. A particular utility can choose i
a suitable alternative, based on its own design evaluation.
l The principal features of cne four alternatives are presented below.
i l
30
I Al ternative 1.
The first al ternat ive provides for upgrading two or more of the source-range monitors (SMt's).
The upgrading includes the connecting cable inside the drywell and the power source for the SRM drives. At least two SRM's would have dual roles of accident instrumentation and normal start-up; these two SRM's would be withdrawn a lesser dis-tance from the core than the SRM in the current design.
It is estimated that,in its fully withdrawn position, the cur-rent SRM will detoct about 10-3 or 10-5 percent of full power.
This sensitivity can be increased by using a withdrawn posi-tion that is less than the present 2-2.5 ft from the core.
I A withdrawn position that produces 10 percent depletion in 5 years was used as a guide to the marirmm allowed burn-up of the sensor. This position below the core would give the SRM a detection capability of about 2 x 10-7 percent of full power.
The SRM drives need not be upgraded, because the upgraded detector system would be adequate, even if the drive did not move the SRM detector.
(An upgraded power source for the drives improves the probability of insertion.) The success of this alternative--which uses the four SRM's for normal start-up--depends on a design modification to accommodate the new cable (the key concern is the flexibility of the cable, for the detector moves about 10 ft; this movement is accommo-dated in the cable loop) and on the design of a limit switch or a decent mechanism to hold the drive tube in the required intermediate position.
Alternative 2.
The second alternative is to replace two or more SRM systems with upgraded systems. The full SRM system, including the drives, would be upgraded. This approach would require input from a potential equipment aupplier in order to estimate schedules, cost, and overall effect of the upgrading. Whereas the first alternative uses upgraded cables and power supply (which are conumercially available), this 31
e approach would require additional engineering to achieve an upgraded drive system as well. A Category 1 drive system is a developmental item.
Alternative 3.
In the third alternative, fixed in-core detectors are used. The system uses SRM-type detectors as stationary detectors that are positioned close enough (as dis-cussed above) to the core to meet the lower range requirements.
New cables are needed to meet the requirements of the accident environment. This system would provide dedicated " accident monitors" in two of the intermediate-range monitor (IRM) tubes or in two local-power range-monitor (LPRM) tubes.
It may be feasible to put five detectors in the LPRM tube or, if space is limited, the bottom detector of the LPRM string could be replaced with the " accident" detector. With this approach the four movable SRM's would continue to be available for normal functions.
Alternative 4 In the final alternative, out-of-core detectors, which are being qualified for use in pressurized water reactors (PWR's), are used. Considerations of this ongoing PWR qualification program for Category 1 instrumen-tation and the lack of any ef fect on the current neutron moni-toring system (NMS) make this alternative an attractive one.
The k'ey question is whether these out-of-core detectors can meet the lower range requirement, for the detectors are posi-tioned outside the RPV shield wall. A test is needed to demonstrate that the neutron count at this location is ade-Based on calculations of neutron flux made for a BWR quate.
at full power (see Fig.1) and on current detector design Other practices, the out-of-core detector may be feasible.
effects, such as attenuation by water that is at a lower tem-perature (than the full-power operating temperature) and by boron in the water, need to be considered.
9 e
32
o w m.
Conclusion A range from 5 x 10-5 percent of full power (within 3 decades of the neutron flux level 100 days af ter shutdown) to An alarm is also 100 percent of full power is recommended.
recommended that would alert the operator of a rise in neutron It is concluded that a Category 2 classification is flux.
responsive to the intent of RG 1.97, as cre the four alterna-tives, provided that the design program resolves the specific design concerns identified in the Discussion.
33 a
t 4
TABLE 1.
RELATIVE NEUTRON FLUX VERSUS TIME l
r Leakage rate, gpm (ramp rate, c/ min)b 1(0.03) 5(0.15) 20(0.60) ercent i
power I
a E
a E
a i
5x 10-8
-555 500
-111 100
-27.75 25 I
5x 10-7
-55 50
-11 10
-2.75 2.5 i
5
- 10-6
-5 5
-1 1
-0.25 0.25 5 = 10-5 0
0 0
5x 10-"
0.8 0.8 0.36 0.36 0.18 0.18 1
5x 10-3 1.33 0.53 0.51 0.15 0.25 0.07 l
5 = 10-2 1.59 0.26 0.62 0.11 0.31 0.06 I
5 = 10-1 1.80 0.21 0.72 0.10 0.36 0.05 i
5 = 10 1.89 0.09 0.80 0.08 0.40 0.04 i
" Shutdown flux = 5 x 10-8 percent of power.
bg - total number of hours; 4 = hours for neutron flux to increase by one decade.
O l
i e
34
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3
7 ISSUE 3.
TREND RECORDING lasue Definition The purpose of addressing Issue 3 is to determine which variables set forth in RG 1.97 require trend recording.
Discussion Regulatory Guide.l.97, par. 1.3.2f, states the general requirement for trend recording as follows:
'%ere direct and immediate trend or transient information is essential for operator information or action, the recording should be con-cinuously available for dedicated recorders." Using the BWR Owners Group Emergency Procedures Guidelines (EPG's) as a basis, j
the only trended variables required for operator action are reactor water level and reactor vessel pressure.
Conclusion On a generic basis, only reactor water level (variable B4) and reactor vessel pressure (variable B6) require trend recording; however, other variables may be necessary on a plant-specific basis.
1
pg un ISSUE 4.
VARIABLES B8 AND C8 B8: Drywell S' ump Level C6: Drywell Drain Sumps Level lesue Definition Regulatory Guide 1.97 requires Category 1 instrumentation to monitor _.drywell sump level (variable B8) and drywell drain sumps level (variable C6). These designations refer to the dryvell equipment and ficor-drata tank levels. Cacigory 1 instrumentation indicates that the variable being monitored is a key variable.
In RG 1.97, a key variable is defined as
"... that sinele variable >(or minimum number of variables) that most directly indicates the accomplishnent of a safety function.. ~." The following discussion supports the BWR
~
Owners Group alternative position that drywell sump level and drywell drain-sumps icvels should be classified as Category 3 instrumentation.
Discussion The BWR. Mark I, II, and III drywells have two drain sumps.
One drain is the equipment drain sump, which collects identi-fled leakaga; the other is the. fler drain sump, which collects unidentif ted leakage.
Although the level of the drain sumps can be a direct indi-cation of bruach of the reactor coolant system pressurs boundary, the indication is not unadiguous, b-suse there is water in those sumps during normal opetation. There is other instru-mentation required by RG 1.97 that would indicate 'eakage in the drywell:
1.
Dryve11 pressure-var'iabla 87, Category 1 2.
Drywell temperature-variable D7, Catagory 2
(
37
__m______________
3.
Primary containment area radiation--variable C5, Category 3 The drywell-sump levei signal neither automatically ini-tiates safety-related systems nor alerts the operator to the need to take safety-related actions.
Both sumps have level detectors that provide only the following nonsafety indications:
1.
Continuous icvel indication (some plants) 2.
Rate of rise indication (some plants) 3.
High-level alarm (starts first sump pump) 4 High-high-level alarm (starts second sump pump)
In addition, timers are used in most plants to indicate the duration of sump-pump operation and thereby permit the amount of leakage to be estimated.
Regulatory Guide 1.97 requires instrumentation to function during and after an accident. The drywell sump systems are deliberately isolated at the primary containment penetration upon receipt of an accident signal to establish containment integrity. This fact renders the drywell-sump-level signal irrelevant. Therefore, by design, drywell-level instrumenta-tion serves no useful accident-monitoring function.
The Emergency Procedure Guidelines use the RPV level and the drywell pressure as entry conditions for the Level control,
Guideline. A small line break will cause the drywell pressure to increase before a noticeable increase in the sump level.
Therefore, the drywell sumps will provide a " lagging" versus "early" indication of a leak.
Conclusion Based on the above considerations, the SWR Owners Group helieven that the drywell-mino level and drywell-drain-sume level ins tr'imentation should be cla.all Led am Cai t.... y i.
"high-quality off-the-shelf instrumaacatien."
e 38
t
~
- ,F
~*
tf~
m ISSUE 5.
VARIABLE C 1 j
C1: Radioactivity Concentration or Radiation Level in Circulating Primary Coolant i
lesue Definition Regulatory Guide 1.97 specifies that the status of the t
fuel cladding be monitored during and af ter an accident. The specified variable to accomplish this monitoring is variable 4
Cl--radioactivity concentration or radiation level in circulat-ing primary coolant. The range is given as "1/2 Tech Spec-Limit to 100 times Tech Spec -Limit, R/hr." In Table 1 of i
RG 1.97, instrumentation for measuring variable C1 is desig-nated as Category.1. The purpose for monitoring this variable is given as " detection of breach," referring, in this case, to breach of fuel cladding.
Discussion i
The usefulness of the information obtained by monitoring the radioactivity concentration or radiation level in the cir-1 culating primary coolant, in terms of helping the operator in his efforts to prevent and mitigate accidents, has not been substantiated. The critical actions that must be taken to prevent and mitigate a gross breach'of' fuel cladding are'(1) 4 shut down the reactor and (2) maintain water level. Monitoring variable C1, as directedin RG 1.97, will have no influence on either of these actions. The purpose of this monitor falls in the category of "information that the barriers to ' release of i
l radioactive material are being, challenged" and." identification
.r l
s of degraded conditions and their magnitude,.so the operator can i
y take actions that are available to mitigate the consequences."
- i s '.u,.'
i h
n
(
, ' _, Jr 39 m[;
i j
u
1
- 7?}
J l
Additional operator actions to mitigate the consequences of fuel barriers being challenged, other than those based on Type A and l
B variables, have not been identified.
Regulatory Guide 1.97 specifies measurement of the radio-l activity of the circulating primary coolant as the key variable in monitoring fuel cladding status during isolation of the NSSS.
