ML20205P804
| ML20205P804 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 03/05/1986 |
| From: | Alamnar M, Eibon K GENERAL PUBLIC UTILITIES CORP. |
| To: | |
| Shared Package | |
| ML20205P802 | List: |
| References | |
| RTR-REGGD-01.097, RTR-REGGD-1.097 TR-028-R00, TR-28-R, TR-O28, NUDOCS 8605220008 | |
| Download: ML20205P804 (156) | |
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OYSTER CREEK RESPONSE TO US NRC REGULATORY GUIDE 1.97 TOPICAL REPORT # 028 I
PROJECT NUMBER:
5300-G0191 M. A. ALAMMAR K. R. EIBON January 9, 1986 APPROVALS:
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ak/w MANAGER, SAFETY ANALYSIS & PLANT CONTROL DATE I
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MANAGER, EPEI DATE g
+t w i s.n DIRECTOR, SYSTEMS EN NEERING DATE dL DIRECTOR, ENGINE ING & DESIGN DATE I
I n r S888: n888: 1, P
TR 028 I
Rev. O Page j ABSTRACT
/
/
This Topical Report describes GPU Nuclear position in regard to meeting US NRC Reg Guide 1.97, " Instrumentation for... Nuclear Power Plants... Following an Accident", Revision 2 at Oyster Creek. This report is based upon GPUN I
Technical Data Report 528, Revision 2 and the BWR Owners Group Position, July 1982.
It recommends that various OC parameters be required for monitoring post-accident conditions.
Recommendations for displaying those parameters for which instrumentation either does not exist or upgrading existing instrumentation which is not in compliance is also given in Table 3.
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I TR 028 I
Rev. O Page A TABLE OF CONTENTS PAGE
1.0 INTRODUCTION
3 I
2.0 METH00.............................
4 2.1 NRC Position 4
2.2 BWROG Position 4
2.3 GPUN Position.......................
4 2.4 Definitions........................
5 I
3.0 RESULTS 7
4.0 CONCLUSION
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5.0 RECOMMENDATIONS 9
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6.0 REFERENCES
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7.0 TABLES.............................
9 t
l TABLE 1 Proposed Parameter Set for Oyster Creek 10 1
TABLE 2 Status of Minimum Parameter Set for Oyster Creek...
26 TABLE 3 Actions Required to Satisfy RG 1.97 Requirements for OCNGS Minimum Parameter Set 39 I
APPENDIX A:
BWR OWNERS GROUP POSITION ON NRC REGULATORY GUIDE 1.97, REVISION 2 48 I
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1.0 INTRODUCTION
USNRC Regulatory Guide 1.97, Revision 2, was issued in December 1980.
The Intent of Regulation Guide 1.97 is to ensure that all light water I
reactors are properly instrumented to.ssure proper responses during and following an accident.
Regulatory Guide 1.97 provides methods which are acceptable to the NRC staff to comply with the commissions requirements for instrumentation necessary to monitor and assess plant conditions during and following an accident.
In addition, Generic Letter 82-33 required that al'1 utilities provide a I
schedule for implementing Regulatory Guide 1.97.
On April 15, 1983, GPU Nuclear advised the NRC that GPU would perform a plant specific study for Oyster Creek and submit the results of this study, including a schedule of implementation by May 1, 1984.
The purpose of this report is to provide the following information for Oyster Creek Nuclear Generating Station (OCNGS):
Specify the minimum parameter set to meet the intent of R.G. 1.97, Revision 2.
Determine the status of the existing instrumentation against the R.G. 1.97 design and qualification requirements.
Provide justification for the variables that do not comply with the requirements of R.G.1.97 but are considered adequate for OCNGS.
I Provide explanations for items which exceed NRC requirements for Oyster Creek.
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TI 028 Rev. O Page Y 2.0 METHODS 2.1 NRC Position The NRC in R.G. 1.97, Revision 2, Table I identified a minimum list I
of "B", "C", "D" and "E" type parameters for light water reactors and their required ranges.
Type "A" variables were not specified because they will depend on the specified planned manual operator I
actions required during Reactor Accidents.
The NRC has stated that 1
Type "A" variables would be determined on a plant specific basis, j
2.2 BWROG Position on R. G. 1.97. Revision 2 The recommendations of the BWROG titled "BWR Owners Group Position on NRC Regulatory Guide 1.97, Revision 2" can be found in a BWROG' report by the same title.
The BWROG identified five variables as Type "A" and proposed six additional variables as potential Type "A".
Also, the BWROG stated its position with regard to Types "B",
I "C", "D",
and "E" variables and design categories as identified in R.G. 1.97, Table I.
2.3 GPUN Position GPUN concurs with the recommendations of the BWROG except as noted in Table I of this report.
In the selection of Type "A" variables, GPUN considered Design Basis Accident Events to ensure that safety systems' success during a DBA does not require operator action based upon parameters other than those selacted. Other considerations during variable selection were:
a)
Scenarios that could lead to core damage or radiation release to the public, may not have been considered as a basis in the I
analysis included in the Facility Design and Safety Analysis Report. (i.e., the TMI-II March 28, 1979 event); and therefore, could be overlooked.
b)
The parameter selection technique employed in R.G. 1.97 was a critical safety function (i.e., reactivity, core cooling, reactor coolant system integrity, and containment integrity)
I approach and does not lend itself to an event oriented approach.
This approach will bound the specific events analyzed for OC.
c)
This critical function approach is also used in development of the Emergency Operating Procedures (EOPs) and their entry I
conditions.
This would also preclude using an Event Oriented approach in determining what "socified manually controlled actions" are required in the E0Ps for " safety systems to accomplish their safety function."
d)
The BWROG also used symptom oriented E0Ps and critical safety function approach in the formulation of their position on R.G. 1.97.
Again, an event oriented approach would be inconsistent with existing work and any results would be suspect.
TR 028 Rev. O Page [
e)
A review of the existing emergency operating procedures (500's) for any specified manual actions proved futile. Most I
procedures simply state " ensure all automatic functions have taken place" and assume most everything functions properly.
In the case of the refueling accident DBA, no specific procedure currently exists. Symptom Based Emergency Operating Procedures were then used as a source of planned manual actions.
The current Oyster Creek E0Ps are based upon Revision 2 of the BWR Owners Group Emergency Procedure Guidelines.
Therefore, a symptom oriented critical safety function approach was used in conjunction with the E0Ps in selecting Type "A" variables.
2.4 Definitions I-The following definitions of Type variables and Categories are taken from R.G. 1.97.
I 1)
Type "A" "Those variables to be monitored that provide the primary information required to permit the Control Room Operator to take the specified manually controlled actions for which no automatic control is I
provided and that are required for safety systems to accomplish their safety function for design basis accident events."
R.G. 1.97 calls these variables I
plant specific and requires plants to specify them as needed.
I 2)
Type "B" "Those indications that provide information to indicate whether plant safety functions are being accomplished.
3)
Type "C" "Those variables that provide information to indicate the potential for being breached or the actual breach of the barriers to fission product release, i.e.,
I fuel cladding, primary coolant pressure boundary, and containment."
4)
Type "D" "Those variables that provide information to indicate I
the operation of individual safety systems and other systems important to safety.".
5)
Type "E" "Those variables to be monitored as re.1uired for use in determining the magnitude of the rt: lease of radioactive materials and in continually assessing such releases."
6)
Category 1 "Provides the most stringent requirements and is l g intended for key variables" (i.e., Class IE, i g seismic, single failure, and Type "A" and "B" key variables).
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Category 2 "Provides less stringent requirements and I
generally applies to instrumentation designed for indicating system operating status."
(Type "D" and "E" key variables).
8)
Category 3 "High-quality off the shelf instrumentation."
(Backup and diagnostic information).
These definitions provide the functional requirements for the design and qualification criteria for instruments identified in this report.
I NOTE:
Variables that could be considered A and B and C variables, e.g. Reactor Water Level, have not been repeated.
They have been placed for clarity only in their highest type and category.
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TR 028 Rev. O Page 9-3.0 RESULTS The results of this report are summarized in Tables I, II, and III.
A.
Table I - Proposed Parameter Set for Oyster Creek Table I lists the variables and categories proposed by R. G. 1.97 and the BWROG's and GPUN's position on these variables.
Table I also contains the BWROG's recommended and proposed Type "A" I
variables.
Justification for inclusion or exception to the R.G. 1.97 or BWROG's recommendation or inclusion of additional variables are contained in Table I as required.
The basis for developing Table I of this report was R.G. 1.97, Revision 2, Supplement I of NUREG 0737 (Generic Letter 82-33) and the Oyster Creek Emergency Operating Procedures.
8.
Table II - Status of Minimum Parameter Set for Oyster Creek l
Table II provides a minimum parameter set for Oyster Creek based on R.G. 1.97, the comments of the BWROG and a detailed review of the Oyster Creek Control Room in light of emergency procedure I
requirements.
Table II also provides the status of these parameters based on the requirements listed in R.G. 1.97, Table I.
C.
Table III - Actions Required to Satisfy R.G. 1.97 Requirement's for I
OCNGS Minimum Parameter Set Table III addresses the deficiencies identified in Table II.
Justification for variables that are not in strict compliance with R.G. 1.97, but for which GPUN does not feel upgrading is required, is also presented in Table III.
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4.0 CONCLUSION
The conclusion of this report is a required parameter set identified in Tables I and II.
The status of compliance for each proposed parameter is also identified.
It is concluded that several of.these parameters I
need upgrading while others are to be accepted as is.
These items are identified and discussed in Table III.
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TR 028 Rev. O Page 7 5.0 RECOMMENDATIONS It is recommended that the parameter instrumentation requiring upgCading identified in Table III be performed.
6.0 REFERENCES
1.
R.G. 1.97, Revision 2.
2.
BWROG Response to R.G. 1.97, Revision 2, December, 1980.
I 3.
R.G. 1.97, Revision 3, May 1983.
Reviewed for information.
4.
GPUN TDR 578 - Torus to Drywell Bypass Area Evaluation 5.
GPUN - E.Q. Haster List Rev. 1.
I 7.0 TABLES I
A)
Table I - Proposed Parameter Set for Oyster Creek B)
Table II - Status of Minimum Parameter Set for Oyster Creek C)
Table III - Actions Required to Satisfy R.G.1.97 Requirements for OCNGS Minimum Parameter Set I
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M TABLE I PROPOSED PARAMETER SET FOR OYSTER CREEK Y = Yes (Implement)
N = No (Do Not Implement)
P = Proposed Recommended By NRC BWROG CPUN Parameter Description Y/N Cat Y/N Cat Y/N Cat Justification A-1 RPV Pressure Y
l Y
l Manual operator actions are:
a) Depressurize the reactor and monitor a safe cooldown rata.
b) Operation of the Isolation Condenser to maintain pressure in the E0P pressure control section.
c) Detection and correction of a cycling EMRV.
d) Verification that pressure is less than 285 psig prior to opening core spray parallel valves.
e) Take manual pressure control if safety systems fail.
The safety functions involved are:
a) Adequate core cooling.
b) Reactor coolant system integrity.
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M TABLE I PROPOSED PARAMETER SET FOR OYSTER CREEK Recommended By NRC BWROG GPUN Pcrameter Description Y/N Cat Y/N Cat Y/N Cat Justification A-2 RPV Water Level Y
l Y
l Manual operator actions are:
a) Restore and maintain water level:
- 1) Control core spray to prevent flooding the vessel.
- 2) Take manual actions if safety systems do not function properly.
- 3) Ensure level is low enough to prevent severe water hammer prior to operation of isolation condensers or EMRVs.
The safety functions are:
a) Adequate core cooling.
b) Reactor coolant system integrity.
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M TABLE I PROPOSED PARAMETER SET FOR OYSTER CREEK Recommended By NRC BWROG GPUN Parameter Description Y/N Cat Y/N Cat Y/N Cat Justification A-3 Torus Water Temperature Y
l Y
l Torus water temperature is an indication of:
a) Exceeding design temperature limits.
b) Adequate heat absorption capability in the
As well as being an E0P entry condition, torus water temperature is an action level to:
a) Initiate torus cooling.
b) Scram the reactor or initiate liquid poison during an ATWS.
c) Emergency depressurization of the reactor to stay within the heat capacity temperature limit.
d) Close a stuck open EMRV.