The words " circulating primary coolant" are interpreted to mean coolant, or a representative sample of such coolant, that flows past the core. A basic criterion for a valid measurement of i
the specified variable is that the coolant being monitored is i
coolant that is in active contact with the fuel, that is, flow-i ing past the failed fuel. Monitoring the active coolant.(or a sample thereof) is the dominant consideration. The post-accident sampling system (PASS) provides a representative sample which can be monitored.
i The subject of concern in the RG 1.97 requirement is assumed to be an isolated NSSS that is shutdown. This assump-tion is justified as current monitors in the condenser off-gas and main steam lines provide reliable and accurate information on the status of fuel cladding when the plant is not isolated.
i I
Further, the post-accident sampling system (PASS) will provide an accurate status of coolant radioactivity, and hence cladding status, once the PASS is activated.
In the interim between NSSS isolation and operation of the PASS, monitoring of the primary containment radiation and containment hydrogen will provide information on the status of the fuel cladding.
Conclusion 4
The designation of instrumentation for measuring variable Ci should be Category 3, because no planned operator actions are identified and no operator actions are anticipated based on this variable serving as the key variable. Existing Cate-gory 3 instrumentation is adequate for monitoring fuel cladding status.
40
.e ISSUE 6.
VARIABLE C 14 C14: Radiation Exposure Rate issue Definl' tion Variable C14 is defined in Table 1 of RG 1.97 as fellows:
" Radiation exposure rate (inside buildings or areas, e.g.,
auxiliary building, fuel handling building, secondary contain-ment), which are in direct contact with primary containment where penetrations and hatches are located." The reason for monitoring variable C14 is given as " Indication of breach."
Discussion The use of local radiation exposure rate monitors to detect breach or leakage through primary containment penetrations is impractical and unnecessary. In general, radiation exposure rate in the secondary containment will be largely a function of radioactivity in primary containment and in the fluids flowing in ECCS piping, which will cause direct radiation shine on the area monitors. Also, because of the amount of piping and the number of electrical penetrations and hatches and their widely scattered locations, local radiation exposure rate monitors could give ambiguous indications. The proper way to detect breach of containment is by using the plant noble gas effluent monitors.
C:onclusicH1 Using radiation exposure ente monitors to detect primary j
containment breach is neither feasible nor necessary. Other
/
41
means of breach detection that are better suited to this function (as described above), are available. Therefore, it is the position of the BWR Owners Group that this parameter not be implemented.
1 42
FN"7 beb ISSUE 7.
VARIABLES D3 AND D8 D3: Suppression Spray Flow
'D8: Drywell Spray Flow issue Definition Regulatory Guide 1.97 specifies flow measurements of suppression chamber spray (SCS) (variable D3) and drywell spray (variable D8) for monitoring the operation of the primary containment-related systems.
Instrumentation for measuring these variables is designated Category 2, with a range of 0 to 110 percent of design flow. These flows relate to spray flow for controlling pressure and temperature of the drywell and suppression chamber.
Discussion The drywell sprays can be used to control the pressure and temperature of the drywell. The residual heat removal (RHR) system flow element is used for measuring drywell flow in most designs.
The suppression pool sprays can be used to control the pressure and temperature in the suppression chamber. The operator controls pressure and temperature by adjusting sup-pression chamber spray flow. The RHR system flow element is used for flow indication in most designs.
Some plants have a flow element in the branch line to the sprays. The suppres-sica chamber spray operates in parallel with the drywell spray and is regulated with a throttling valve. The flow is deter-mined by the position of the throttling valve that is in the branch line that feeds the containment spray lines. These valve positions are indicated in the control room. The 43
effectiveness of these flows can be verified by pressure and temperature changes of the drywell and the suppression chamber.
1 Conclusion The current plant designs, in conjunction with operating practice, provide for operator information that is sufficient for determining the existence of spray flows to the drywell and suppression chamber without the use of a dedicated flow-measuring instrument.
f l
5 f
44
m i fi Law ISSUE 8.
VARIABLE D7 D7: Dryvell Atmosphere Temperature issue Definition Regulatory Guide specifies drywell atmosphere temperature (variable D7, Category 2) as one of the key variables in monitoring individual safety systems. The temperature range is specified as 40'F to 440*F.
Discussion The evaluation of this issue addressed requirements that call for direct operator action based on variable D7. that is, temperature and the associated variable of pressure. The BWR Emergency Procedure Guidelines (EPG's) provide guidelines for control of containment pressure and temperature. Classifica-tion of this variable should be done on a plant-specific basis with full consideration for EPG requirements.
Temperature-monitoring hardware inside the drywell may not be qualified to the accident conditions specified in RG 1.97; the primary item of concern is the cable inside the drywell.
Conclusion SWROG recommends baplementation of variable D7 require-ments as specified in RG 1.97.
45 I
7 2
.J ISSUE 9.
VARIABLES D13 D17 i
D13: RCIC Flow D14: HPCI Flow D15: Core Spray System Flow D16: LPCI System Flow D17: SLCS Flow Issue Definition Regulatory Guide 1.97 specifies flow measurements of the following systems: reactor core isolation cooling (RCIC)
(variable D13), high-pressure coolant injection (HPCI) (vari-able D14), core spray (CS) (variable D15), low-pressure coolant injection (LPCI) (variable D16), and standby liquid control (SLC) (variable D17). The purpose is for monitoring the oper-ation of individual safety systems.
Instrumentation for meas-uring these variables is designated as Category 2; the range is specified as 0 to 110 percent of design flow. These vari-ables are related to flow into the reactor pressure vessel (RPV).
Discussion The RCIC, HPCI, and CS systema each have one branch line-the test line--downstream of the flow-measuring element. The test line is provided with a motor-operated valve that is nor-mally closed (two valves in series in the case of the HPCI).
Further, the valve in the test line closes automatically when the emergency system is actuated, thereby ensuring that indi-cated flow 'is not being diverted by the test line. Proper valve position can be verified by a direct indication of valve position.
Although the LPCI has several branch lines located downstream of each flow-measuring element, each of those 46
e-em
'6 a..
lines is normally closed. Proper valve position can be veri-fled by a direct indication of vnive ponttinn.
For all of the above systems. there are valid primary indicators other than flow measurement to verify the per-formance of the emergency system; for example, vessel water level.
The SLC system is manually initiated. Flow-measuring devices were not provided for this systen. The pump-discharge header pressure, which is indicated in the control room, will indicate SLC pump operation.
Besides the discharge header pressure observation, the operator can verify the proper functioning of the SLCS by monitoring the following:
j 1.
The decrease in the level of the boric acid storage tank 2.
The reactivity change in the reactor as measured by neutron flux 3.
The motor contactor indicating lights (or motor cur-i rent) 4.
Squib valve continuity indicating lights 5.
The open/close position indicators of check valves (available in some plants)
The use of these indications is believed to be a valid alterna-tive to SLCS flow indication.
Conclusion The flow-measurement schemes for the RCIC, HPCI, CS, and LPCI are adequate in that they meet the intent of RG 1.97.
Monitoring the SLCS can be adequately done by measuring vari-ables other than the flow.
47
(II 1 T<
]
lSSUE 10.
VARIABLE D18 D18: SLCS Storage Tank Level issue Definition Regulatory Guide 1.97 lists standby liquid-control system (SLCS) storage-tank level as a Type D variable with Category 2 design and qualification criteria.
Discussion The symptomatic Emergency Procedure Guidelines (EPG),
Revision 1, as presently approved do not consider ATWS condi-tions; however, the EPG committee of the BWR Owners Group has been developing a draf t reactivity control guideline in which procedures are described for raising the reactor water level
. based on the amount of boron injected into the vessel, as indicated by the SLC tank level. Additionally, the operator is required to trip the SLC pumps before a low SLC tank level is reached, thereby preventing damage to the pumps that would render them useless for future injections during the scenario.
Regarding the instrumentation category requirement for variable D18, RG 1.97 indicates that it is a key variable in monitoring SLC system operation. Regulatory Guide 1.97 also states that in general, key Type D variables be designed and qualified to Category 2 requirements.
In applying these requirements of the Guide to this instrumentation, the following are noted 48
b; rcr 1.
The current design basi.s for the SLCS assumes a need for on niternative method of reactivity control without a con-current loss-of-coolant accident or high-energy line break.
The environment in which the SLCS instrumentation must work is therefore a " mild" environment for qualification purposes.
2.
The current design basis for the SLCS recognizes that the system has an importance to safety that is less than 3
the importance to safety of the reactor protection system and the engineered safeguards systems. Therefore, in accordance with the graded approach to quality assurance specified in RC 1.97, it is unnecessary to apply a full quality-assurance program to this instrumentation.
Based on a graded approach to safety, this variable is 4
more appropriately considered a Category 3 variable.
Conclusion i
SLCS storage-tank-level instrumentation should meet Category 3 design and qualification criteria.
It is realized that the resolution of the ATWS issue may include substantial changes to the SLCS design criteria. At that time, the SLCS instrumentation should be reevaluated to ensure adequacy.
4 4
49
~~?9 rp,
ISSUE 11.
VARIABLES D26 D'30 D26: Turbine Bypass Valve Position D27: Condenser Hoewell Level D28: Condenser Vacuum D29: Condenser Cooling Water Flow D30: Primary Loop Recirculation leeue Definiticn Regulatory Guide 1.97 states that "The plant designer should select variables and information display channels required by his design to enable the control room personnel to ascertain the operating status of each individual safety system and other systems important to safety to that extent necessary to determine if each system is operating or can be The purpose of this analysis was placed in operation.
to determine whether certain other D-type variables should be added to Table 1, RG 1.97.
Discussion Regulatory Guide 1.97 addressed safety systems and systems important to safety to mitigate consequences of an accident.
Another list of variables has been compiled for.the BWR in NUREC/CR-2100 (Boiling Water Reactor Status Monitoring during Accident Conditions, Apr. 1981). That report and a companion report, NUREC/CR-1440 (Light Water Resctor Status Monitoring during Accident Conditions, June 1980), address plant systems not important to safety, as well as systems that are important to safety.
In particular, these reports consider the potential role of the turbine plant in mitigating certain accidents.
These two reports were reviewed in determining whether any.
vurtuhlen niumlet tw nihliil t o t ho' 111: 1.97 l ise t.
4 50 J
m
- .ff' s--
The NUREG evaluations used a systematic' approach to derive a variable list.
The basic approach of the analysis was to focus on those accident conditions with which the operator is most likely to be confronted and on those accident conditions that result in the most serious consequences, should the oper-ator fail to accomplish his required tasks. These studies used probabilistic event trees and the sequences of the Reactor Safety Study (WASH 1400) and similar studies. The events in each sequence that involved operator action were identified.
Also, events were added to the event tree to include additional operator actions that could mitigate the accident. The event i
tres defines a series of key plant states that could evolve as l
I the accident progresses and as the operator attempts to respond.
5 Thus the operator's informational needs are linked to these i
plant states.
NUREC/CR-2100 is a BWR evaluation undertaken to address appropriate operato,e actions, the information needed to take those actions, and the instrumentation necessary--and suffi-cient--to provide the required information.
The sequences evaluated were 1.
Anticipated transient followed by loss of decay-heat removal 2.
Anticipated transients without scram (ATWS) 3.
Anticipated transient together with failure of HPCI, RCIC, and low-pressure ECCS 4
Large loss of coolant accident (LOCA) with failure i
of emergency core-cooling systems 5.
Small LOCA with failure of emergency core-cooling systems The RC 1.97 list is based on accidents that result in an isolated NS$$. The NUr.EG documents considered accidents that could be prever.ced or mitigated by using water inventory and the heat sink in the turbine plant.
51
Conclusion Five of the 15 variables identified in the NUREC, but not in RG 1.97, are recommended as Type D, Category J additions to the RG 1.97 list. Four of these variables are in the turbine plants the turbine bypass valve position, condenser hotwell level, condenser vacuum, and condenser cooling water flow. These variables provide a primary measure of the status of a heat sink or water inventory in the turbine plant. The turbine-plant systems are not to be classed as " safety systems" or as systems important to safety. The addition of reactor primary-loop recirculation flow is also recommended.
$2
T i l'l 6A ISSUE 12.
VARIABLE E2 i
E2:
Reactor Building or Secondary Containment Radiation issus Definition Regulatory Guide 1.97 specifies that " Reactor building or secondary containment area radiation" (variable E2) should be monitored over the range of 10-1 to 10" R/h for Mark I and 7
II containments, and over the range of 1 to 10 R/hr for Mark III containments. The classification for Mark I and II is Category 2; for Mark III, the classification is Category 1.
Discussion As discussed in the variable C14 position statement (Issue 6), Secondary Containment Area Radiation is an inap-propriate parameter to use to detect or assess primary con-tainment leakage. However, for the Mark III containment, the reactor building is essentially part of the primary contain-ment and it is appropriate to monitor that building volume as specified in RG 1.97.
Conclusion It is the position of.BWROG that the specified reactor building area radiation monitors be installed on Mark III containments, but that these monitors should not be required for plants with Mark I and II containments.
53
ISSUE 13.
VARIABLE E3 E3: Radiation Exposure Rate issus Definition Regulatory Guide 1,97 specifies in Table 1, variable E3, that radiation exposure rate (.inside buildings or areas where access is required to service equipment important to safety) be monitored over the range of 10-1 to 10" R/hr for detection of significant releases, for release assessment, and for long-term surveillance.
Discussion In general, access is not required to any area of the secondary containment in order to service equipment important to safety in a post-accident situation.
If and when accessi-bility is reestablished in the long term, it will be done by a combination of portable radiation survey instruments and post-accident sampling of the secondary containment atmosphere. The existing lower-range (typically 3 decades lower than the RG 1.97 range) area radiation monitors would be used only in those instances in which radiation levels were very mild.
Conclusion It is BWROC's position that unless plant-specific design requires access to a harsh environment area to service safety-related equipment during an accident, this parameter should be modified to allow credit for existing area radiation moni-tors. That is, this parameter should be reclassified as
$4
Category 3 with a lower range :o be selected on a plant-specific basis.
6 55
'l ISSUE 14.
VARIABLE E13 E13: primary coolant and Sump leeue Definition 4
Regulatory cuide 1.97 requires installation of the capa-bility for obtaining grab samples (variable E13) of the con-tainment sump, CCCS pump-room sumps, and other similar auxi-11ary building sumps for the purpose of release assessment, verification, and analysis.
Discussion The need for sampling a particular sump must take into account its location and the design of the planc in which it i
is installed. For all accidents in which radioactive material would be in the primary containment sump of a BWR Mark I or Mark II containment, this sump will be isolated and will over-flow to the suppression pool. A suppression pool sample can therefore be used as a valid alternative to a containment-sump sample.
The analysis of ECCS pump-room sumps and other similar auxiliary building sump liquid samples can be used for release assessment, as suggested in RG 1.97 only for those designs in which potentially radioactive water can be pumped out of a controlled area to an area such as radwaste. For designs in which sump pump-out is not allowed on a high-radiation or an LOCA signal, or in which the water is pumped to the suppression pool, a sump sample does not contribute to release assessment.
For these designs, the use of the subject sump samples for verification and analysis is of little value; a sample of the suppression pool and reactor water, as required by other 4
$6
e m
+
j I
I portions of RG 1.97 provides a much better measurement for these l
purposes.
l Conclusion i
1.
A suppression-pool samplu can be used as an alterna-tive to a primary containment-sump sample for plants with Mark I
l I or II containments.
i 2.
The analysis of ECCS pump-room sumps and other similar l
auxiliary building sumps is a consideration only if the water i
I is pumped out of the reactor building (e.g., pumped to radwaste).
]
For designs in which sump pump-out is not allowed on a receipt i
of an accident signal, or in which the water is pumped to the suppression pool, analysis is not necessary.
Provisions for j
sump sampling and analysis should be in accordance with each i
j utility's response to NUREG-0737.
i i
I
(
s k
I i
I 57
[
6.
CONCLUSIONS The BWR Owners Group RC 1.97 Committee completed an extensive analysis of the regulatory positions proposed in
- RC Regulatory Guide 1.97, Rev'ision 2.
The principal goal of the committee was to fornulate the position of the BUR Owners Group relative to RG 1.97 requirements.
Teward that end, the committee developed--on the basis of studies con-ducted by its own representatives and its contractors--a auries of positions with respect to interpreting and imple-menting the various provisions of RG 1.97.
The Owners Group concurs with the intent of RC 1.97, which is to ensure that each BWR f acility is suf ficiently instrumented to make possible the timely and effective assessment of plant and environmental conditions during and following an accident.
The Owners Group also recommends implementing the partic-ular variables and instrumentation requirements of RG 1.97, except in those instances when deviations frem the RC l.97 positions are indicated, are desirable, are in accord with the intent of RC 1.97, and are technically justifiable. The exceptions noted hv the Owners Crotip.1re a,onerally derived from the incompatibility of an RG 1.97 requirement with the intent of RC 1.97; from evidence that the implementation of an RG 1.97 position would not accomplish its intended objec-tive or that the consequence of its implementation would be undesirable f rom a safety point of view; or from the availa-bility of more effective or more practical ways of achieving a particular monitortug activity.
39
e l
APPENDIXES
'sL I - 8121 Do.: ember 1981
~
APPENDIX A THERMAL ANALYSES Oft IN. CORE THERMOCOUPLES IN BOLLING WATER REACTORS (S. Levy, incorporated)
J. C. Gillis J. E. Hench E. A. Adams J. E. Eddleman M. A. Beckett Prepared for the BWR Owners Group
~
Sy S. Levy. Incorp: rated 1999 S. Bascom Ave., Suite 725 Campbell, California 95008 l
l i, s
i 1
l t
i.j' Abstract I
i
)
One of the new BWR requirements in Reg. Guide 1.97, in response to the event
]
at Three Mile Island is the requirement for thermocouples located at the j'
top of the core.
An analysis was performed of the heat transfer in a BWR
{
fuel bundle during a core uncovery event to determine the nature of the j
response of thermocouples to core heatup. The thermocouples were assumed to be located in the in-core guide tubes, and are heated primarily by ra-l' diation from the fuel channels. The results of this analysis show that for i
{
conditions typical of small break loss of coolant accidents, there is a j
delay of at least 10 minutes betwien the start of core uncovery and the time when the thermocouple reads 450F a:.nve saturstion. It is also probable that j'
operation of relief valves during a small break LOCA would interfere with the thermocouples operation and could render them useless.
i I
1-i i
l i.
l i
i l-l l
j i
M
Summary and Conclusions.
Une ut the new BWR requirements in Reg. Guide 1.9/, in response Lu the event at Three Mile Island is the requirement for thermocouples located at tne top of the core. The stated purposes of these thermocouples are to provide a backup level gauge, and to provide an assessment of the degree of degradation of the core, should it become uncovered. It has been proposed that these thennocouples be located in the thimbles wnich house the in-core neutron flux gauges. Based on simple heat transfer analyses of conditions typical of Small Break Loss of Coolant Accidents, it is our conclusion that these thermocouples will not show a temperature 450F above saturation until at least 13 minutes after the core has started to uncover.
We have also reviewed a calculation by the staff of the Nucle 3r Regulatory Commission (NRC) of the response of thermocouples in the in-core thimbles.
The NRC analysis concludes that the thernioccuple response time is on the order of two minutes. We believe that the difference between our analysis and theirs is that we used different, and we believe, more realistic decay power levels and the convective cooling effect of boil-of f steam on the fuel rods and channel. Simple calculations show that these elements are important parts of the problem.
We have also found that, tAing the NRC assumptions, our calculation will reproduce their results.
A preliminary look at two alternative locations (upper plenum and steam dome) did not indicate that thermocouples located there would have better response times.
'OO@OO@OO
'O O @ O O @ O O*
00000000 00000000
@O00000@
@OOOOOOO 00000000 00000000 00000000 00000000
@OOOOOOO
@O000000 00000000 00000000 00000000 OOOOO@OO Thimble Thermocouple
'O O O O O O O O"
'O O G O O G O O' 00000000 00000000
~
@O000000 GOOOOOO@
0000@O00 00000000 I
00000000 00000000
@OOOOOOO
@O00000@
00000000 00000000
,O O @ O O @ O O O O @ O O @ O O,,
r s
s 3
FIGURE 1 i
THERMOCOUPLE MOUNTED IN THIMBLE AMONG CHANNELS Section 1 I.
Heat Transfer Analysis of In-Core Thermocouples One of the signals received by plant operations during the accident at Three Mile Island was a high temperature reading - indicating the presence of superheated steam - from the core exit thermocouples. It has now been suggested by the NRC that in-core thermocouples could be used to detect core uncovery by showing high temperatures whenever superheated stean appears. The merits of this idea for Pressurized Water Reactors (PWRs) are j
being debated elsewhere, only SWRs will be considered here.
i Ob
-,.v
II.