Torus water temperature measurement is required by NUREG 0783.
The safety functions are:
- 1) Containment integrity.
- 2) Reactor coolant integrity.
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M TABLE I PROPOSED PARAMETER SET FOR OYSTER CREEK Re :ommended By NRC BWROG GPUN Pcrameter Description Y/N Cat Y/N Cat Y/N Cat Justification A-4 Torus Water Level Y
1 Y
1 Manual operator actions are:
a) Maintaining torus level below the torus load limit curve or depressurize the reactor to below the load limit in the E0Ps.
b) Add water as necessary to ensure ECCS equipment has adequate NPSH.
c) Limit an increasing level to ensure an adequate torus vent path.
Safety functions are:
a) Containment integrity.
b) Adequate core cooling, i
A-5 Drywell Pressure Y
1 Y
1 Manual operator actions are:
a) Start containment spray since this requires a coincident lo-lo reactor water i
level signal for automatic initiation or if a failure to auto start occurs.
1 Safety functions are:
l a) Primary containment integrity.
I b) Reactor coolant integrity.
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W PROPOSED PARAMETER SET FOR OYSTER CREEK Recommended By NRC BWROG GPUN Parameter Description Y/N Cat Y/N Cat Y/N Cat Justification 1
A-6 Drywell Combustible Gas P
Y 1
Manual actions are:
1 Concentratiod (Oz, Hz) a) Shift to an alternate mode of core cooling due apparent cladding failure (i.e.
Zr/ water reaction).
b) If hydrogen exceeds explosive limits, institute hydrogen control procedures.
Safety functions are:
a) Adequate core cooling.
l b) Primary containment integrity.
Only proposed for those plants with HPCI or A-7 Condensate Storage Tank P
N l
Level RCIC systems with automatic suction transfer (i.e. from CST to torus). These systems do l
not exist at Oyster Creek (See D-2).
See BWROG discussion in Appendix A, Page 12 of l
Reference 2.
Condensate Storage Tank level is not called out in 0.C. EOPS.
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E' TABLE I PROPOSED PARAMETER SET FOR OYSTER CREEK Recommended By NRC BWROG GPUN Pcrameter Description Y/N Cat Y/N Cat Y/N Cat Justification A-8 Emergency Diesel P
N The only " safety related" loads that would be Generator Load added to the EDG after a large accident are RBCCW, service water. TBCCW fans and an air compressor. These loads are not needed immediately following a reactor accident.
Therefore, various ECCS loads may be secured (redundant core and containment spray systems) leaving sufficient desired capacity.
A-9 Reactor Building P
N See BWROG discussion in Appendix "A", Page 12 Flood Level of Ref. 2.
Capacity for operator to pump reactor building sump to torus does not exist and this is "an aid not the accomplishment of a safety function".
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PROPOSED PARAMETER SET FOR OYSTER CREEK Reconsnended By NRC BWROG GPUN Parameter Description Y/N Cat Y/N Cat Y/N Cat Justification B-1 Neutron Flux Y
1 Y
2 Y
2 GPUN concurs with the NRC on the identification of B-1 through B-10 as Type "B"
variables except for B-5, BWR Core Thermocouples. See BWROG issue 3 for a discussion of B-5.
Also, CPUN agrees with the BWROG on downgrading B-8, Drywell Sump Level, to a Category 3.
See BWROG issue 4 for a discussion.
B-2 Control Rod Position Y
3 Y
3 Y
3 See B-1.
3 Y
3 Y
3 See B-1.
B-4 RPV Water Level Y
1 Y
1 Y
1 See B-1.
B-5 BWR Core Thermocouples Y
1 N
N See B-1.
B-6 RPV Pressure Y
1 Y
1 Y
1 See B-1.
B-7 Drywell Pressure Y
1 Y
1 Y
1 See B-1.,
B-8 Drywell Sump Level Y
1 Y
3 Y
3 See B-1.
B-9 Containment Pressure Y
1 Y
1 Y
1 See B-1, B-7.
Containment pressure taken as drywell pressure because as shown in Ref. 4, drywell pressure envelopes torus pressure.
B-10 Drywell Isolation Valve Y
1 Y
1 Y
1 See B-1.
Position
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M TABLE I PROPOSED PARAMETER SET FOR OYSTER CREEK Recommended By NRC BWROG GPUN Parameter Description Y/N Cat Y/N Cat Y/N Cat Justification B-11 Reactor Water Level Cold Reference Leg Temp Y
2 (Drywell Temperature)
B-12 Torus Pressure Y
2 Torus pressure is approximated by drywell pressure (A-5).
Ref. 4 shows this is a conservative approach at Oyster Creek.
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M TABLE I PROPOSED PARAMETER SET FOR OYSTER CREEK Recommended By NRC BWROG GPUN Parameter Description Y/N Cat Y/N Cat Y/N Cat Justification C-1 Radioactivity Conc. or Y
1 N
N BWROG Issue 5 of Reference 2.
Radiation Level in Primary Coolant C-2 Analysis of Reactor Y
3 Y
3 Y
3 Coolant (Grab Sample)
C-3 BWR Core Thermocouples Y
1 N
N BWROG Appendix "A" of Reference 2.
C-4 Drywell Area High Y
3 Y
3 Y
3 4
Radiation C-5 Drywell Sump and Equipment Y 1
Y 3
Y 3
BWROG Issue 4.
Use alarm, leak rate indicator, Drain Tank Level flow integrators and pump run time integrators.
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M TABLE I PROPOSED PARAMETER SET FOR OYSTER CREEK Recommended By NRC BWROG GPUN Parameter Descriptior.
Y/N Cat
?/N Cat Y/N Cat Justification C-7 Containment Effluent Y
3 Y
3 Y
3 Variables C-6 and C-8 are considered to be Radioactivity (Noble Gases) equivalent at Oyster Creek because of physical configuration.
C-8 kadiation Exposure Rate Y
2 N
N See BWROG Issue 6 of Reference 2.
This variable is not a good indicator for detection of breach due to already high radiation levels.
C-9 Effluent Radioactivity Y
2 Y
2 Y
3 See C-6 from Reactor and Turbine Building C-10 Reactor Building Pressure -
Y 3
Reactor building pressure (atmospheric d/p) is an indication of secondary containment integrity.
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PROPOSED PARAMETER SET FOR OYSTER CREEK Recommended By i
NRC BWROG GPUN l
Pr.rameter Description Y/N Cat Y/N Cat Y/N Cat Justification i
D-1 Main Feedwater Flow Y
3 Y
3 Y
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l D-2 Condensate Storage Tank Y
3 Y
3 Y
3 L
Level D-3 Torus Spray Flow Y
2 N
N See BWROG Issue 7 of Referenes 2.
D-4 Drywell Atmosphere Temp.
Y 2
Y 2
Y 2
Reactor water level cold reference leg temperatures are indicative of drywell temperatures. Due to their locations and Oyster Creek post-accident drywell conditions, plant analysis has shown that these thermocouples are representative of drywell temperature.
See B-11.
D-5 Drywell Spray Flow Y
2 N
N See BWROG Issue 7 of Reference 2, See D-16 (Cont. Spray Flow)
D-6 Main Steam Line Y
2 N*
N
- Not recoassended if not part of plant design Isolation Valve 'aakage (see Reference 2, pg. 20)
Control System Pressure i
l D-7 Valve Monitoring System The Oyster Creek VMS is an acoustic monitoring (VMS) - Vessel Pressure system which indicates valve position, open or reliefs shut, in the control roc:n.. Direct operator j
EMRV'S (5)
Y 2
Y 2
Y 2
action will close an open EMkV. However, the
{
Oyster Creek code safety relief vs1ves are' Code Safety (16)
Y 3
completely automatic ar.d can not be over Valves ridden.-
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PROPOSED PARAMETER SET FOR OYSTER CREEK Recommended By NRC BWROG GPUN Parameter Description Y/N Cat Y/N Cat Y/N Cat Justification D-8 Isolation Condenser Y
2 Y
2 Y
2 Shell-side Water Level D-9 Isolation Condenser Y
2 Y
2 Y
2 System Valve Position D-10 RCIC Flow Y
2 N
N System not installed at Oyster Creek.
D-11 HPCT Flow Y
2 N
N System not installed at Oyster Creek.
D-12 Core Spray Flow Y
2 Y
2 Y
2 D-13 LPCI Flow Y
2 N
N System not installed at Oyster Creek.
D-14 SLCS Flow Y
2 Y
3 Y
2 See BWROG Issue 9 of Reference 2.
No action plan until ATWS requirement is finalized.
D-15 SLCS Storage Tank Level Y
2 Y
3 Y
3 See BWROG Issue 10.
D-16 Containment Spray System Y
2 Y
2 Y
2 Primary indicator of the proper operation of Flow the containment spray system's function of delivering cooling water sprays to the drywell/ torus that is necessary for long-time decay heat remova1 during a LOCA.
D-17 Containment Spray Y
2 Y
2 Y
2 Primary indicator of the proper operation Heat Exchanger Outlet of the containment spray system's function
- Temperature of delivering cooling water sprays to the drywell/ torus that is necessary for long-time decay heat removal during a LOCA.
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M TABLE I PROPOSED PARAMETER SET FOR OYSTER CREEK Recommended By NRC BWROG GPUN Parameter Description Y/N Cat Y/N Cat Y/N Cat Justification D-18 Emergency Service Water Y
2 Y
2 N
Verification of proper operation of the con-Temperature to Containment tainment spray HX is obtained from system Spray Heat Exchanger flow and temperature data.
D-19 Emergency Service Water Y
2 Y
2 Y
2 Flow to Containment Spray D-20 High Radioactivity Y
3 Y
3 Y
3 In Radwaste Control Room only.
Tank Level D-21 Emergency Ventilation Y
2 Y
2 Y
2 Damper Position D-22 Status of Standby Power Y
2 Y
2 Y
3 Oyster Creek has no safety grade hydraulic and other Energy Sources system. All safety functions of Instrument Important to Safety Air are accomplished by local accumulators.
D-23 Turbine Bypass Valve Y
3 Y
3 BWROG Issue 11 of Reference 2.
Position D-24 Condenser Hotwell Level Y
3 Y
3 BWROG Issue 11 of Reference 2.
D-25 SBGTS Fan and Valve Y
2 Key parameters needed to verify proper system Indication operatior.. Provides hold up of noble gases and removal of iodines and particulates prior to releace through the stack.
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W mm TABLE I PROPOSED PARAMETER SET FOR OYSTER CREEK Recommended By NRC BWROG CPUN Parameter Description Y/N Cat Y/N Cat Y/N Cat Justification l
D-26 MSIV Position
~
Y 3
Direct indication of the ability to use plants main heat sink.
It is also an entry condition to E0Ps and automatic scram signal.
Y 3
Indication of heat load on main heat sink.
It D-27 Main Steam Flow would verify that steam is going to condenser vice torus or through a pipe break and is also an automatic MSIV isolation signal.
Y 3
Needed to qualify core spray flow as flow to D-28 Core Spray Isolation Valve Position the reactor vs. through the test line, relief valve or line break.
D-29 CRD Flow Y
3 CRD flow and pressure are required to assess the operability of this system to provide high pressure coolant make up and scram accumulator supply.
D-30 CRD Pressure Y
3 CRD flow and pressure are required to assess (Accumulator Charging) the operability of this system to provide high pressure coolant make up and scram accumulator supply.
D-31 Torus to DW and Rx Y
3 Vacuum breaker position is extremely important Building to Torus to ensuring the torus will perform its steam Vacuum Breaker Position suppression function. Any open vacuum breaker is alarmed in the control with open/ shut indication available in the reactor building.
This is acceptable as is.
UNY
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W TABLE I PROPOSED PARAMETER SET FOR OYSTER CREEK Recommended By NRC BWROG GPUN Parameter Description Y/N Cat Y/N Cat Y/N Cat Justification E-1 Drywell Area Radiation Y
1 Y
1 Y
1 High Range l
l E-2 Reactor Building Area Y
2 N
N See BWROG Issue 12 of Reference 2 and E-3.