Physical Description of the Thermacouples Mountea in Flux Monitor Thimbles Af te.r inspection of the BWR design, it has been concluded by the authors, and independently by the NRC staff, that the most logical place (and perhaps the only practical place) to locate in-core thermocouples is in the thimbles which house the in-core neutron flux monitors. A plan view of the physical situation is shown in Figure 1.
The fuel rods are surrounded by a square zircalloy channel, and the thimble is at the channel corner.
It is assumed that the thermocouple sits in the center of the thimble as shown.
The dimensions of parts shown are given in Appendix A.
Questions about the usefulness of the thersocouples mounted in the thirr-bles have centered on their time of response during a small break LOCA. In that situation the core is initially covered with water and the reactor has been scrammed. The decay heat in the core rods continues to boil the water in the core, and eventually the water level drops to tne top of the core.
As the water level drops further, to the level of the thermocouple, the rods are uncovered and begin to heat up.
Heat then flows outward to tre channel wall, to the thimble, and finally to the thermocouple.
III Heat Transfer Analysis of the Response Characteristics of In-Core Thermocouples in Small Breaks The response characteristics of thermocouples mounted in the thimbles used for in-core neutron monitors was investigated by writing planar env.gy balance equations for:
1) the rods (the fuel bundle was broken into four subgroups) 11) the channel tii) the thimble iv) the thermocouple.
\\
Also, a hest balanc3 equation was written to calculate the te Prature od steem as it rises L:1 rough the uncovered portion of the core.
h7 ether, t hat.c equations formed a self-consistent set which determines tne temperature-time history of the thermocouple.
A.
Energy 'calance on tne thermoccuple.
The thermocouple was asssumed to receive heat by radiation from the thimbla wall.
This is the only method of heat transfer assumed - convection through the air in the thimble was ignored. The energy equation was then:
l s
4 UI d Tte
,(
ha (Tec4 Tth)[J dt ML
[R3 where R3, 1 - 4,gg 1
,_1 - ste (2)
Ae AtcC Ath etn t
a 2
B.
Energy Balance on the Thir.cle.
The thimble receives energy by radiation from the channel wall, and loses energy by natural convection to the steam between the channels, and by radiation to the thermocouple. The stasc between the channels is assumed to be at the saturation temperature.
The energy balance can be written:
4 - Teli). <
(Tec4 - Teh ) + in th (Tsatit3%
4 a'
sn.
.l. C p r,2?o_ (T L
o dt Mth N
(3) whare 1
I " 'C I
I " 'th '
R2
=
+ b.
(4)
+
,Ac #C Ath Eth, 0
2 4HJ A3 showed that R is two orders of magnituce A relative evaluation of R 3
larger than R. Since the tet:perature differences are about ue same, the 2
thimble's heat lon to the thermocouple is or.glected.
l
~
68 t
t C.
Energy Balance on the Cliannel Wall.
The channel wall receives energy by radiation from the fuel rods, and lose's it both by convection to the steam flow and by rad.stion to the thermocouple thimble. As disc.sssed below in more detail. the rod bundio i k divided int.o four rod subgroups and energy balance equations are written for each.
The radiant heat transfer between each of those rod groups and the channel was calculated using gray body f actors (Fjj) discussed 1.1 section E. The sum of the radiant transfer from all the rod grocos to th3 channel is:
4 4
4 4
- a Fig (Try -Tc)+Fg(Tg -Tg)
Orad = Ag 4
4
+F3c(Tp3-Tg)+F4e(Tr4 Tg)
(5)
The channel convection terms are calculated using a forced convection heat transfer coefficient on the inside of the channel, and a natural heat transfer coefficient on the outside of the channel. These coefficients are calculated from correlations discussed in section E.
It is assumed that the steam temperature between the channels is at saturation.
W O
- E (T3g-T ) + E (Tn SAT-T )
cony F
g g
The energy balance equation for the channel is then:
4 4
4
[(AeF Ur2 -Tg) gg(Tr1 -Tg)+F'2c dig 1_
g
,7 )
at (mc)g 4
4
+F3g(Tp3 -Tg ) + F,(Tr4 "Ic) 4 S1-T,>. wT T-T,>}
.wT 69
+
i n
m.
Corner Rods (4)
O O O O O O,d_
f
_ O_. O_ O_ _O _ O.
ceeter aoee (4)
O,i
'*"*)
000000 O,e i
O'O O'0 '
00 I
I Interior acds (32)
OO OLQRO OiOf 010OOOO90
~
O!O O O O O O'O OId
~O dU~OTO3
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FIGURE 2 DIVISION CF R005 INTO R00 GROUPS FOR E
RADIATION MODEL D.
Energy Balance Equations for the Four Rod Groups The 64 rods in a single 8 by 8 fuel rod bundle were divided up into four groups as shown in Figure 2.
An energy balance equation was written for each of these rod groups which considered 'she heat up of the rods by decay heat, the transfer of energy among the rod groups (and channel wall) by ra-diation, and heat transfer by convection to the steam. Radiation from the rods to the steam was neglected as this has been shown (4) to be a small term.
The four rod group energy balance equations then have the form 4
rj ) *
(0)
DECAY ij^i(Tri T
r,1,,
1 Q
dt n (mc)p j=1 -,
4
+ is A (T sT3t )
p3 r3 l
l 70 F
)
-e n
The decay heat is determined from the ' dis decay heat curve for times between 150 and 10,000 seconds, ano the initial power before scram.
00ecay(s.t)
= (Oo) 130(t-tscram).283
,f(3)
(9) where f(x) is the axial power shape, and Qo is the initial power.
The initial power level assumed is 2436 megawatts (thermal). The axial power shape used is:
4,4}b (10)
'f(x)
= 1.387 cos where x is in feet and the computed angle is in radians.
E.
Convective Heat Transfer Correlations and Radiation Model Equations 5 and 7 above use the convective heat transfer coefficients for the rod surf ace, the inside channel surface and the outside channel surface.
When the Reynolds' number fer the steam flow through the rod bundle is greater than 2300, the correlation below is used to obtain the Nusselt number for the rod surfaces.
0.022 Pr.5 g,0.8
- F (s/r)
(II) 0 Nuir The Reynolds number in this calculation is defined as:
Re, 4 Grdflow, 4 Gst Aflow
- st P pst Ad (12)
Equation (12) was modified for the paral'el rod geometry by the factor F j
(s/r) which depends, as shown by Reference 1 on the ratio of rod pit:h to rod radius (s/r). The resulting heat transfer coefficients ranged bit-
~
tween 10 and 17 Stu/hr ft2 op, n-
When the Reynolds number is celow 2300, a constant Nusselt number, given for rod bundles as a function of (s/r) by Sparrow, Loeffler and.%bbard is used. (Ref. 3)
C. f(s/r)
(13)
Nu
=
For the channel wall, tha Nusselt number for turbulent flow is calculated from equation 11, without the F (s/c) correction.
Similarly, for laminar flow, equation (13) is used for the channel without the F (s/r) correction factor.
Radiation heat transfer betwe.en the rod groups is calculated using grey body f actors, which account for the fact that some of the radiation incident on a surface is absorbcd and some is reflected.
These factors denoted F j are defined in terms of the radiant heat transfer between two i
surfaces as:
4 Qij
- Aj F;j a [Tj4 - Tj ]
M These f actors were developed from the emissivities of the surf aces (as-sumed to be.6) and the geometric view factors for rod to rod and rod to channel radiation given in Reference 5.
As in reference 5, it was assumed that all radiation emitted by a rod would be absorbed by its 25 nearest neighbors, and that the fraction of rcdiation emitted outside the 25 nearest neighbor rods (or channel surface) which arrived at a given roc after multiple reflections was negligible.
F.
Calculation of the Steam temperature and Flow Rate L
In equations 5 and 7 the rate of convective heat transfer is determined by the flow rate of boiled-off steam, and its temperature as it moves through the fucl assemblies.
The boil-off rate, for a partially-sabmerged fuel bundle, was calculated by assuming that all the decay heat from de portion of the fuel rods below the waterline goes into producing steam. The water level is determined by integrating the boil-off rate as the calculation proceeds.
72 3
1
~
When the steam leaves the water's surf ace, its temperature will be at saturation. As the steam rises through the rod bundle it will be heated by contact with the rods. Thus, steam temperature is both a function of tine and elevation.
To calculate the steam temperature at any elevation at a given time the following equction is integrated from the liquid surf ace to the top of the rod bundle.
dTst hf Ar (Tr - Tst)
(15)
=
C dx GAflow p This integration is done numerically using a core divideo into twelve zones. The rod temperatures are obtained from a heat balance on ai; average rod in each of the twelve zones.
The above set of ordinary differential equations was integrated forward in time simultaneously using a fourth-order accurate Adams predictor-corrector scheme.
IV Results for Thermocouple in Thimble The calculations described above was performed for the foliewing starting conditions:
Reactor power at 2% of full power (2436 MW thermal) - this corre-sponds to 700 seconds after scram.
No feedwater supply to reactor pressure vessel or leakage.
Constant-Reactor pressure of 1000 psia.
8x8 fuel l
73
O These conditions were chosen so nat our calculation would correspond to one performed by the NRC which will be discussed later.
In the NRC calculations, it was assumed that the operator would not consider the thermocouple signal to be seriously out of line until it read 450F above saturation. At first glance this seems like a high number.
However, it must be remembered that the saturation temperature is not absolutely steady and that during plant transients, it can change by about + 200F, so the value of 450F is reasonaole. The fact that the operator has to keep tre change of saturation temperature with reactor pressure in mind is another complicating factor which will make successful use of the thermocouples less likely.
Figure 3 shows the calculated temperature response for three axial ther-mocouple positions, the top of the core,11 f t and 10 f t. elevations. This graph shows that the response times are on the order of 13 minutes. Fio-ure 3 also shows tnat the optimum location for the thermocouple is near to the top of the core, although the response time (measured froh. the start of core uncovery) is not a strong function of position.
After examining Figure 3 it was decided to use a thermocouple location 1 ft from the top of t.1e core for all further ca'culations.