Radiation E-3 Reactor and Turbine Y
3 Y
3 Y
3 See BWROG Issue 13.
A combination of installed Building Exposure Rate sensors and portable radiation survey instruments and samplers will be used if post-accident access is necessary.
E-4 Stack Noble Gas Y
2 Y
2 Y
3 The noble gas monitor for the stack effluent Concentration and consists of high quality, commercial grade Flow Rate equipment.
In the event it fails, post-accident monitoring vill be accomplished by manual sampling and laboratory analyses.
The sampling station will be in an outdoor mild environment which makes environmental qualification unnecessary.
E-5 Stack and Turbine Y
3 Y
3 Y
3 Building Particulate and Halogen Concentration E-6 Radiation Exposure Meters -
Deleted by NRC Errata, July, 1981 E-7 Airborn Radiohalogens Y
3 Y
3 Y
3 and Particulate E-8 Plant Environs Radiation Y
3 Y
3 Y
3
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TABLE I PROPOSED PARAMETER SET FOR OYSTER CREEK Recommended By NRC BWROG CPUN P rameter Description Y/N Cat Y/N Cat Y/N Cat Justification E-9 Plant and Environs Y
3 Y
3 Y
3 Radioactivity E-10 Wind Direction Y
3 Y
3 Y
3 E-11 Wind Speed Y
3 Y
3 Y
3 E-12 Estimatation of Y
3 Y
3 Y
3 Atmospheric Stability E-13 Reactor Coolant and Y
3 Y
3 Y
3 Delete sump sample, see BWROG Issue 14.
l Drywell Sump Sample Use torus sample instead.
E-14 Drywell Hydrogen /0xygen Y
3 Y
3 Y
3 and Gamma Spectrum E-15 Turbine Building Noble Y
3 Y
3 Y
3 Gas Concentration 9
%?o o is.
m me e
em W
W m
g rr em W
W m
W W
W W
STATUS OF MINIMJM PARAMETER SET FOR OYSTER CKEK ENVIRONMENTAL SEISMIC QUALITY 0.C.
REG. GUIDE POWER CR TSC/ EOF VARIABLES QUALIFICATION QUALIFICATION ASSURANCE REDUNDANCY RANGE RANGE SUPPLY DISPLAY LOCATION tsee mata A-1 RPV Pressure Comply See Note 3 See Note 1 Comply 0-1500psis N/A See Note 9 Yes (Category 1)
A-2 RPV Water Level Comply See Note 3 See Note 1 Comply
-150' TAF N/A See Note 9 Yes (Category 1)
(See Note 4) +180 TAF A-3 Torus Water Temperature Comply See Note 3 See Note 1 See Note 5 0-400*F N/A See Note 9 Yes (Category 1)
Note 5 A-4 Torus Water Level Comply Comply Comply Comply 10*-360*
N/A Comply Yes (Category 1) inches A-5 brywellPressure Comply Comply Comply Comply 0-260 psia N/A Comply Yes (Category 1)
A-6 Drywell Combustible Comply Comply Comply Comply 0-30%(Hz)
N/A Comply Yes Gas Concentration 0-10%(02)
(H. 0 )
2 3
(Category 1)
%?o.
t o S$
e
M M
M M
M M
M M
MgM M
M M
M M
M M
M STATUS OF MINIDED1 PARAMETER SET FOR OYSTER CREEK ENVIRONMENTAL SEISMIC QUALITY 0.C.
REG. GUIDE POWER CR TSC/ EOF VARIABLES QUALIFICATION QUALIFICATION ASSURANCE REDUNDANCY RANGE RANGE SUPPLY DISPLAY. LOCATION (See Note B-1 Niutron Flux Not Qualifted N/A See Note 1 Comply Comply 10-s 100 See Note 9 Yes (Category 2)
Percent Power B-2 Control Rod Position N/A N/A N/A N/A Comply Full in or N/A Yes (Category 3) not full in B-3 RCS Soluble Boron N/A N/A N/A N/A Comply 0-1000 ppm N/A N/A Concentration (Sample)
(Category 3)
B-4 RPV Water Level
- - - - - - - - - - See A - - - -
Core Support See A-2 See A-2 (Category 1) plate to center line of MSL B-6 RPV Pressure
- - - - - - - - - - See A - - - - ------
15psta-See A-1 See A-1 (Cagegory 1) 1500psig B-7 Drywell Pressure
- - - - - - - - - - See A - - - - -------------------
0 to Design See A-5 See A-5 (Category 1)
Pressure B-8 Drywell Sump Level N/A N/A N/A N/A Do not Bottom to N/A No (Category 3) comply top B-9 Containment Pressure
- - - - - - - - - - See A - - - - ----------------
10psta-See A-5 See A-5 (Category 1)
Design Pressure B-10 Primary Containment Qualified See Note 3 See Note 1 Comply Comply Closed -
See Note 10 Yes Isolation Valve Not Closed Position (Excluding Check Valves)
(Category 1)
?NY
%?om go ao m
l
m M
W W
M h
M M
M EII E E
E M
E E
E W
E STATUS OF HINIMM PARADETER SET FOR OYSTER CREEK l
ENVIRONMENTAL SEISMIC QUALITY 0.C.
REG. GUIDE POWER CR TSC/ EOF VARIABLES QUALIFICATION QUALIFICATION ASSURANCE REDUNDANCY RANGE RANGE SUPPLY DISPLAY LOCATION (Eme unte B-11 Reactor Water Level Comply N/A See Note 1 N/A 0-400*F N/A N/A Yes Reference Leg Temp Catestory 2) i B-12 Torus Pressure
- - - - - - -Instrument with sufficient range does not exist - - - - - - -
N/A N/A Yes l
(Category 2) 2 1
l i
i i
e YN g
b e cm 4
M M
M M
M M
M M,3 m
M M
M M
M W
STATUS OF MINIMUM PARAMETER SET FOR OYSTER CREEK ENVIRONMENTAL SEISMIC QUALITY 0.C.
REG. GUIDC POWER CR TSC/ EOF VARIABLES QUALIFICATION QUALIFICATION ASSURANCE REDUNDANCY RANGE RANGE SUPPLY DISPLAY LOCATION (See Note 11 C-2 Analysis of Primary N/A N/A N/A N/A Comply 10 uCl/M1 to N/A N/A Coolant (Sample) 10 Ct/M1 (Ganina Spectrum)
(Category 3)
'C-4 Drywell Area High Inst. does not exist for this variable IR/h-N/A No 5
Radiation (Category 3) 10 R/hr C-5 Drywell Drain Sumps N/A N/A N/A N/A Do not Bottom to N/A Alarm is Level comply top provided (Category 3) in Radwaste (Identifted and CR Unidentifted Leakage) 0
%?o goa
M M
M M
M M
W,g M
M M
M M
M M
STATUS OF MINIMUM PARAMETER SET FOR OYSTER CREEK ENVIRONMENTAL SEISHIC QUALITY 0.C.
REG. GUIDE POWER CR TSC/ EOF VARIABLES QUALIFICATION QUALIFICATION ASSURANCE REDUNDANCY RANGE RANGE SUPPLY DISPLAY LOCATION fSee Ngit_[1 C-6 Containment Effluent N/A N/A N/A N/A See Note 13 10uCl/cc-N/A Yes Radioactivity-Noble 10-2uC1/cc Gases (Category 3)
C-8 Effluent Radioactivity See f:ote 2 N/A See Note 1 N/A See Note 13 10-s C1/cc-N/A Yes u
Noble Cases 10 uCi/cc 3
(Category 2)
C-9 Rx Bldg. Pressure N/A N/A N/A N/A Comply N/A N/A Yes (Category 3) e
%?o 6o$
D
m M
M M
M M
M M
M TABLE II STATUS OF MINIMD1 PARApfTER SET FOR OYSTER CREEK ENVIRONMENTAL SEISHIC QUALITY 0.C.
REG. GUIDE POWER CR TSC/ EOF VARIABLES QUALIFICATION QUALIFICATION ASSURANCE REDUNDANCY RANGE RANGE SUPPLY DISPLAY LOCATION ISee Mate D-1 Hain Feedwater Flow N/A N/A N/A N/A Comply 0-110% design N/A Yes (Category 3) flow D-2 Condensate Storage N/A N/A N/A N/A 0-50 ft.
Bottom to top N/A Yes Tank Level (Category 3)
D-4 Drywell Atmosphere Qualifted See Note 3 See Note 1 Comply 0-660*F 40*F-Comply Comply Temperature Type T 440*F (Category 2)
D-7 Valve Honitoring System (VHS)-
Vessel Pressure Relief EHRV'ST(5)
Comply See Note 3 See Note 1 N/A Open/
Closed-not N/A Yes (Cat. 2)
Closed closed, or o to 50 psis Code Safety (16)
N/A N/A N/A N/A Open/
closed-not N/A Yes Valves (Cat. 3)
Closed closed, or 0 to 50 psig l
l 2' a' d -
$.* o oM w
s
M M
M M
M M'
gy M
M M
M STATUS DF MINIPSD4 PARAMTER SET FOR DYSTER CREEK ENVIRONMENTAL SEISMIC QUALITY 0.C.
REG. GUIDE POWER CR TSC/ EOF VARIABLES QUALIFICATION OUALIFICATION ASSURANCE REDUNDANCY RANGE RANGE SUPPLY DISPLAY LOCATION fSee unte D-8 Isolation Condenser Comply See Note 3 See Note 1 N/A 0-10 ft.
Top to See Note Tr Yes System Shell-Side Water bottom Level (Category 2)
D-9 Isolation Condenser Comply See Note 3 See Note 1 N/A Comply Open or See Note 10 Yes System valve Position See Note 2 Closed (Category 2)
D-12 Core Spray System Comply See Note 3 See Note 1 N/A See 0-110%
See Note 9 Yes Flow Note 8 design flow (Category 2) 0-14 SLCS Flow N/A N/A N/A N/A Does not 0-110%
N/A Flow /No (Category 3) comply.
design flow Flow Only flow Indication No flow Ind.
D-15 SLCS Storage Tank N/A N/A N/A N/A Comply Bottom to N/A Yes Level top (Category 3)
D-16 Containment Spray Comply See Note 3 See Note'I N/A Comply 0-110%
Comply Yes Flow design flow (Category 2)
D-17 Containment Spray Heat Comply See Note 3 See Note 1 N/A n-500*F 32-350*F Comply Yes Exchanger Outlet Temp.
(Torus Water Side)
(Category 2) e t
$.O O
l Y
c)
M M
M M
M M
gy M
M M
M M
M STATUS OF MINItaM PARAMETER SET FOR OYSTER CDrrr ENVIRONMENTAL SEISMIC QUALITY 0.C.
REG. GUIDE POWER CR TSC/ EOF VARIABLES QUALIFICATION QUALIFICATION ASSURANCE REDUNDANCY RANGE RANGE SUPPLY DISPLAY LOCATION (See Note D-18 Emergency Service Water. N/A N/A N/A N/A 32*F-N/A No Temperature to 200'F Containment Spray Heat Exchangers (Canal Intake Temp.)
(Category 2)
D-19 Emergency Service
- - - - - - - - - - - - - Inst. does not exist - - - - - - - - - - - - - 100%
N/A No Water Flow to design flow Containment Spray Heat Exchangers (Category 2)
D-20 High Radioactivity N/A N/A N/A N/A Comply Top to N/A No Liquid Tank Level bottom Indication (Category 3) in Radwaste CR D-21 Emergency Ventilation Quallfted See Note 3 See Note 1 N/A Open/
Open/
N/A Yes Damper Positon Closed Closed (Category 2)
D-22 Status of Standby Power N/A N/A N/A N/A Comply Voltages N/A Yes and Other Energy Currents Sources Important to Pressures Safety
{
(Category 3)
I D-23 Turbine Bypass Valve N/A N/A N/A N/A Open/Close N/A N/A Yes Prsition (Category 3) i i
r i
i l
$$Y 5.* o wo$
ta
E U
E E
E E
E E
T STATUS OF HINIMUM PARAMETER SET FOR OYSTER CREEK I
ENVIRONHENTAL SEISHIC QUALITY 0.C.
REG. GUIDE POWER CR TSC/ EOF VARIABLES QUALIFICATION QUALIFICATION ASSURANCE REDUNDANCY RANGE RANGE SUPPLY DISPLAY LOCATION (See Note 11 I D-24 Condenser Hotwell N/A N/A N/A N/A 0-60" N/A N/A Yes l
Level (Category 3)
D-25 SIGTS Fan and Valve Qualifted See Note 3 See Note 1 N/A On/Off N/A N/A Yes Indication (Fans)
(Category 2)
Open/ Closed (Valves) i l D-25 HSIV Position N/A N/A N/A N/A Comply N/A N/A Yes (Cateoory 3)
?
8 f-27H.3tnSteamFlow D
N/A N/A N/A N/A 0-4x10 N/A N/A Yes (Category 3) lbm/hr l D-28 Cere Spray Isolation N/A N/A N/A N/A Open/Close N/A N/A Yes
' Valve Position (Category 3)
, D-29 CRD Flow N/A N/A N/A N/A 0-100gpm N/A N/A Yes (Category 3)
D-30 CRD Pressure N/A N/A N/A N/A 0-2000psig N/A N/A Yes l
( Accumulator Charging) i (Category 3)
?
lD-31TorustoDWandRx N/A N/A N/A N/A Open/Close N/A N/A Yes Bldg. to Torus Vacuum (Alarm) l Breaker Position (Alarm)
(Category 3) i i
i a
$*O o$
g M
m M
M M
M M
M M
M g,,p W
W M
M M
M M
M iTATUS OF MINIMB4 PARAMETER SET FOR OYSTER rarrr ENVIRONMENTAL SEISMIC QUALITY 0.C.
REG. GUIDE POWER CR TSC/ EOF VARIABLES QUALIFICATION QUALIFICATION ASSURANCE REDUNDANCY RANGE RANGE SUPPLY DISPLAY LOCATION fSee Note 7
E-1 Drywell Area Radiation Inst. does not exist for this variable.
IR/hr-10 No High Range R/hr (Category 1)
E-3 Reactor and Turbine N/A N/A N/A N/A Comply 10~3R/hr N/A Yes Building Exposure Note 12 to 10*R/hr Rate (Category 3)
E-4 Stack Noble Gas See Note 2 N/A See Note 1 N/A Cogly 10-suct/cc-N/A No Note 7 10*uct/cc-Concentration and 0-110% went Flow Rate design flow (Category 3)
E-5 Stack and Turbine N/A N/A N/A N/A Sample 10-8uct/cc-N/A No Building Particulate 10auct/cc and Halogen Concentration 0-110% vent (Category 3) design flow E-7 Airborne Radiohalogens N/A N/A N/A N/A Comply 10*'uct/cc-N/A N/A and Particulates 10-8uct/cc Portable Sampling (Category 3)
E-3 Plant and Environs N/A N/A N/A N/A Comply 10-3R/hr-N/A N/A Radiation (Portable 10*R/hr Instrumentation)
Photons (Category 3) 10-3R/hr 10'R/hr BETA radiation and low energy Photons e
$.* o woa
M M
M M
M M
M M
M M
M M
M M
M M
M M
M j
TABLE II STATUS OF HINIMD4 PARAMETER SET FOR OYSTER corrr ENVIRONMENTAL SEISMIC QUALITY 0.C.
REG. GUIDE POWER CR TSC/ EOF VARIABLES QUALIFICATION QUALIFICATION ASSURANCE REDUNDANCY RANGE RANGE SUPPLY DISPLAY LOCATION fSee Note E-9 Plant and Environs N/A N/A N/A N/A Comply Multi-channel N/A N/A Radioactivity (Portable Gamuna-Ray Instrumentation)
Spectrometer (Category 3)
E-10 Wind Direction N/A N/A N/A N/A Comply 0-360*
N/A Yes (Category 3)
E-ll Wind Speed N/A N/A N/A N/A Comply 0-30mps N/A Yes (Category 3)
(67 mph)
E-12 Estimation of N/A N/A N/A N/A Comply
-5'C-N/A Yes Atmospheric Stability 10*C (Category 3)
Accuracy per 50 meters E-13 Reactor Coolant N/A N/A N/A N/A Comply Grab Sample N/A N/A cnd Drywell Sunp Sample (Category 3)
E-14 Drywell Hz. 02 N/A N/A N/A N/A Congly Grab Sample N/A N/A and Gansna Spectrum (Category 3)
C-15 Turbine Building Noble N/A N/A N/A N/A Comply N/A N/A Gas (Category 3)
$+O wO$
e
d TR 028 Rev. O Page 3 7-NOTES FOR TABLE II
~
I 1)
GPU Nuclear has a documented quality assurance plan which, as a minimum, satisfies the requirements of 10CFR50, Appendix B.
GPU Nuclear's quality assurance plan has been reviewed and approved by the NRC.
i Any instrumentation which has to be replaced because of technical inadequacies (performance or environmental qualification) will be procurred per the requirements of GPU Nuclear's quality assurance plan, which may or may not include the quality assurance requirements specified in USNRC Regulatory Guide 1.97, Revision 2.
I The instruments in compliance with technical and environmental qualification requirements but lacking quality assurance documentation shall be considered on a case by case basis and may be used for compliance with R.G. 1.97 quality assurance requirements.
Lack of I
quality assurance documentation for existing instrumentation will not per se require any modification to be performed at Oyster Creek.
2)
Equipment located in a Mild Environment 10CFR50.49(3)(111) - Hild environment equipment is not included in the scope.
- Comments on the proposed rule (3) scope - The commission has determined that no additional requirements are necessary for mild I
environment equipment.
Requalification of Electrical Equipment 10CFR50.49(K) - Not required to requalify equipment previously qualified to the DOR guidelines. OCNGS equipment was qualified to D0R guidelines; therefore, R.G. 1.89 qualification requirements are not I
applicable.
1 3)
The seismic qualification of current post-accident monitoring I
instrumentation complies with the Oyster Creek licensing basis as stated in the FSAR.
Equipment upgraded to satisfy range and environmental qualification criteria will be evaluated.for seismic considerations.
I Where documentation for seismic qualification of existing equipment does l
not exist, the equipment will be considered on a case by case basis.
GPUN will finalize a program of seismic equi.pment qualification dependent upon resolution of Unresolved Safety Issue A-46, Seismic Qualification of I
Equipment in Nuclear Power Plants.
I I
I
TR 028 Rev. O Page 38 (Notes for Taole II)
(Continued)
I 4)
The reactor water level system consists of four independent systems to monitor the entire range of reactor level. Three systems have redundant indication in the control room and the fourth one is a single channel system. Qualified water level instruments indicate water level from five I
inches below the bottom of the fuel to five inches below the isolation condenser steam lines. This is the OC limiting condition for high reactor water level control.
5)
The torus water temperature is monitored by four different thermocouples locations in the toros. Each channel is recorded in the control room.
All four channels are recorded on the same recorder.
6)
The drywell atmosphere temperature is monitored at five different locations in the drywell. Each channel is recorded in the control room.
I All five channels are recorded on the same recorder.
7)
GPUN takes exception to the high range requirement of 104 uci/cc at Oyster Creek.
8)
The range required for core spray system flow is in compliance with R.G.
1.97 requirements for system II and not in compliance for system I.
9)
Both instrument cnannels powered by the same diesel generator with provisions to transfer to other diesel generator.
- 10) Tne indication for the valve positions is powered from the power feeds that power the control circuits for the respective valves.
- 11) Those R.G.1.97 parameters which are to be available to the TSC/E0F are the same as the parameter selection for the Oyster Creek SPOS, which includes all Type "A" variables. These variables will be available to I
the TSC/ EOF via the Oyster Creek SPDS and/or plant computer.
- 12) Worst case maximum ranges of type E-3 variables will be addressed on a 4
case-by-case basis rather than using an arbitrary range of 10 R/hr.
- 13) Cal {brationinformationthatconfirmstherangeof10-6 to I
10- uCi/cc is not available. This monitor is original plant equipment whose principal function is to actuate the Standby Gas Treatment System.
I lI I
I
M M
M M
M M
M M
Stgg M
M M
M M
M M
M M
ACTIONS REQUIRED TO SATISFY R.G. 1.97 REQUIREMENTS FOR OCNGS MINIMUM PARAMETER SET AREAS OF NON-COMPLIANCE SYSTEM CR VARIABLE CAT. CODES EQ REDN RANGE DSPL REMARKS A-3 Torus Water 1
3,4 X
Plan to install. Notes 5, 6, 7 Temperature Required per Nureg 0783. Redundant and separate channels will be provided.
O
$.O WO$
4
TABLE III ACTIONS REQUIRED TO SATISFY R.G. 1.97 REQUIREMENTS FOR OCNGS MINIMUM PARAMETER SET AREAS OF NON-COMPLIANCE SYSTEM CR VARIABLE CAT. CODES EQ REDN RANGE DSPL REMARKS l-B-1 Neutron Monitoring 2 X
Plan to install. Working with GE on proposed wide range neutron monitoring system that will use environmentally and seismically qualified components. See Notes 5, 8 B-3 RCS Boron 3 1 Grab Sample.
B-8' Drywell Sump Level 3 3 X
X X
Do not plan to upgrade - See Note 1 B-12 Torus Pressure 2
X X
Plan to upgrade. Planned for upcoming 11R outage.
%fo AO$
b Z
s
W W
M M
M M
M M
M M
M M
M M
M M
M M
M TABLE III ACTIONS REQUIRED TO SATISFY R.G. 1.97 REQUIREMENTS FOR OCNGS MINIMUM PARAMETER SET AREAS OF NON-COMPLIANCE SYSTEM CR VARIABLE CAT. CODES EQ REDN RANGE DSPL REMARKS l
C-2 Analysis of 3 2 Grab Sample Reactor Coolant C-4 Drywell Area High 1 3,16 X
X X
X Inst. does not exist.
Plan to install to Radiation meet NUREG-0737 requirements. Planned for E-1 upcoming 11R outage.
C-5 Drywell Sump 3 3 X
X See Note 1 and B-8 and Equipment Drain Tank Level t
$ak
%.* o oM.
M M
M M
M M
M M
M M
M M
M M
M M
M M
M TABLE III ACTIONS REQUIRED TO SATISFY R.G. 1.97 REQUIREMENTS FOR OCNGS MINIMUM PARAMETER SET
~
AREAS OF NON-COMPLIANCE SYSTEM CR VARIABLE CAT. CODES EQ REDN RANGE DSPL REMARKS D-12 Core Spray System 2 7 X
Plan to upgrade the system that 1
Flow does not meet range requirements.
Planned for upcomit g 11R outage.
D-14 SLCS Flow 3 1 X
Do not plan to upgrade - See Issue 9 of BWROG D-19 ESW Flow 2
X X
X Plan to install.
Instrument does not exist at Oyster Creek.
See Note 5 l
$$N
$O
{O$
P
M M
M M
M M
M M
M M
M M
M M
M M
M M
M TABLE.III ACTIONS REQUIRED TO SATISFY R.G. 1.97 REQUIREMENTS FOR OCNGS MINIMUM PARAMETER SET AREAS OF NON-COMPLIANCE SYSTEM CR VARIABLE CAT. CODES EQ REDN RANGE DSPL REMARKS D-20 liigh Radioactivity 3 10 X
Do not plan to upgrade. See Note 4 Tank Level t
$$Y
%?o goM w
M M
M M
M M
M M
M M
M M
M M
M M
M M
M TABLE III ACTIONS REQUIRED TO SATISFY R.G. 1.97 REQUIREMENTS FOR OCNGS MINIMUM PARAMETER SET AREAS OF NON-COMPLIANCE SYSTEM CR VARIABLE CAT. CODES EQ REDN RANGE DSPL REMARKS E-1 Drywell Radiation 1 16 X
X X
X Plan to install.