More detailed information on the resoonse of the system with the thermo-couple located one foot below the top of the core is shown in Figure 4.
The plane of the thermocouple is uncovered about 150 sec after the top of the core uncovers. The rods begin to heat up adiabatically, but later the rate temperature rise drops off due to convection and radiation losses.
As the foam level in the bundles drops, and more and more of the core below the plane of the thermccouple is uncovered, the temperature of the steam passing the thermocouple location rises. The channel wall, thimble a.1o thermocouple all rise in temperature, and the thermocouple 'is 450F above saturation 780 seconds (13 minutes) after the start of core uncoverf.
Figure 4 also shows that the. time lag between the thimble and thermocouple s
temperatures is extremely small, thus direct contact between the thermo-couple and thimble will not significantly reduce the time delay.
74
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=
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FIGURE 4 TEl4PERATURE TIME lilSTORIES FOR TilERI10 COUP'.E LOCAT10ft i f L BEL 0tl TOP OF CORE 250-200-Degrees above Adiabatic Temp Rise Center Rods Saturation 150 0F
~
./
Steam 100.
/
Channel Thinible 50'
/
/
- T/C
//
/
J 0
100 200 300 400 500 600 700 800 TIME AFTER START OF CORE UNC0VERY, SEC 9
=
l V.
Verification of Analys:s To check the correctness of the above calculation, two checks were made.
First, the initial rate of temperature rise should be consistent with the adiabatic rod heat up rate at 2% power.
This rate is dT A
averace bundle decay power
- axial peaking function dt Dunole heat caoacity sec. [e]awatt / 560 assemblies,, f(x) 0.02
- 2438 megawatts
- 948 64*{7.37LbmU02 +.911 Lem Z
= 0.12 Stu F
0 Lcm F 1.30 F/sec.
- f(x)
=
A line corresponding to the adiabatic heat up rate at i ft. below TAF nas been drawn on Figure 4 and it can be seen that the rod temperature rise ra:e I
approaches it naar its time of uncovery.
A calculation was also conducted to check the correctness of the steam temperature rise calculation.
Figure 5 shows the axial distribution of interior group rod temperatures and steam temperatures at 1000 sec af ter the start of core uncovery.
To check the calculated steam temperatures, the rod temperature distribution was approximated with the dashed lines
~
shown.
For a linear temperature profile, constant heat transfer co-efficient and flow velocity the analytical solution for steam temperatu e is:
= ae b(x-1/k) + (Tg + b/k - a) e-kx (16)
T 3g where a and b are the coefficients of the linear temperature profile (Te
- a+bx) and k is defined as g,
Ih CP (17)
Using the heat transfer coafficient computed from the correlation givan earlier (9.42 Stu/lir-Ft2 OJ), the steam temperature was calculated usi1g the above formula.
Result:; are plotted on Figure 5 and show close agreement with the macnine calculation.
i l
l 77
FIGURE 5 CHECK 0F STEAM TEMPERATURE CALCULATION O
COMPUTED R00 TEMP.
A COMPUTED STEAM TEMP.
ASSUMED LINEAR R00 TEMP. PROFILE STEAM TEMP. PROFILE FRCM EQN. 16 N
l.\\.s<
)
l ax x
- l Degrees F Above
,aturation I
100 I
I-I 2
4 6
8 10 12 78 F ET FROM BAF
VI Comoarison of Present Calculations with a Similar Analysis by the Staf f of the NRC.
As part of this project, we have reviewed a calculation of the the,mocouple response time by the NRC office of Nuclear Regulatory Research.
The'r calculation assumed a 2% of rated uniform axial power input and no convective heat transfer.
They assumed that convection and radiation losses from the rods would be negligible.
Their results are plotted n Figure 6.
The adiabatic roc heat up rate which they calculated was about 2.70F per second at the 80% ef core height elevation (about 9.7 f t above 3 A F) and 3.80F at the 60% core height elevation. With these heat up rates their results show that a thermocouple at.he 60% height would show a 450F temprature rise 120 sec after the 60% plane is uncovered.
The simple calculation in the last section shows that the adiabatic heatup rate should be on the order of 10F/sec rather than the 2.7-3.8 that the NRC used. However, in order to compare our calculation to theirs, we adjusted the prescram power in our code (to 8,672 megawatts from 2436) and set the convective heat transfer coefficients equal zero. These results are shown in Figure 7.
They agree very well with the NRC results. Using the NRC heatup rate our code predicts that a thermocouple at the 60% height will show 450F temperature rise 135 seconds after the 60% plane is uncovered.
The NRC calculated the 60% plane would uncover after 90 sec and the 80%
plane af ter 210 sec. Our calculations, with their assumptions, shows these planes uncovering at 110 and 242 seconds respctively.
We conclude that the essential differences between our calculation and t,e NRC's are the extremely high heat up rates they assumed and the fact that they neglected convection to the passing steam. Both of these differencas tend to make the calculatec core temperatures rise more quickly after uncovery which speeds up thercocouple response. We believe our assumptions are more realistic, and our results T. ore correct.
79 l
af at,0F s
500\\
1 100-Rods j
l (Adiabatic l
250.
j l
/
/
9 ds (Ad ebatic) d T/C l
80-l I
250.
450F l
r S0-M
.i Percent of Care Which Is Covered 100 200 300 TIME, SECONOS AFTER START OF CORE UNC0VERY FIGURE 6 RESULTS OF NRC CALCULATION 30
=_ _ _
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100 200 300
- 0t r 11MC nFitii LIARI LF CORL UNCOVERY, LEC3.
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FIGURE 7 i
PRESEli CALCULAT10:4'WITH NRC ASSUMPTI0 tis k
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e n
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+,
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VII.
Ef fect of Crangini; e..c.c-
-ss..re vessel oressuic sil tne calculatican c::. m ee it..ne previous sections assomed tr e
.. a co....nt during core unc.,very end hea u reastor vessel pressur.
During the sort of small 'reu ;a<.s of coolant eccident where core ?
a I
mocouples are likely to te cuetat, r.c ever, the pressur e will most I P..-
not be constant.
For example, 'cica in Figure 8 is a cou.auted pres. '.
trace for the Leibstad ;; tant aurir.g a Turoine Trip transient. The r s.".:-
vessel pressure rises te, tne relief eslee set point and then drops.. hen t:N
~
valve is open. During tnis pressure drop, voics will form in the satura*.r.d licuid. Tnese voids will raise tne oater level as illustrated in Figun The c. mount by whicn the water level will rise can be determined by a stis.:.le approximate, calculation.
According to Reference 5, the fluic filled cross-sectional area
.2 i
Peachbottom II plant betneen the top and bottom of active fuel is about.
2 3
ft.
The amount of water below the core is about 4100 f t.
.. i r..
2 2
density of saturated water nese 1000 psia is 46.3 lbm/ftJ, the mat water in the reactor i3 Mass of H O = 190,000 - 10,140 Z 2
~
wherc Z in the height c ; ac. ;w c.,re nnich is covered. The quality chu..,;e.
'or ca incremental enar.,e ii. pr. ssure can ce obtained from 'he enain..h 3x.
dx
.. n d t.
cP bncer tnese condi; ions in-v 0.00-p
=
, L,e.
y For "ne u0 i'ti cchge.. pre bwee wrm n'*igure $ :,*.0h.
t 4 <. : '.,, ',. ~ :...
ae'.1ef v a ; ve invett.
I
?8-. '.
to an increase in valt.;.c af av 4 1894 - 101 :
i
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1 1
1
' 1 VFWf Pip.S RISE tt'SI) 1 2 SWETY VR.YE FLCW C8 M 9F(L9ETC C 3 MLIEF Vf VE FLC'd 5
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100.
s 0.
I ik 3 7 't I k 1'u 3.
O.
10.
20.
30.
40.
TIME (CECJ FIGURE 8 SMALL BREAK PRESSURE HISTORY (Liebstadt)
VALVE CLOSED VALVE OPEN
..l f...---- J cPhsam4#F c
+-
s 1 y c:c@..
% ys
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.i h.d
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- n
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S:i FIGURE 9 I
LdVEL SWELL EFFECT OF OPEN RELIEF VALVE 83
FIGURE 10 ANTICIPATED EFFECT OF LEVEL SWELL OPEN CLOSE OPEN CLOSE OPEN CLOSE FUQ y
6 C
t O
( I/C TSAT i
TIME
I 2
Using the core, bypass and annulus fluid cross section of 220 ft, this corresponds to a change in wa*.er level of ah = 8.64 + 0.462 Z or 8-12 ft.
This will be enough to periodically cover and uncover the thermocouple until the core is almost completely uncovered.
The effect of this periodic swamping of the thermocouple plane is not aasy to predict. If the rods are hot enough, then the rod surf ace will not rewet and very little heat will be lost. On the other hand, even if the channel wall is hot, the fact that it has a high surf ace to volume ratio means that it (and the thimble) probably will rewet, and its temperature will drop to saturation.
In this
- case, the temperature-time history of the thermocouple would look like Figure 10. The rods would heat up gradually but the th'ermoccuple would never read a temperature very far from
~
saturation.
VIII.
Other locations for Thermocouples A very quick investigation was made of two alternative locaticos for the thermocouples. The two locations looked into, in the upper plenum and in the steam dcme, were chosen on the basis of the following argument. If it is impractical to locate an in-core thermocouple any closer to the fuel cladding than in the in-core flux monitoring tubes, then the only other way to get the information that the core is overheating is to measure the steam temperature af ter the steam has lef t the core. The ideal way to do this
~
would be to put a bare thermocouple in the ; team flow just above the core exit. Examination of detailed reactor drawings indicates that this would be very difficult to do.
An easier alternative would be to put the thermocouple in the steam dome. A thermocouple in the steam dome, however, will not respond immediately to an increase in core steam exit temperature.
To get to a thermocouple in the steam dome, the steam will have to pass through relatively cold standpipes, steam separators and dryers before it enters the dome, j
i l
f as t
The analysis developed to investigate thermocouple response in the in-core tubes was used to determine the response time of thermocouples in these two locations.