Planned for upcoming 11R High Range outage.
E-k Stack Noble Gas 3 18 Stack noble gas concentration from scintilla-Concentration and tion monitors is continuously indicated and re-Flow Rate corded in control room. Additionally, sampling capability will be added to allow gas concen-tration to be analyzed on-site.
See Note 5 E-5 Stack and Turbine 3 18 Sample Bldg. Particulate and Halogen Concentration E-7 Airborne Radio-3 19 Portable halogens and Particulate E-8 Plant Environs 3 19 Portable Inst.
Radiation E-9 Plant and Environs 3 19 Portable Radiation f
$$Y
%5o os a
A
M M
M M
M M
M M
gg g M
M M
M M
M M
M M
ACTIONS REQUIRED TO SATISFY R.G. 1.97 REQUIREMENTS FOR OCNGS MINIMUM PARAMETER SET AREAS OF NON-COMPLIANCE SYSTEM CR l
VARIABLE CAT. CODES EQ REDN RANGE DSPL REMARKS l
l E-13 Reactor Coolant 3 21 See Issue 14 of BWROG to take sample from and Drywell Sump Torus instead of Drywell Sump Sample E-14 Drywell Hydrogen 3 21 Sample Oxygen and Canna Spectrum s
e ENY
%?o oe g
TR 028 Rev. O Page @
NOTES FOR TABLE III 1.
There is no indication of actual level in either the Drywell Sump or Drywell Equipment Drain Tank.
H1 level alarms are annunciated in the New Radwaste Control Room along with flow integrators. The Drywell Sump i
fill rate is indicated and alarmed in the Main Control Room (i.e.
unidentified leakage) and pump run time integrator indication is available in the 480V room in the Turbine Building.
These indications are adequate for determination of leak rate.
2.
An upgrade of the valve monitoring system was implemented to environmentally qualify this system.
3.
Actual control room level indication is 0-10 feet vice R.G. 1.97 recommended span of 0-12 feet.
Since maximum allowed operating level is I
7.7 feet by procedure 307, 10 feet is an adequate upper limit to assure proper isolation condenser function.
4.
Information is displayed in Radwaste Control Room; may use phone or I
radio to transfer this information to Main Control Room.
5.
The modifications recommended in Table III will be incorporated into the I
Integrated Living Schedule for Oyster Creek. Commitments regarding scheduling will be incorporated into the GPUN Integrated Living Schedule l
which is currently being negotiated with the NRC.
6.
GPU Nuclear will environmentally qualify those components necessary to satisfy the requirements of Reference 5 per the requirements of 10CFR50.49, Environmental Qualification of Electric Equipment.
7.
E.Q. non-compliance were addressed prfor to November 30, 1985.
I 8.
GPU Nuclear will take exception to qualifying the Average Power Range Monitors. GPUN will qualify the SRM & IRMs as Category (1) with the proposed wide range monitoring system and will have an upper power level I
limit of 20%.
The.APRMs will not be qualified because E0Ps ATHS mitigation steps require the operator to take certain actions if power is greater than 2% or cannot be determined.
Therefore, knowing the exact power level (above 2%) has no impact on operator action.
I
'I
'I
- I l
5
TR 028 Rev. O SYSTEM CODES
~
I 1.
Reactivity Control 2.
Core Cooling I
3.
Reactor Coolant System Integrity 4.
Containment Integrity 5.
Condensate and Feedwater 6.
Main Steam System 7.
Safety Systems 8.
Cooling Water System 10.
Radwaste Systems 11.
Ventilation Systems 12.
Power Supplies 13.
Reactor Coolant System (Recirculation) 14.
RBCCW 15.
Service Water System 16.
Containment Radiation 17.
Air Radiation 18.
Airborne Radioactive Material Release from Flant 19.
Environ Radiation and Radioactivity 20.
Meteorology 21.
Accident Sampling Capability On-Site 22.
CRD I
I I
TR 028 Revt 0 Page 48 I
5 I
I I
I APPENDI M I
BWR OWNERS GROUP POSITION ON NRC REGULATORY GUIDE 1.97, REVISION 2 I
I I
I lI l
I I
I I
I
'I
N 1
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BWR OWNERS GROUP
'h
,,,,,,,_,,_...-,.e-'*
- g h
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's in 13 llg
\\g July 1982 lI is
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to' I
I I
I I
I DISCLAI1ER
[
The positions reported herein are con-sensus responses to the requirements of NRC Regulatory Guide 1.97, Revision i'
2, December 1980, and as such do not necessarily express in every particu,
lar the several positions of the par-ticipating utilities.
I I
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I I
I I
I I
~
I
0 CONTENTS Page 1.
INTRODt.*CTION 1
i Sponsoring Utilities 3
2.
Bk'R O'4;ERS GROUP POSITION STATEMENT 5
General Position Statement 5
Implementation of Design Changes 9
3.
PROPOSED TYPE A VARIABLES 10 Variables Identified as Type A 11 Potential Type A Variables 12 4.
PLANT VARIABLES'FOR ACCIDENT MONITORING 14 Type A Variables 16 Type B Variables 17 Type C Variables 18 I
Type _ D Variables 20 Type E Variables 23 5.
SUPPLEMENTARY ANALYSES 25 (Issues 1 - 14) 6.
CONCLUSIONS 58 I
APPENDIX A:
THERMAL CONDUCTIVITY OF IN-CORE THERMOCOUPLES IN BOILING WAT'l REACTORS 63 APPENDIX B:
BWR VARIABLES (TABS.E 1, RG 1.97) 96 APPENDIX C:
ABBREVIATIONS 107 I
I I
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I
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1.
INTRODUCTION Following the publication of Regulatory Guide 1.97, Revision 2, by the U. S. Nuclear Regulatory Commission in December 1980, the B'4R Owners Group (BWROG) established a committee to review and evaluate the regulatory positions described therein.I The intent of RG 1.97 is to ensure that all light-water-cooled nuclear power plants are instrumented as necessary to measure certain prescribed variables ant' syste=s during and after an accident.
The principal purpose of the Bk' ROC RG.l.97 Committee was to evaluate the safety effects and the feasibil-icy of implementing the proposed regulatory positions--particu-larly those defined in Table 1, RG 1.97.
Twenty-four (2!.) domestic and two (2) forei;;n utilities supported the Conmittee's efforts.
Seventeen (17) of these 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.
Meetings of the committee commenced in April 1982 and con-tinued through July 1982.
The sponsoring utilities and their l
representatives who served on the BWROG RG 1.97 Comittee 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-l and contractor-generated data related to RG 1.97 requirements, and to the formulation of recommendations based on the commit-l tee's reviews and analyses.
Besides conducting its own studies, the committee contracted other analytical work to Roy l
& Associates, Inc.; 5. Levy, Inc.; and the General Electric Company.
I As used throughout this report, RG 1.97 refers to RG 1.97, Revision 2, December 1980.
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0 A sum.ary statenent of the Omers Group position relative to RG 1.97 requirements is presented in Sec. 2; some proposed Type A variables, which are unspecified in RC 1.97, are defined in Sec. 3; a detailed Owers'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-cinent 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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I Sponsoring Utilities The sponsoring utilities of the BWROC RC 1.97 Committee, their assigned contacts or committee members, and consultants are identified below.
Committee Membership (f.ames of the working members of the committee are in italics.)
Boston Edison Company RICH ST. ONGE; s*ERRY XITE::-! SKI Cincinnati Gas & Electric Company
.: LLIA:' :3C?ER; ROCER TH0::CY Cleveland Electric Illuminating Company RA.' :A:l'.'??
Detroit Edison Company
,e Georgia Power Company
~"'
(ICC chairman) (from Southern Company Services Inc.)
Gulf States Utility Company MATEE RAHMAN; FHILLI?S ?CRTIR Iowa Electric Light and Power Company
?C5. EF (YCC:) 3ALA3 (Chairman)
Jersey Central Power & Light Company JAA'IJ CEARSCS; PAUL PROCACCI; ABDUL R. BAIG g
Long Island Lighting Company JC.W: ?:3F??
I Mississippi Power & Light Company SAM HOBBS; RUE:.l. 350k'l.
Northeast Utilities A'ARIC 3LA:lCAFLOR Northern Indiana Public Service Company ADAM SHAHBAZI g
Pennsylvania Power & Light Company JOHll BARTOS; DAN CARDIN0BE l
l Philadelphia Electric Company ATS 30frTRS; RICK OGITIS Power Authority of the State of New York G. RAUGARA:; J. STREET i
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Public Service Electric and Gas Company RICHARD O'CONNELL Tennessee Valley Authority KATHRYS ASHLEY: PC.:f?T :{LIf;;I.:
tiashington Public Power Supply System ARUN JOSHI; ii:lD E!!;TI::GTCN Supporting Utilities I
Carolina Power & Light Company Centrales Nucleares Del Norte (S.A.)
Cor.monwealth Edison Company Ente, Nazionale per l' Energia Elettrica Illinois Power Cor.pany Nebraska Public Power District Niagara !!ahawk Power Corporation Ncrthern State.4.ow r Company I
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EPRI/SSAC C. Dan tiilkinson, program manager (replaced by Robert Kubik for report coordination in Feb. 1982)
Consultants General Electric Company S. Levy, Inc.
Roy and Associates 8
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1 2.
BWR OWNERS GROUP POSITION STATEMENT I5 The Bb' ROC position on NRC Regulatory Guide 1.97, Revision 2, is presented in the following statement.
The statement reflects the intent of the regulatory positions set forth in RC 1.97 but includes alternatives and deviations that relate 3
to specific instrumentation requirements and to the particulars of their implementation.
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-by-variable basis is presented in Sec. 4, and supplementary data are provided in Sec. 5 and in the appendices.
General Position Statement l
BhTOG concurs with the intent of RG 1.97, Revision 2.
The intent of the regulatory guide is to ensure that necessary and sufficient instrumentation exists at each nuclear power station for assessing plant and environmental conditions during and following an accident, as required by 10 CFR Part 50, 1
Appendix A and General Design Criteria 13, 19, and 64.
Imple-mentation of RG 1.97 requirements is recommended except in those instances in which deviations from the letter of the guide are justified technically and when they can be imple-Y mented without disrupting the general intent of the Guide.
In assessing RG 1.97, the Owners Group has dratTt upon information contained in several applicable documents, such 5
as ANS 4.5, NL' REG /CR-2100, and the Bb' ROC Emergency Procedures 1
Guidelines, and on data derived from other analyscs and stud-ies.
The Owners Group believes that literal compliance with 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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could adversely affeet operator judgment under certain condi-
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For example, research by S. Levy, Inc., shows that core tions.
thermocouples will provide ambiguous inf ormation tb B'iR opera-The Owners Group intends to foll'ow the criteria used by tors.
the NRC for establishing Category 1, 2, and 3 instruments, should be noted that Category 2 instruments could although it vary widely between utilities, because of various plant-unique features.
The following Owners Group compliance statement is appli-cable to the regulatory positions defined in RG 1.97, Revision 2 (the paragraph numbers cited correspond to those in RG 1.97).
1.
Acc iden t-Stonitorin2 Instrumentation I
B'..1 Ow ers Group concurs with this defini-
"ar.
1.1:
The
'd..s Owner. Creup concurs with this defini-
a r Th6 Instru.nents used for accident monitoring to Par. 1.3:
the provisions of RC 1.97 shall have the proper sensitivity, meet the con-range, transient response, and, accuracy to ensure that trol room operator is able to perform his role in bringing the plant to, and maintaining it in, a safe shutdown condition and in assessing actual or possible releases of radioactive, mate-rial follawing an accident.
Each utility shall assess its f
I plant accident-monitoring instrumentation system.
Accident-monitoring instruments that are required to be I
environmentally qualified will be qualified to the requirement The seismic of NUREG-0588 and Memorandum and Order CLI-80-21.
I qualification of instruments will be based on individual assessments performed by each utility.
Each plant will comply with the quality assurance require-ments, using its approved quality assurance program, as described in the FSAR or elsewhere.
This would ensure that accident-monitoring instruments comply with the applicable requirements of Title 10 CFR 50, Appendix B.
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Each plant program for periodic checking, testing, cali-brating, and calibration verification of accident-conitoring g
instrument channels (RC 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 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 independent channel that
=
monitors a different variable bearing a known relationship to the variable being monitored.
3 2.
Providin; the operator,; f.. ti.c e ap s f 1 I t;. of icr-turbin; :.ae reasured variable te dc ts rmine which channel has failed b: observing the response en 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 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 commitments in the FSAR, or elsewhere.
Il Par. 1.3.2:
The Bh'R 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 StJR Owners Group concurs with the regu-latory position for Category 3 inscrumentation.
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
.I clarify the intent of RC 1.97, which specified that these I
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I condi-instruments be easily discerned for use during accident tions (see Issue 1, Sec. 3).
Par. 1.5:
II,e Sh?. (Aners Group concurs with the regula-tory position taken in this section, except as modified by Par. 1.3 above.
Par. 1.6:
It is the position of Bb' ROC that in terms of I
accident monitoring at a BWR facility, Table 1 of RG 1.97 does represent a minimum number of variables and does not neces-not sarily represent correct variable ranges or instrumentation categories.
Each S'..~4 f acility shall assess its compliance with the intent of PC 1.97 by establish!ng a list of accident-monitoring variables applicable te its om plant.
The classification of i n.,
- n.. a t u t w n u : s to -c;.s r.
t.
Variabic-..u Cate;ory 1,
. ', o: 3 4.all i.s 1: sonM :aace,c i t.. 'h intent and methcd used I
in
. 97.
The.BbT. Umcrs Group position on the implementation of B
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 Instrumentation The Bb'R Ccers Group position stated in Par. 1.3 above is applicable to the Type D and E variables described in RC 1.97.
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Par. 2.1:
The BkT Owners Group concurs with these definittons.
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Par. 2.2: The BWR Owners Group concurs with this regula-tory position.
I Par. 2.3: The Bb'R Owners Group concurs with this regula-tory position.
t 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 above is anplicable to this regulatory position.
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i E-I implementation of Design Changes i
The B'.*R Owners Group recor: mends that the impler.entation into each plant design of additional design changes, as required by RG 1.97, be integrated with the implementation of other con-trol room design improvements.
A relationship exists between identifying accident-monitoring variables, developing operating procedures, reviewing control room human factors engineering, and incorporating design changes into the plant.
SbT,0G believes that an integrated approach l
precludes the use of a specific implementation date for all BWR plants.
In this regard, the Owners Croup reco m. ends that imple-nentation dates should be scheduled on a plant-by-plant basis.
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I 3.
PROPOSED TYPE A VARIABLES E
I Regulatory Cuide 1.97, Revision 2, designates all Type A variables as plant-specific, thereby definin;; 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 j
I 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 speeffied safety functions." Variables associated with con-Linpac action.4 that u;. be ident.:id in written procedures cru _1ci.id ed : v.? this definition of primary information.
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'. 3 part of their review of E 1.97, the EUR 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-fied 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 sunmary 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 (EPG's).
Although all of I
the operator actions specified below may not be required to
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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, HPCI, RCIC, and RWCU:
(2) l initiate isolation condenser; (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 Water Level Operater action:
Festore and maintain RPV water level.
Safety function:
Core cooling Variable A3.
Suooression 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 integrity and (2) maintain reactor coolant system integrity.
Variable A4.
Suppression Pool b'ater Level l
Operator action:
Maintain suppression pool water level l
within normal operating limits:
(1) transfer RCIC suction l
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 l'
limit.
Safety function:
Maintain containment integrity.
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E Variable'AS.
"r:.ecli h ssure t'perator action:. Control primary containment pressure V'
I by an.s of several systuns, such as centainment pressure con-trol systems, suppression pool sprays, drywell sprays.
I Safety function:
(l) 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 includ.ed in Sec. 4.)
Variable 1.
Condensato Storage Tank Level Operator action:
Transfer HPCI or RCIC suction or both f rem LM te suppre:,3ic reci.
Di:, ussic::
'm -:s reco=cadcd autcr..atic suction trans-fer for HPC: and RCIC.
This variable is not a Type A variable if the automatic suction transfer is not installed.
Variable 2.
Emergenev Diesel Generator (EDG) Load Operator action:
Control loading of the EDC'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.
R2 actor Buildine Flood Level y
I Initiate pump-back of sump to suppression N
Operator action:
pool.
I Uater can accumulate in the reactor building Discussion:
The during long-term cooling with any postulated leakage.
flood-level indication would alert the operator to a problem, f
but this indication is an aid to and not the accomplishment of a safety function.
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Variable 4 Drvuell Tennerature Operator action:
Initiate sprays, reactor water level compensation.
Discussion:
This variable may be needed for reactor-water-level compensation.
Note: Although the EPC's mention dryvell temperature, the dryvell pressure is the key variable for con-tainment integrity; dryvell 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 ms; be uscd to approximate the suppression pool pressure.
Varia':lo 6.
On" gen or Hydrocen Concentration Operator action:
If containment atr.osphere approaches the combustible limits, initiate combustible gas control systems.
Oxygen for inerted and hydrogen for non-inerted containments.
Safety function:
Maintain containc:ent integrity.
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I PLANT VARIABLES FOR ACCIDENT MONITORING 4.
H B'.. HOC position. on the implementation of the variables listed in Table 1 of RC 1.97 and on the assignment of design and qualification criteria for the instrumentation proposed for is summarized in the tabulation that follows.
their measurement I
In brief, the measurement of the five variable types provides the following kinds of information to plant operators I
during and after an accident:
(1) Type A--primary information, 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) 3-3--infor:::: ion about the op. ration of individual safety systems; and O) iyis L--information about the magnitude of the reluasc of radieactive 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 I
most stringent requirements; Categories 2 and 3 impose pro-gressively less stringent requirements.
The categories are also related (in RC 1.97) to " key variables." Key variables are defined dif ferently for the o
different variable types. For Type B and Type C variables,,
the key variables are those variables that most directly Odi ct: thc c:c r.r!isi:: int of auf ty fw:cticn; instrumenta-tion for these key variables is designated Category 1.
Key variables that are Type D variables are defined as chose vari-ables that most directly *ndica:a N.' operation of a safety ayste; instrumentation for these key variables is usually I
Category 2.
And key variables that are Type E variables are defined as those variables that most directly indicate the rcZcaw of radica:tds cateria?; instrumentation for these key I
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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 I
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 )
Sk7.0G's position is sho'.t for each variable and for its instrumentation design criteria ~and category.
(The letters u3 g
and 37 preceding the category numbers identify the Owners Group I
and RG 1.97, respectively.)
In general, there are three kinds of responses or're* commendations:
(1) implement the variable and required instrumentation in accord'ance with the regulatory I
position stated in Table 1, RG 1.97 (2) implement, with quali-fying exceptions or revisions; and (3) do not implement.
I 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.
Ilote tca~ refs Nn:cs te rk i:t ir. Sec. 5 cre r ie l'y citing the l3.nc nw4ers that appear in the upper corner of the pa ges in :'ec. 3.
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Type A Variables The following Type A variables are recommended by the Owners Group (OC) for inclusion in RG 1.97 as type A.
(See Sec. 3.)
A1.
Reactor pressure (OG Category 1)
B RECOSS!ENDATION:
Implement.
See B6, C4, and C9.
I A2.
Coolant level in reactor (OG Category 1)
REC 0!O1E!. ATION:
Implement.
See B4 T
I Suppression pool water temperature (OC Category 1)
A3.
RECO:0IENDATION:
Implement.
See D6.
A4.
Suppression pool wa:er level (OG Category 1)
RECO:CIENDATICN :
Implement.
See C7 and D5.
(0 r tc;ory 1)
'5.
Drpeell pressure a
J CCC'!!E:.DA~ !J: :
imp ler.un t.
.ype ' fer plants tci tiwu t autostartin.: dr.wll sprar.
See C7, 39, C8, C10, and D'.
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I Type B Variables R ze'.i h y 7:r r:i Bl.
Neutron Flux (OG Category 2; RG Category 1)
I RECOSDENDATION:
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)
RECOBCiENDATION:
Implement B3.
RCS Soluble Boron Concentration (sample) (OG Category 3; RG Category 3)
RECO>SENDATION:
Implement Core Cco?63J B4.
Coolant Level in Reactor (OG Category 1; RG Category 1)
I FCC&O;ENDATION:
Do not imple.cnt.
Fee A3, C3, and j
Issue 3.
35.
SLT Core Themocouples (RG Category 1)
RECOS2ENDATION:
Do not implement.
See C3 and Appendix A.
- in::ining ?ta:ro." C:cla-t Systen D::cgrity I
B6.
RCS Pressure (OG Category 1; RG Category 1)
RECO?cENDATION:
Implement.
See A2, C4, C9, and Issue 3.
B7.
Dr>vell Pressure (OG Category 1; RG Category 1)
I RECOFDtENDATION:
Implement.
See A6, B9, CS, C10, and D4.
B8.
Drymell Sump Level (OG Category 3; RG Category 1) g E
REC 01CIENDATION:
Implement as Category 3.
See C6 and Issue 4.
Maintaining Conrain. men: Integri:y B9.
Primary Containment Pressure (OG Category 1; RG Category 1)
REC 010ENDATION:
Implement.
See A6, B7, C8, C10, and D4.
B10. Primary Containment Isolation Valve Position (excluding check valves) (OG Category 1; RG Category 1)
I RECOBSENDATION:
Implement.
Redundant indication is not required on each redundant isolation valve.
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Type C Variables
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C1.
Radioactivity Concentration or Radiation Level in Circu-I lating Primary Coolant (RG Category 1)
RECOSCIENDATION:
Do not imple=ent.
See issue 5.
C2.
Analysis of Primary Coolant (ga=ma spectrum) (OG Category y
3; RG Category 3)
REC 050tENDATION:
Implement C3.
BWK Core Thermocouples (RG Category 1)
RECOSCIENDATION:
Do not implement.
See B5 and Appendix A.
? :.ar "c. '.'w : : i n..:.': w.=:. e.. ;;u :.
C4.
RCS Pressure (OG Category 1: RC Category 1)
R.Tm""fNDATION:
' :'lement.
Fee i2, 34 and C9.
L.'.
ri:-r Nn t:innent Arca : scia:ie- (v? Category 3; hC Ca:egory 3)
RLC0:CENDAT IO:..
Implement.
See El.
Co.
Drywell Drain Sumps Level (identified and unidentified leakage) (OG Category 3: RC Category 1)
REC 0!DIENDATION:
Implement as Category 3.
See B8 and i
Issue 4.
C7.
Suppression Pool Water Level (OG Category 1; RG Category 1)
I REC 050!ENDATION:
Implement.
See A5 and DS.
g CS.
Drywell Pressure (OG Category 1; RG Category 1)
RECO>DIENDATION:
Implement.
See A6, B7, 59, C10, and D4.
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C9.
RCS Pressure (OG Category 1; RG Category 1)
RECOSS!ENDATION:
Implement.
See A2, B6, and C4.
l C10. Primary Containment Pressure (OG Category 1; RG Category 1) g REC 0501ENDATION:
Implement.
See A6, B7, B9, C8, and D4 BE Cll. Containment and Dryvell H: Concentration (0G Category 1; RG Category 1) i RECOSS!ENDATION:
Implement I
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C12. Containment and Drywell Oxygen Concentration (for inerted containment plants) (OG Category 1; RC Category 1)
RECO?O ENDATIO5:
Implement.
See Al.
Radioactivity--Soble Cases (from Effluent Cl3. Containment identified release points including Standby Cas Treatment Systen Vent) (OG Category 3; RC Category 3)
I REC 0501ENDATION:
Implement C14. Radiation Exposure Rate (inside buildings or areas, e.g.,
I auxiliary building, fuel handling building, secondary which are in direct contact with primary containment, containment where penetrations and hatches are located)
,I (RG Category 2)
See E2, E3, and REC 010!ENDATION: Do not implement.
Issue 6.