The temperature drop of the steam as it flows through the dryers and separators was calculated (approximately) by treating these parts as a uniform temperature heat exchanger:
Tst(exit) = Tst(entrance) + [Tsurf - Tst(entrance)] e-Ntu where Tsurf is the ;cmperature of the dryers, separator and standpipes, and Ntu is defined Ntu
=
(5 cp) steam The heat transfer coefficient used was the same one calculated for the rod bundle.
The separator-dyer-standpipe temperature was calculated as a function of time by d(Tsurf)
(m cp)
[Tst (exist) - Tst (entrance)]
dt (msep )
C 2
The area of the separator-standpipes-dryers was estimated at 20,000 Ft,
the mass was estimated at 130,000 lbm.
Results shown in Figure 11 do not show the alternative locations to be promising. As Figure 5 showed earlier, the temperature of the steam at the core exit follows the temperature of the top of the rod bundle f airly closely. Since the power is low at the top of the bundle, the temperature there rises fairly slowly.
For this reason, a thermocouple in the upper plenum would not read 450F above saturation for seven minutes after the start of core uncovery. Figure 11 shows that the time delay introduced by the hardware above the upper plenum is not too great, and that a thermocouple in the steam dome would read 450F above saturation about 9.2 l
minutes after uncovery.
l l
86
o i
l The two response times calculated above f or thermocouples in the upper plenum and steam dome are intended to illustrate the lower limit of how f ast they could possibly be under idealized conditions in which an un-shielded thermocouple is placed directly in the steam flow out of the core (upper plenum) or directly in the steam flow out of the dryers (steam dome). For other, more realistic, installation positions these times are unrealistically low.
In both cases the large volumes of saturation temperature steam in both the upper plenum and steam dome will dilute the superheated steam from the core and will slow the response greatly.
Calculations which include this dilution effect in a very approximate manner show the time delay increased by a factor of two.
O 1
gy 37
flGURE 11 E
TEMPERATURE TIME lilSTORIES FOR ALTERfiATE LOCAT10ris
- NOT INCLUDir:G DILUTIGil BY STAURATED STEAN.
i 50 -
40, Upper Plenum Steam Dome Degrees Above 30-Saturation e
OF 20, 10-t B
5 I
I E
I I
3
~
l 100 200 300 400 500 600 700 800 l
TIME AFTER START OF CORE UNC0VERY, SEC t
1 I
e
~
IX. Estimates of Costs & Exposure for Installation of incore Thermocoucl s i
l Tables 1 and 2 show estimated costs and exposures respectively for in-stallation of 16 thermocouples (TC's) in the UWR cure fur use as a diverse level sensing method. The 16 TC's are to be installed in 16 different LPRM tubes, 4 in each quadrant of the core. Three cases are considered:
l Case 1.
Installatior. Prior to Fuel Load l
Case 2.
- nstallation During an Outage Case 3.
Differential Cost of TC Installation vs. Norm.' Failed 1.PRM Replacement work performed during a refueling outage.
The costs include material, labor, overhead, engineering and A/E fees, contingency and escalation @ 10%/yr. for 3 years.
The material costs include 5700,000 for 16 strings of qualified LPRM assy. w/TC which results in a cost of $43,750/assy. Tnis compares with estimated cost of $20,000 to 530,000/assy for a standard replacemer.t LPRM assy. The additional costs includes the TC, and allocated R&D and qualification costs. In calculating the differential cost in Table 1, Case 3 the cost of a typical LPRM ansy.
wo/TC was taken as $25,000.
The costs and radiation expenses for thermocouple installation can be summarized as:
~
Exposure Nan /R Cost Min.
Nax.
Case 1 (Prior Fue'l Load)
$ 2,093,948 N/A N/A Case 2 (During Outage) 2,470,220 65 450 Case 3 (
vs. Rep 1. LPRM) 1,697,237 50 250 39
i Table 2 shows a r.iin/ max rem exposure expected for installation during an outage.
There is a wide variation in expected radiation rates at operating plants which is affected by factors such as:
History of Fuel Failures Water Chemistry Reactor Water Clean Up & Polishing Demineralizer Operation l
History.
Some plants could produce rates 2 or 3 times higher than the highest rate l-on Table 2.
The rates on Table 2 are considered ranges expected for 15%
of operating BWR's. The tatal exposure would b,e spread over a number of workers 50 as not to exceed the quarterly allowables for I worker.
The following assumptions were used in developing these estimates:
l 1.
Installation of TC's would be accomplished by repiccing an L?RM assy. with a new design which includes a TC in the LP.'.M assy.
2.
The existing wiring and connectors for LPRM's need not be al-tered or replaced.
4 3.
New uiring for 16 TC's is added using existing sparc electri:al penetrations.
No drywell sh'. eld or primary containment core drilling is necessary.
4.
The TC's are wired back to the relay room to 16 signal con-ditioners and from there to 2 recorders in the control roon..
The system is separated into 2 divisions I
90 i.
5.
For installation of each of 16 LPRM assy. relateo cable und conduit runs inside containment, a five man crew including 1 3upervisor is used.
The four workers require a total of 30 Mandays (per TC) to do the work.
Half the 80 Man / days (MD) is spent inside containment. of this 40 MD, 2MD/TC is spent inside the drjwell and the remaining 38 MD/TC is spent inside contain-ment.
6.
The differential exposure between installing TC's vs. the normal failec LPRM replacement activity is the exposure resulting f rom cable installation inside primary containment only.
4 W
1 l
l l
TABLE 1 8
Case i Casa ;
rav 3 Prior to Ouring Cost in Addition to fuel Load Outage Replacement of failed LPRMS ITEM gig ml WI Labor Material Labor Ma tt. rial Labor Material 1.
LPRM Strings & Install 2,560 700,000 6.400 700,000 28 300.000 (16 Strings) 2.
Cable (to Control Room) 1,740 4,800 3,720 4,800 3,720
'4,800 3.
Penetrations & Assy.
44g 140,000 1,380 140,000 1,.18 0 140,000 (Incl. Seal)
'4.
Tenninal Boxes 160 4,000 480 4,000 480 4,000 5.
Cable Trays & Installation 3,400 48,000 5,000 48,000 5, M0 48,000 i
i 6.
Electronics Installation 550 24,000 550 24,000 550 24,000
)
Sub Total 8,858 920,800 17d30 020,d00 11,258 520,000 Labor 9 520/MH 177,160 350,600 225,160 Distributed Cests 97,000 193,000 123,838 (Clerical: Doc. etc.)'
8 551 (DL)
Utility Engineering 130,000 140,000 140,000 A/E Fee== 51 (H+L) 55,000 65,000 65,000 Esulation (3 yr 910s) 413,988 500,820 322,439 Contingency 300,000 300,000 300,000 Total
$2,093,948
$2,470,220
$1,697,237
s Table 2.
1.
Radiation Intensity Location Exoosure mR/He Inside Orywell Min Max Al LP11M flange 100
/50 Platicem (5' Gelow Flange) 50 300 inside Primary Containment 10 50 II.
Estimated Excosure for 16 LPRM Assy. w/TC.
Min.
Drywell:
12.8 ManR x
TC 0
HR Prim Contm:
38MO 8 hrs 16 TC 10 mR 48.64 ManR x
x
=
TC D
Hr Min. Total 61.44
=
Say 65 Man R Max Orywell:
2 MO 8 hrs 16 TC 750 mR 192 Man R x
X X
=
TC 0
Hr Prim Contm:
38 MO 8 hrs 16 TC 50 mR =
x x
x 243.2 Man R TC D
Hr TOTAL = 435.2 Man it Say 450 Man R M0 = Man Day
'n
.]
a Table 2 (Contd)
III.
Differential Exoosure vs. Reolacement of 16 Failed LPRM Prim. Contm Exp.
= 50 Man R Min.
=
=250 Man R.
Max.
=
E e
1 O
hk
I X.
Conclusions Based on the preceeding analyses we conclude:
1.
If thermocouples are mounted in BWR cores for use as core uncover y indicators they will not respond for at least 10 minutes af ter uncovery in a small break LCCA.
2.
Because BWR's have other level gages, the operator will be given conflicting infermation d aring this 10-13 minutes.
That is, his ccre thermocouples would say he is not in trouble, while his level gages say he 15-3.
The analysis performed by the NRC calculates a quick respun',e ut the core thermocouples because of two assumptions made - first ti.4t convective heat transfer may be neglected, and second that the uncovered reds (at 2%
decay heat) heat up at a rate of 30/sec.
These assumptions are unrealistic, and erroneously lead to the conclusion that core ther-mocouples are an effective means of determining core water level.
4 The operation of pressure relief valves during a small break LOCA tas the potential to render the thermocouples useless.
They could read the saturation temperature even while the core heats up.
This will furtter confuse the operator.
5.
Locating the thermocouple in the upper ple.1um or steam come probat.ly will not reduce the time delay. Furthermore, this has not yet been pro'.en to be a feasible option, due to installation difficulties.
6.
The installation cost of in-core thermocouples will be on the order of 2.5 million dollars for four thermocouples per quadrant.
7.
The maximum radiation exposure for thermocouple installation will be 450 man-rem.
y
REFEREi.CES '
1.
Convective Heat and Mass T ansfer, W. M. Kays and' N. E. Cra.vford.
McGraw Hill Publishing Co., 1978.
2.
"BWR 4/5/6, Standard Safety Analysis Report", General Electric Cc.
3.
5parrow, E. M., A. L. Loeffler, Jr., and H. A. Hubbard, Trans. ASME, J. Heat Transfer, pp. al5-422, Nov. 1961.
4
" Calculations of Combined Radiation and Convection heat Transfer in Rod Bundles Under Emergency Cooling Conditions", K. H. Sun, J. M.
Gonzalez and C. L. Tien ASME pa'per JS HT.-64,1975.
5.
" Gray - A Program for the. Calculattuna of Radiation Heat Transfer Gray Body Factors in Boiling 'At'er Fuel Bundles", J. M. Sorensen, D.
A. Mandell, R. Be. Belew, J.
P'. Dougherty.
6.
Core Design and Operating Data for Cycles'I and 2 of Peach httom 2, EPRI Tooical Report NP-563, June 1978.
~
7.
Turnage, Anderson, Davis an Piller " Advanced To Phase Flow In-strumentation Program Quarterly Progress Report for Jan-March 1980",
NUREG/CR-1647 (Sept. 1980)
Q o
s 8.