Radioactivity--Noble Cases (from buildings as
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C15. Effluent indicated above) (OG Category 2; RG Category 2)
RELO:2tE!'D.\\ TION :
Impicment y
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I Ill Type D Variables
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Dl.
Main Feedwater Flow (OG Category 3; RG Category 3)
REC 0F0!ENDATION:
Implement D2.
ndensate Storage Tank Level (OG Category 3; RG' Category REC 0!CIENDATION:
Impi.ement
?ri =.~j Conrain :ent-Rcla:ci Sy :n p
D3.
Suppression Spray Flow (RG Category 2)
I RECO:C!ENDATION:
Do not implement.
See Issue 7.
D4.
Dr Nell Pressure (0G Category 2; RG Category 2)
I REC 0!CIENDATION:
Implement.
See A6, 37, B9, C8, and C10.
al '..'ater Level (OC Category 2; RG Category r
"5.
Su n; ire s s Dn I
% 0.'CIENJ.ir10.N :
I: plement.
See A5 and C7.
D6.
Suppression Pool t.'ater Temperature (0G Category 2; I
RG Category 2) l RECOSDIENDATION:
Implement.
l Both local and bulk temperature.
See A4.
D7.
Drywell At=usphere Temperature (OG Category 2; RG Cate-gory 2)
REC 0tDLENDATION:
Implement.
See Issue 8.
D8.
Dr>vell Spray Flow (RG Category 2).
RECO>DIENDATION :
Do not implement.
See Issue 7.
R
- .'r'n ?:ax~ Sp.'tt-D9.
Main Steamline Isolation Valves' Leakage Control System l
l Pressure (OG Category 2; RG Category 2)
REC 0!ciENDATION:
Implement if system is part of plant lg
' 3 design.
D10. Primary System Safety Relief Valve Position, Including ADS or Flow Through or Pressure in Valve Lines (OG Category 2; RG Category 2)
RECOM>iENDATION:
Implement l
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'I fafety Syn:cma Dil. Isolation Condenser System Shell-Side Water Level (OG Category 2; RG Category 2)
I RECOBOENDATION:
Implement if system is part of plant design.
D12. Isolation Condenser System Valve Position (OG Category 2; RG Category 2)
REColeENDATION:
Implement if system is part of plant design.
D13. RCIC Flow (OG Category 2; RG Category 2)
REC 0F0ENDATION:
Implement.
See Issue 9.
D14. HPCI Flow (OG Category 2; RC Category 2)
RECOBOENDATION:
Implement.
See Issue 9.
D15. Core Spray System Flow (OG Category 2; RG Category 2) l REC 0!OENDATION:
Implement.
See Issue 9.
D16. LPCI System Flow (0G Category 2; RG Category 2)
REC 0!DENDATION:
Implement.
See Issue 9.
D17. SLCS Flow (OG Category 3; RG Category 2)
REC 010ENDATION:
Implement as Category 3.
Await ATWS resolution.
See Issue 9.
D18. SLCS Storage Tank Level (OG Category 3; RG Category 2)
REC 010!ENDATION:
Implement as Category 3.
Avait ATWS
- ,I resolution.
See Issue 10.
?esidual Heat Removat (RHR) Systems D19. RHR System Flow (OG Category 2; RG Category 2)
I RECOBOENDATION:
Implement D20. RHR Heat Exchanger Outlet Temperature (OG Category 2; RG Category 2)
REC 010ENDATION:
Implement Cooling Water System D21. Cnoling Water Temperature to ESF System Components (OG Category 2; RG Category 2)
RECOM)fENDATION:
Interpret as main system flow and implement.
a 21
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D22. Cooling Uater Flow to ESF System Ceeponents (OG Category 2; RC Cate;;ory 2)
RECOSDtENDATION:
Interpret as main system fJow and implement.
Radu:::c Sya:u 3 D23. High Radioactivity Liquid Tank Level (OG Category 3; I
RG Category 3)
RECOMBENDATION:
Implement
'/er.0;;a im: Qc:r c D24. Emergency Ventilation Damper Position (OG Category 2;.
I RC Category 2)
REC 0!O!ENDATION:
Interpret as meaning dampers actuated under accident conditions and whose failure could result in radioactive discharge to the enviro. ment. Control g
I room damper position should be indic..ted.
Implement.
5 E
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D25. Status of ::tandby Power and Other Energy Sources Important to Safety (hydraulic, pneumatic) (OG Category 2; RG Category 2)
RECO>D!ENDATION :
Implement; on-site sources only.
(!!cto:
The adii:icn of the l0lLouir; D-:yp2 0:.riables is I
rec:?~ ended by B'30G; see Issue it, Sec. 5. )
D26. Turbine Bypass Valve Position (OG Category 3)
I g
RECO)0!ENDATION: Add to RG 1.97.
See Issue 11.
D27. Condenser Hotwell Level (OG Category 3)
I RECO)DENDATION: Add to RG 1.97.
See Issue 11.
D2S. Cendenser Vacuum (0G Category 3)
RECO:DIENDATION: 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.
D30. Primary Loop Recirculation Flow (OG Category 3)
RECO>DiENDATION:
Add to RG 1.97.
See Issue 11.
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Type E Variables Containmen: Radia ion El.
Primary Containment Area Radiation--High Range (OG Category 1; RG Category 1)
RECO.YENDATION:
Implement in accordance with NUPEG-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)
REC 010ENDATION:
Do not implement for Mark I and II con-tainments.
Irrplement for !! ark III contain=ents.
See Cl4, lI E3, and Issue 12.
Arca Radia ion it E3.
Radiation Exposure Race (inside buildings or areas where access is required to service equipment important to lI safety) (OG Category 3; RG Category'2)
REC 0!DENDATION:
Implement as Category 3, using existing instrumentation.
See C14 E2, and Issue 13.
Airborne Radioactive Materials Released from ?:an:
E4.
Noble Cases and Vent Flow Rate (OG Category 2; RG Cate-I gory 2)
RECOBCfENDATION:
Implement II E5.
Particulates and Halogens (OG Category 3; RG Category 3)
RECOBOENDATION:
Implement Dwirons Radiation and Radioactivity E6.
Radiation Exposure Meters (continuous indication at fixed locations)
'I RECO.TENDATION: Deleted.
See NRC errata of July 1981.
1 E7.
Airborne Radiohalogens and Particulates (portable sampling with on-site analysis capability) (OG Category 3; RC Cate-gory 3)
REC 0101ENDATION:
Implement E8.
Plant Environs Radiation (portable instrumentation)
(OG Category 3; RG Category 3)
REC 0bcENDATION:
Implement (portable equipment)
E9.
Plant and Environs Radioactivity (portable instrumenta-tion) (OG Category 3; RG Category 3)
I REC 030tENDATION:
Implement (portable equipment) 23
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.:tC Cate;' sty 3; RC Cate;or' 3)
Clo. Wind Direction i
- iECO.sDIEND.iile:::
1eplutent Ell. Wind Speed (OG Category 3; RG Ca:egory 3)
REC 050iENDATION:
Implement B
I E12. Estimation of Atmospheric Stability (OG Category 3; y
RG Category 3)
RECO.'CIENDATIO:::
Implement I
-; >c i y :." : ~ 'e ~ lar.& ? !. ' n.'
- s..;"y -:a C:: s. ~ i t. Or.-F : - )
j l
E13. Prin.ary Coolant and Sunp (0C Category 3--Primary Coolant E'
I 5
only; RG Category 3)
RECOSD!ENDATION:
Implement Primary Coolant.
Do not impiccient Surp.
See Issue 14.
I
.4. iantainnent *i. (OC Category 3; RC C:.te;cre 3) i.ED W.:.?.il:i.:
Ir., icnen t I
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SUPPLEMENTARY ANALYSES 13 These supplementary analyses support positions cited in Sec. 2 (Issue 1) and Sec. 4 (Issues 2-14).
Contents Issue 1.
Inscrument Identification Issue 2.
Variable B1 Issue 3.
Trend Recording j
Issue 4 Variables B8 and C6 Issue 5.
Variable Cl 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 326-030 Issue 12. Variable E2 Issue 13. Variable E3 Issue 14. Variable E13 18~
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ISSUE 1.
INSTRU M ENT ID ENTIFIC ATION WS E
Issue Definition I
D 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 g
that they are intended for use under accident conditions."
II" I
a Discussion The objective of this regulatory position is the achieve-ment of good human factors engineering in the presentation of I
information to the control room operator. This objective is best achieved by evaluating current practices and procedures aids that provide for identifying instruments in a manner that 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 1
shutdown, operational training, and procedures.
I Conclusion E
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 l3 and,resentason e, inf _ uen m he c _ o1 _ e,er _.
This position is taken to clarify the intent of RG 1.97, which specifies that these instruments be easily discerned I
l for use during accident conditions.
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ISSUE 2.
VARIABLE B1 l
1 Bl:
Neut.ron Flux issue 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 ft.11 power (SRM, APRM).
The stated purpose is " Function detection; accomplishment of mitigation."
E Discussion The lower end of the specified range, 10-6 percent full power, is intended to allow detection of an approach to.criti-8 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 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
- boron, 4.
A range of leak rates up to 20 gpm was considered j
(see Table 1).
l 27 l
l
i s
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 = 10-8 percent of full power. The choice of 5 = 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 I
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 he to increase the power from 5 = 10-8 percent to 5 = 10-7 percent, and 10 hr to increase it from 5 = 10-7 percent to 5 = 10-6 percent.
The reactor is suberitical and the neutron level is given Neutron level = S = 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 I
1.0.
Thus, the calculation model used the above equation to I
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.
l The increase in reactivity toward criticality can be turned around by actuating the SLCS. It is assumed that oper-ati;gprocedures provide for refilling the SLCS tenh soon after its coruction. A second actuation of the SLCS would cause a decrease in reactivity because of the high concentration of boron in the injected SLCS fluid relative to that in the leak-ing fluid (nominally 400 ppm). The sensitivity of the detector must allow adequate time for the operator to act.
Ten minutes I
1 3
2e
u s
is considered sufficient time for operator action for accident prevention and mitigation.
Table 1 shows that the detector sensitivity (i.e., lower range) requirement is a function of leak rate and therefore of reactivity-addition rate.
On the basis of a 20-gpm leak rate, Table 1 shows that a detector that is on scale within 3 decades of the shutdown power would allow 0.18 hr (10.8 min) for operator action before reactor power increased another decade.
A total of 0.36 hr (21.6 min) would be available for operator action from the time the indicator comes on scale to the time reactor power reaches 0.5 percent of full power. An alarm would be provided to warn the operator when the neutron 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 large that it could not in reality go undetected by the oper-ator. Moreover, reactivity-addition caused by this gradual I
boron depletion is unlikely, since boron concentration is sampled and measured periodically. Again, the improbable 20-gpm leak rate was used only to obtain a mechanistic and conservative approach for selection of instrument sensitivity.
An absolute criterion for the lower range must include consideration of the neutron source level.
The use of the neutron level 100 days after shutdown is conservative. There is high probability that conditions would be stable and con-trollable 2 days 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
, I will vary with fuel design, fuel history, and shutdown con-trol strength. Measurements of shutdown neutron flux (with all rods inserted) at two BWR reactors show readings of 30 to 80 counts /sec (1000 counts /sec corresponds to 10-8 of full 29
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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
,I i
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 2015 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 101S would be rendered inoperable.
I Further, the operator can always actuate the SLCS on loss of instrumentation.
Although some upgrading of the current NMS may be appro-I 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 meets the intent of RG 1.97.
Four alternative design approaches to meeting the neutron flux requirements of RG 1.97 have been identified. All four 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 a suitable alternative, based on its own design evaluation.
The principal features of the four alternatives are presented below.
5 gg
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Alternative 1.
The first alternative provides for upgrading two or more of the source-range monitors (SM1's).
The upgrading includes the connecting cable inside the drywell and the power source for the SMt drives. At least two SM!'s would have dual roles of accident instrumentation and normal start-up; these two SUf's would be withdrawn a lesser dis-tance from the core than the SMi in the current design.