Turnage, Anderson, Davis and Miller, " Advanced Two Phase Flow Instrumentation Progre Quarterly.Progrcss Report for April-June, 1980, NUREG/CR-1768 (Dec. 1980).
9.
Turnage, - Anderson, Davis and Miller, " Advanced 'Two Phase Flow Instrumentatior Program Quarterly Progress Report for July-Sept.
1980, NUREG/CR-1903 (Mar. 1981).
i e
\\
s 4
s s
A
1 I
APPENDIX A Tne dimensions used in this analysis are shown below; f
Rod bundle axial length 148 ins.
1 Rod diameter 0.416 ins, 1
Cladoing thickness 0.034 ins.
Fuel Rods per bundle 64 Rod to wall gap 0.135 ins.
Channel cross section 5.52 x 5.52 ins.
Chan1el wall thickness
.120 ins.
Rated Reactor Thermal Power 2436 megawatts Thimble diameter 0.70 ins.
Thimble thic': ness 0.080 ins.
i k
e f
9~
APPENDIX B l
TABLE 1: BWR VARIABLES (NRC Regulatory Guide 1.97, Revision 2)
TYPE A Variables: those vanables to be monitored that provide the pnmary information required to permit th room operator to take sped.1 mar.uaUy controlled actions fo; which no automatv.controlis provided and for safety systems to accomplish thetr safety functions for design basis acczdent events. Primary inform tion that is essential for the direct accomphshment of the specified safety functions; it does not include those va that are associated with contmrency actions that may also be identified in wntren procedures.
A vanable included as Type A does not preclude it fron betng included as Type B, C. D, or E or vice versa.
Ca'tegory (see Regulatory 4
Vanable Range Positiori 1.3)
Purpose Plant specific Plant specific' 1
information required for operater action i
TYPE B Vanables. those vanaties th at provide mformation to mdtcate whether plant safety functions are being ac Plant safety functions are (1) reactivity control (2) core coohng (3) mamtammg reactor coolant system integnty maintaming contamment mtegnty Or;luding radioactive effluent control). Vanables are listed with designated r category for design and qualTication requiremerrt.. Key vanables are indicated by design and qualification Categ Reactivity Control Neutron Flux 10% to 100% fuu power i
Function detection; accomplishment (SRM. APRM) of trutigation Control Rod Pos; tion Fuu in or not fullin 3
Venficatton RCS Soluble Boron Concen.
O to 1000 ppm 3
Venfication tration (Samplel Core Cooling Coolant Levelin Resetor Bottom of core support plate to 1
Function detection; accomobshment icsser of top of vessel or center-of mittgation;long term surveillance line of mam steam une.
2 200'F to 2300*F l'
To provide diverse indication of BWR Core Thermocouples water level e
Maintaining Reector Coolant System integnty RCS Pressure; 15 paa to 1500 pus 1
Function detection; accomplishment of mittgation; verification
.\\
Drywell Pressure 0 to design pressure 3 (ps.s?
I Function detection; accomplishment of mitigation;ver:fication i
Four thermocouples per quearent. A minimum of one measurement ter quadrant ts required for operation.- /
8 Where a venable is hated for mars than one pur mee. the instrumentation requirements may be inteersted and miy one measurement pr 2
Design pressure a that value correspon1 ant to ASME code values teet are obteened et or below code edloweble values for m I
strees.
l l
l 9ty 1
% \\
^
TABLE 1 (Contmuod)
Category (see Regulatory Variable Range Position 1.3)
Purpose TYPE B (Continued) 2 Drywell Sump Level Bottom to top i
Function detection; accomplishment of mitigation; venfication Maintaining Containment integrity 2
3 Pnmary Contamment Pressure 10 psia to design pressure i
Function detection, accomplishment of trutigation;venfication Pnmary Containment Isola-Closed-not closed i
Accomplishment of isolation tion Valve Position lesclud mg check valves)
TYPE C Vanables: those vanables that provide information to mdicate the potential for being breached or the actual breach of the barners to fission product releases. The barners are (1) fuel cladding. (2) pnmary coolant pressure boundary,and(3) con-tainment.
Fuel C! adding Radioactivity Concentration or 1/2 Tech Spec limit to 100 times Detection of breach Radiation Levelin Circulating Tech Spec limit, R/hr Pnmary Coolant Analysis of Pnmary Coolant 10 wCi/gm to 10 Cilgm or 3*
Detail analysis; accomplis'hment of (Gamma Spectrum)
TID 14844 source term in mitigation: venfication, long term coolant volume surveillance BWR Core Thermocouples:
200*F to 2300*F l'
To monitor core cochng Reactor Coolant Pressure Boundary RCS Pressure
- 15 psia to 1500 psis I
Detection of potential for or actual s
breach, accomphshment nf mitiga-tion;long term survettlance 8
37 Detection of breach; venfication 6
Pnmary Containment Area I R/hr to 10 R/hr Radiation:
I l
- Sampling or monitoring of radioactive lieusds and gases should be performed in a manner that ensures procurement or representstive semples. For gases the enterta of ANSI NI).1 should be apphed. For hounds, proviosons should be made for sempting from weu mised turbu-tent sones, and semphng lines should be deangned to mmimite posteout or deposition. Fod safe and convenient sempting, the provmons shoulJ unclude:
- a. Sh6elding to maintain radietton doses ALAft A.
- b. Sample containers with containerempting port connector compettbdity,
- c. Capatnhty or sempting under primary system pressure and negattve pressures.
- d. Hendhne and trentport capsbehty, and
- e. Preeerensement fne snelys,a and interpretectem.
'The menemum value may se revised upward to settsfy ATWS requirements.
(
0Minimum of two monteors et widely esperated locations.
7Detectors should respond to gereme radiation photons within a of $20 percent at any specific photon energy from 0.1 MeV to 3 Me7. energy range from*60 lieV to 3 MeV with an energy response occuracy Overall system accutscy should be within a factor of 2 over the entire r an ge.
1.97 9 LOO
e TABLE 1 (Contmuod)
Category (see Regulatory Variable Range Position 1.3)
Purpose TYPE C (Conanued)
Reactor Coolant Pressure Boundary (Contmuodi
'Drywell Dram Sumps level Bottom to top l
Detettson of hresch. accomplishment 2
of mitigatson;venficauon;long term (Identified and Umdentified survedlance Leakage)
Suppression Pool Water Level Bottom of ECCS suction line i
Detection of breach;accomphshment to 5 ft above normal water of trutagation; venfication,long term level survedlance Drywell Pressure O to design pressure 3 (psig)
I Detection of breach: verification t
Containment RCS Pressure 15 psia to 1500 psig is Detection of potential for breach; 2
accomphshment of mitigation Pnmary Contamment Pressure 10 pua pressure to 3 times design i
Detection of pntential for or actual t
pressure for concrete. 4 times breach, accomphshment of mitiga-3 design pressure for steel tion Containment and Drywell O to 30". (capabihty of operating I
Detection of potential for breach; Hydrogen Concentration from 12 psia to design pressure )
accomphshment of mitigation 3
Contamment and Drywell O to 10"o(capabdity of operating I
Detection of potential for breach; Onysen Concentration (for from 12 pua to design pressure )
accomp!sshment of mitigation 3
inerted containment plants)
Contamment Effluent: Radio.
10 uCi/cc to 10 2 uCi/cc 3 a.,
Detection of actual breach; accom-activity Nnble Cases (from pbshment of mitigation; venfica-tion identified release points includ-ins Standby Gas Treatment System Vent) 7 Radiation Exposure Rate (in-10 R/hr to 10' R/hr 2
(ndication of breach t
ude buddings or areas, e.g.,
ausdiary budding, fuel hand-ling budding, secondary con-tainment, which are in direct contact with pnmary con-tamment where penetrations and hatches are located)
Provtssons should be made to monstof oilidentifled pathways for teleene of gaseous tedsoective metenais to the enyttons 6n conformance O
with General Design C stenon 64. Monttonns of 6ndividual effluent etteams is only requited wnete such streams ete teleased datectly anto the enyttonment, if two of more streams att combined pnnt to telease rtom a common dischatte point, morutonns of the combined stream a considered to meet the talent of this reguletory guide prowtJeJ such monitonnt has a range adequate to measure wortt-case teleases.
' Monitors should be capable of detecting and measunn radioestive gaseous effluent concenttetions with compoestions tsaging from fresh mastures. *stn overall system aceutecses within a factor of 2. Effl.ent concentre-equalsbnum noete gas flesson product mistures to to day od tenne met be espressed in terms of Xe 4 33 equiveients or in terms of any noDie gas nuctodetst it is not espected that a sensie monienting device will have sufficsent range to encompass the entate tange provided 6n this regulatory tu6de and that muitspie components of systems will be needed. IEaJeting equipment may be used in monitor any portson of the stated tange within the equipreent Jesagn retang.
1.97 10
.01 i
o TABLE 1 (Congnued) o Category (see Regulatory Variable Range Position 1.31 Purpose TYPE C (Continued)
Containment (Continued) 2 yCi/cc 2'
Indication of breach Effluent Radioactmty Noble 10 yCi/cc to 103 Gases (from buildmgs as mdicated above)
TYPE D Variables: those variables that provide information to indicate the operation ofindividual safety systems and other systems important to safety. These vanables are to help the operator make appropriate decisions in using the individual sys-tems important to safety in mitigating the consequences of an accident.
Condensate and Feedwater System Main Feedwater Flow 0 to 1107, design flow
3 Detection of operation; analysis of cooling Condensate Storge Tank Level Bottom to top 3
Indication of avadable water for cooling Primary Containment Related Systems Suppression Chamber Spray 0 to 110% design flow
2 To morutor operation Flow 2
Drywell Pressure 12 psia to 3 psig 2
To monitor operation 3
0 to 1107. design pressure Suppression Pool Water Level Top of vent to top of weit well 2
To monitor operation Suppression Pool Water 30*F to 230*F 2
To monitor operation Temperature Drywell Atmosphere 40*F to 440*F 2
To monitor operation Temperature 8
Drywell Spray Flow 0 to 1107. design flow '
2 To morutor operation Main Steem System Main Steamline Isolation 0 to 15"of water 2
To provide indication of pressure Valves' Leakage Control 0 to 5 psid boundary mavitenance System Pressure Primary System Safety Relief Cosed-not closed or 0 to 50 psig 2
Detection of accident; boundary Valve Positions, including ADS integrity indication or Flow Through or Pressure in Valve Lines 10Desen flow 4 the mesimum flow entscipated in normet operetson.
l.97 1 l LO2
e a
TABLE 1 (Continued)
Category (see Regulatory Vertable Range Position 1.3)
Purpose TYPE D (Cononued)
Safety Systems isolation Condenser System Top to bottom To monitor operation Shell. Side Water Level isolation Condenser System Open or closed To monitor status Valve Position u
RCIC Flow 0 to 110", design Gow'8 2
To monitor operation llPCI Flow 0 to 1IM design dow'8 To monitor operation Core Spray System Flow 0 to 110", design now'8 To monitor operation LPCI System Flow 0 to I1% design now'8 2
To monitor operation SLCS Flow 0 to 110", design now'8 2
To monitor operation SLCS Storage Tank Level Bottom to top To monitor operation Resir'. sal Heat Removal (RHR)
Systems RilR System Flow 0 to ll(Y: design now'8 To monitor operation RilR Ilev Exchanger Outlet 3:*F to 3!0*F 2
To monitor operation Temperature Cooling Water System Cooling Water Temperature to 32*F to 200*F To monitor operation ESF System Components Cooling Water Flow to ESF 0 to 110". de: tan dow' 8 2
To monitor operation System Components Radweste Systems High Radioacnvity Liquid Tank Top to bottom 3
To monitor operation Level Ventilation Systems Emergency Ventdation Damper Open closed status 2
To monitor operation Position Power Supplies Status of Standby Power and Voltages, currents. pressures 2'
To monitor system status 8
Other Energy Sourceslmportant to Safety (hydraulic, pneumatac)
I' Statue indiosson of aal Standby Power a.c. buses, d.c. Duses. inverter output buses, and oneumatic supplies.
l.97 l!
103' w __
TABLE 1 (Contmued)
PE E Venables: those variables to be monitored as required for use in determmme the magnitude of the release of radio-
- ve rnaternah and contmually assessmg such releases Category (see Regulatory Variable Range Position 1.31 Purpose Containment Radiation Pnmary Containment Area i R/hr to 10' R/hr l**'
Detection of sienificant releases.
3 Radiatsori lingh Range release assessment;long-term survedlance; emergency plan actuation Reactor Budding or Secondary 10 R/hr to 10' R/hr for Mark !
2' Detection of significant releases, Contunment Area Radiation
- and 11 contunments release assessment,long term I R/hr to 10' Rihr for Mark !!!
l*
sursedlance contunment Area Radiation Radiation Exposure Rate!
10 s Rlhr to 10* R:ht 2
Detection of sienificant releases.
7 (mside buddmps or areas where release assessment;long term ateess is required to servi 6e survedlance equipment important to safety)
Airborne Radioactive Materials Released from Plant Noble Gases and Vent Flow Rate Dryweu Purse. Standby Gas 10* Si/cc to 10' uCi/cc Detection of sismficant releases; Treatment System Purge O to II0f4 vent design flow
release assessment (for Mark 1 and 11 plants)
(Not needed if efnuent discharges and Secondary Contun-through common plant venti rnent Purge f for Mark Ill plants)
Secondary Contamment 10** uCi/cc to 10" uCi/cc 2'
Detection of sinnificant releases.
Purge ifor Mark I. II, and 0 to 110?. vent desian flow
release assessment 111 plants) f Not needed if efnuent discharges through common plant vent)
Secondary Contunment 10** Si/cc to 10' uCi/cc 2'
Detection of sismficant releases; (reactor stueld buildmg 0 to 110% vent design flow
release assessment annulus, if in design )
INot needed if effluent discharges through common plant vent)
Ausdaary Budding 10'* Ai/cc to l08 uCi/cc 2'
Detection of significant releases, lincludmg any budJms 0 to !!0fe vent de.asn flow
release assessment;long term contamma ptsmary system (Not needed if effluent discharges survedlance gases, e.g., waste gas decay through common plant vent) tank)
Common Plant Vent or Multi-101,Ci/cc to 103 uCi/ec 2'
Detection of siensficant releases, purpose Vent Diseharg:ng 0 ' !!O3 vent Jesign flow
release assessment;long term i
Any of Above Releases (if surveillance drywell or SGTS purge is j
meluded) 10** ;.Ci/cc to 10' uCi/cc l.M !J i i i 'i
o o
TABLE 1 (Connnued)
Category (see Regulatory Vaneble Ranoe Posinon 1.3)
Purpose TYPE E (Continued)
Airbome Radioacave Materials Released from Plant (Conanued)
Noble Gases and Vent Flow Rate (Contmued)
AU Other identified Release 10* uCyce to 102 uCi/cc 2'
Detection of significant relo w s; Points 0 to 110% vent design flow
release assessment long-term (Not needed if effluent discharges survedlance through other monitored plant vents)
Particulatei and flalogens All Identified Plant Release 10'3 uCi/cc to 10 uCi/cc 3
Detection of significant releases; 2
32 Pomts. Sampimg with Onsite O to 110% vent design flow
release assessment;long term Analysts Capabdity survedlance Environs Radiation and Radio-actiesty Radiation Exposure Meters Range, location. and qualafica-Vertfy significant releases and local (contmuous indication at non criteria to be developed to magnitudes fixed locations) satisfy NUREG 0654. Seenon
!!.H.5b and 6b requirements for emergency radiological monitors Airborne Radiohalogens and 10* uCi/cc to 10'3 pCi/cc 3
Release assessment; analysis 83 Particulates (portable sampimg with onsate analysis capabdity)
Plant and Environs Radiation 10'3 R/hr to 10' R/hr, photons 83*
Release assessment, analysis (portable instrumentabon) 10'3 rads /hr to IO* rads /hr, beta 83' radianons and low energy photons Plant and Environs Radio.
Multichannel samma ray 3
Release assessment; analysts activity (portable instru-spectrometer mentation)
I2To provtda informsuon resarding release of tedioactive halogene and partaculates. Contmuous collection of representative samples followv4 by onnte datoratory measurements of samples for radaonalogens and particu.ates. The design envelope for thielding, handling. and analyticas purposes should assume Jo minutes ofintegrated sampling time at sampler design flow, an average concentratiot. of to yO/cc of radiciodanes in saaeous or vapor form. an average concenerstion of 10 average samma photon energy of 0.s MeV pet disentepetion.'gCi/ct of particulate radiosodines and particulates other than redsosodmes, 13 Foe esemating release rates of radioacetve mecenals released during an acesdent.
I'To monitor radiation and airborne radioactivity concentrations in many arena throughout the facility and the site environs where et.s improcucal to snatell stessonary monitors capable of covenna both normal and accident leveta.
i 1.97 14 IC3
o o
TABLE 1 (Continued)
Category (see Regulatory Variable Range Position 1.31 Purpose TYPE E (Continued) 88 Meteorology wtnd Direction 0 to 360* (:$* accuracy with a 3
Release assessment oeflection of 15'). Stamns speed 0.45 mps (1.0 mph). Damping ratio between 0.4 and 0.6. distance con.
sunt 12 meters Wutd Speed 0 to.10 mps (67 mph) ::0.:: mps 3
Releue assessment (0.5 mph) accuracy for wind speeds less than 11 mps (25 mph) with a starting threshold of less than 0.45 mps 1.0 mphi Estimation of Atmos-Based on vertical temperature 3
Release assessment pheric Staothly difference from pnmary system.
5'C to 10*C (.9'F to 18'F) and 30.15*C accuracy per 50 meter intervals (:0.3*F accuracy per lo4 f oot intervals) or analogous tante for alternative stabtlity estirnates Amident Semolinq!
- Caos.
belity (Analysis Capabd-ity On Site)
Pnmary Coolant and Sump Grab Sample 3* 87 -
Release assessment; venfication, analysts Gross Activity 10 uCi/mi to 10 Ci/mi Gamma Spectrum (Isotopic Analyns) e Boron Content 0 to 1000 ppm Chlonde Cor tent 0 to 20 ppm Dissolved Hydrogen or 0 to 2000 cetSTP)ILg Total Gas
ts Dissolved Oxygen 0 to 20 ppm pil I to 13 i
Containment Air Grab Sample 3*
Release assessment; venficauon.
artalysts Hydrogen Content 0 to 10".
O to 307e for inerted containments Oxygen Content 0 to 30"e Camma Spectrum (hotopic analysis) 8ICusdance on meteorologsw measurements is being developed in a Proposed Revis6on I to Regulatory Gesede 1.23. **Meteorologscal Programa en Support of Nuclear rower Planta."
16The time for takatis and analystng sampfes should be 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> or less from the time the decision la mode to sample, esteet for chlonde wtiuh should be withan 2e hours.
I An (notoGod espetetty should be provided for obtaining contaamment sump. ECCS pump room sumps, and other semdat essentiary budding sump ugened aamptes.
IIAppines only to pnmety coolant.not to semp.
m.i $
los
/
1 q
l APPENDlX C ABBREVIATIONS i
ADS automatic depressurization system APRM average-power range monitor NCJS anticipated transients without scram BWR boiling water reactor BWROC Boiling Water Reactor Owners Group CRD control rod drive CS core spray CST condensate storage tank ECCS emergency core cooling system EDG emergency diesei generator EPG Emergency Procedure Guidelines EPRI Electric Power Research Institute ESF engineered safety feature HPCI high-pressure coolant injection IRM intermediate-range monitor LOCA loss of coolant accident LPCI low-pressure coolant injection LPCS
. low-pressure core spray LPRM local power range monitor NMS neutron monitoring system NSAC Nuclear Safety Analysis Center NSSS nuclear steam supply system OG Owners Group PASS post-accident sampling system PWR pressurized water reactor RCIC reactor core isolation cooling RCS reactivity control system RHR residual heat removal RG Regulatory Guide i
107
O 6
RPV reactor pressure vessel RWCU reactor water cleanup unit SBGT standby gas treatment SCS suppression chamber spray SGTS standby gas treatment system SLCS standby liquid control system SRM source range monitor S R'l safety relief valve I
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