It I
is estimated that in its fully withdrawri position, the cur-rent SUt will detect about 10-3 or 10-5 percent of full power.
This sensitivity can be increased by using a withdrawn posi-I tion that is less than the present 2-2.5 ft from the core.
A withdrawn position that produces 10 percent depletion in 5 years was used as a guide to the r ::.W.e allowed burn-up of the sensor. This position below the core would give the SMt a detection capability of about 2 < 10-7 percent of full power.
The SM! drives need not be upgraded, because the upgraded detector system would be adequate, even if the drive did not move the SMt detector.
(An upgraded power source for the l g drives improves the probability of insertion.)
The success of this alternative--which uses the four SMi's for normal start-up--depends on a design modification to accommodate the I
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 detent 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 supplier in order to estimate schedules, cost, and overall effect of the upgrading. Whereas the first alternative uses upgraded cables I
and power supply (which are commercially available), this I
1 31
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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 SDf-type detectors as I
stationary detectors that are positioned close enough (as dis-
,l 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 (IM!) tubes or in two local-power range-monitor (LPD!) tubes.
It may be feasible to put five detectors in the LPWI tube or, if space is g
4 limited. the bottom detector of the LPD! string could be replaced with the " accident" detecter, k*ith this approach the four movable SD:'s would continue te be available for normal functions.
'I Alternative 4.
In the final alternative, out-of-core detectors, which are being qualified for use in pressurized I
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 (N11S) make this alternative an attractive one.
The key question is whether these out-of-core detectors can i
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-t Based on calculations of neutron flux made for a BWR quate.
at full power (see Fig. 1) and on current detector design l
Other practices, the out-of-core detector may be feasible.
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effects, such as attenuation by water that is at a lower tem-a perature (than the full-power operating temperature) and by boron in the water, need to be considered.
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Conclusion is A range f rom 5 = 10-5 percent of full power (within 3 decades of the neutron flux level 100 days after shutdown) to 100 percent of full power is recommended. An alarm is also i
recommended that would alert the operator of a rise in neutron flux.
It is concluded that a Category 2 classification is responsive to the intent of RG 1.97, as are the four alterna-l tives, provided that the design program resolves the specific (l
design concerns identified in the Discussion.
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F, TABLE 1.
RELATIVE NEUTRON FLUX VERSUS TIMEa E
v i
Leakage rate, gpm (ramp rate, c/ min)
Percent 1(0.03) 5(0.15) 20(0.60)
F I
g of power E
o E.
6 E
O I
5x 10-8
-555 500
-111 100
-27.75 25 5x 10-7
-55 50
-11 10
-2.75 2.5 5x 10-6
-5 5
-1 1
-0.25 0.25 5x 10-5 0
0 0
5 = 10-'
O.8 0.8 0.36 0.36 0.18 0.18 5 = 10- 3 l 1.33 0.53 l
0.51 0.15 l
0.25 0.07 i
5 10 -'
1.59 0.26 l
0.62 0.11 l
0.31 0.06 l 5 = 10-1 1.80 0.21 0.72 0.10 0.36 0.05 5 = 10 1.89 0.09 0.80 0.08 0.40 0.04 5
- Shutdown flux = 5 = 10-8 percent of power.
b E = total number of hours; a = hours for neutron flux to increase by one decade.
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ISSUE 3.
TREND RECORDING I
I issue Definition I
5 The purpose of addressing Issue 3 is to determine which variables set forth in RG 1.97 require trend recording.
Discussion Regulatory Guide 1.97, par. 1.3.2f, states the general requirement for trend recort (ng as follows:
"Where direct and i cediate trend or transient information is essential for operator information or action, the recording should be con-tinuously available for dedicated recorders." Using the B'a~d Owners Group Emergency Procedures Guidelines (EPG's) as a basis, the only trended variables rcquired for operator action are reactor water level and reactor vessel pressure.
f Conclusion On a generic basis, only reactor water level (variable B4) and reactor vessel pressure (variable B6) recuire trend recording; however, other variables may be necessary on a plant-specific basis.
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ISSUE 4.
VARIABLES 88 AND C6 3
B8:
Drywell Sump Level C6:
Drywell Drain Sumps Level issue 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 drywell equipment and floor-drain tank levels.
Category 1 instrumentation indicates that the variable being monitored is a key variable.
In RG 1.97, a key variable is defined as that single variable (or minimue. number of variables) that most directly indicates the accomplishment of a safety function.
The following discussion supports the BWR Owners Group alternative position that drywell sump level and drywell drain-sumps levels 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-fied leakage; the other is the floor drain sump, which collects unidentified leakage.
Although the level of the drain sumps can be a direct indi-cation of breach of the reactor coolant system pressure boundary, the indication is not unambiguous, because there is water in those sumps during normal operation. There is other instru-mentation required by RG 1.97 that would indicate leakage in the drywell:
1.
Drywell pressure--variable B7, Category 1 2.
Drywell temperature--variable D7, Category 2 37
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i 3.
Primary containment area radiation--variable CS, Category 3 g
E The drywell-sump level signal neither automatically ini-tiates safety-related systems nor alerts the operator to the I
need to take safety-related actions.
Both sumps have level detectors that provide only the following nonsafety indications:
1.
Continuous level indication (some plants) f 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 su=p systems are I
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 I
Based on the above considerations, the B'a Owners Group believes that the dryvell-sump level and drywell-drain-sump level instrumentation should be classified as Category 3, "high-quality off-the-shelf instrumentation."
lI l
38
a I'I ISSUE 5.
VARIABLE C 1 B
C1:
Radioactivity Concentration or Radiation Level in Circulating Primary Coolant I
Issue Definition Regulatory Guide 1.97 specifies that the status of the fuel cladding be monitored during and after an accident.
The specified variable to accomplish this monitoring is variable I
Cl--radioactivity concentration or radiation level in circulat-ing primary coolant. The range is given as "l/2 Tech Spec 1.imit to 100 times Tech Spec Limit, R/hr."
In Table 1 of RG 1.97, instrumentation for measuring variable Cl 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 c.ladding.
Discussion The usefulness of the information obtained by monitoring the radioactivity concentration or radiation level in the cir-culating primary coolant, in terms of helping the operator in his efforts to prevent and mitigate accidents, has not been i
substantiated.
The critical actions that must be taken to I.
prevent and mitigate a gross breach of fuel cladding are (1) shut down the reactor and (2) maintain water level.
Monitoring variable C1, as directed in 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 radioactive material are being challenged" and " identification of degraded conditions and their magnitude, so the operator can l'
take actions that are available to mitigate the consequences."
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Additional operator actions to mitigate the consequences of fuel barriers being challenged, other than those based on Type A and B variables, have not been identified.
Regulatory Guide 1.97 specifies measurement of the radio-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 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 m'onitored.
is The subject of concern in the RG 1.97 requirement assumed to be an isolated SSSS that is shutdown.
This assu=p-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 Further, the post-accident sampling system (PASS) will provide an accurate status of coolant radioactivity, and hence cladding I
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 I
p The designation of instrumentation for measuring variable Cl should be Category 3, because no planned operator actions j
are identified and no operator actions are anticipated based p
on this variable serving as the key variable.
Er.isting Cate-gory 3 instrumentation is adequate for monitoring fuel cladding f
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status.
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1 ISSUE 6.
VARIABLE C 14 I
C14:
Radiation Exposure Rate 1
lssue Definition I
Variable C14 is defined in Table 1 of RG 1.97 as follows:
" Radiation exposure rate (inside buildings or areas, e.g.,
I auxiliary building, fuel handling building, secondary contain-ment), which are in direct contact with primary containment wherc 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 I
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 l
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 l*
noble gas effluent monitors.
1.
l
' g Conclusion
)05
]
Using radiation exposure rate monitors to detect primary containment breach is neither feasible nor necessary. Other 41
N E!
g means of breach detectica 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.
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- L.1 aI 1I ISSUE 7.
VARIABLES D3 AND D8 D3:
Suppression Spray Flow DS: Dryvell Spray Flow lssue Definition I
Regulatory Guide 1.07 specifies flow measurements of I
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 I
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 I
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 RER system flow element is used for flow indication in most designs.
Some plants have I
a flow element in the branch line to the sprays. The suppres-l sion chamber spray operates in parallel with the drywell spray l
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 i
1 43
O M'
I Il effectiveness of these flows can be verified by pressure and temperature changes of the drywell and the suppression chamber.
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 I
and suppression chamber without the use of a dedicated flow-measuring instrument.
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F ISSUE 8.
VARIABLE D7 D7: Drywell Atmosphere Temperature issue Definition Regulatory Guide specifies drywell atmosphere tempurature (variable D7, Category 2) as one of the key variables in 1
monitoring individual safety systems. The temperature range is specified as 40*F to 440'F.
Discussion The evaluation of this issue addressed requirements that I
call for direct operator action based on variable D7, that is, temperature and the associated variable of pressure. The BkA 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 pri=ary item of concern is the cable inside the drywell.
Conclusion Bk'ROG recommends implementation of variable D7 require-ments as specified in RG 1.97.
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o ISSUE 9.
VARIABLES D13-D17 E
I D13:
RCIC Flow D14:
HPCI Flow g
D15:
Core Spray System Flow 37 I
D16:
LPCI System Flow D17:
SLCS Flow issue Definition Regulatory Cuide 1.97 specifies flow measurements of the I
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 saf ety ' 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 l
The RCIC, HPCI, and CS systems 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).
jI Further, the valve in the test 14 e closes automatically when the emergency system is actuated, thereby ensuring that indi-cated flow is not being diverted by the test line.
Proper l
valve position can be verified by a direct indication of valve position.
i Although the LPCI has several branch lines located downstream of each flow-measuring element, each of those
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lines is normally closed.
Proper valve position can be veri-fied by a direct indication of valve positidn.
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 u
devices were not provided for this system.
The pump-discharge header pressure, which is indicated in the control room, vill indicate SLC pump operation.
Besides the discharge header pressure observation, the operator can verify the proper functioning of the SLCS by monitoring the following:
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-rent)
W 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-i ables other than the flow.
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ISSUE 10.
VARI ABLE D18 D18:
SLCS Storage Tank Level issue Definition 5
I Regulatory Guide 1.97 lists standby liquid-control system (SLCS) storage-tank level as a Type D variable with Category 2 I
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
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indicated by the SLC cank level.
Additionally, the operator -
is required to trip the SLC pumps before a low SLC cank 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:
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The current design basis for the SLCS assumes a need g
for an alternative method of reactivity control without a con-cur ent 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
- hat the system has an importance to safety that is less than 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 RG 1.97, it is unnecessary to apply a full quality-assurance program to this instrumentation.
I Based on a graded approach to safety, this variable is more appropriately considered a Category 3 variable.
Conclusion II SLCS storage-cank-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 shotild be reevaluated to ensure adequacy.
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5 ISSUE 11.
VARIABLES D26-D30 I
B l
D26: Turbine Bypass Valre Position D27: Condenser Hotweli Level g
g lg D28:
Condenser Vacuum y
D29:
Condenser Cooling Water Flow D30:
Primary Loop Recirculation j
Issue Definition
- I B
Regulatory Guide 1.97 states that "The plant designer should select variables and information display channels l
required by his design to enable the control room personnel to ascertain the operating status of each individual safety y
l system and other sy' stems important to safety to that extent necessary to determine if each system is operating or can be placed in operation.
The purpose of this analysis was to determine whether certain other D-type variables should be I
added to Table 1, RG 1.97.
Discussion 1
I 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 NUREG/CR-2100 (Boiling Water Reactor Stattis Monitoring during Accident Conditions, Apr. 1981). That report and a companion report, NUREG/CR-1440 (Light Water Reactor 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.
,g 5
These two reports were reviewed in determining whether any variables should be added to the RG 1.97 list.
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l The NUREC 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 cperator is most likely to be confronted and on those accident conditions that result in the most serious consequences, should the oper-I ator fail to accomplish his required tasks.
These studies used probabilistic event trees and the sequences of the Reactor Safety Study (L.' ASH 1400) and similar studies.
The events in I
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
tree defines a series of key plant states that could evolve as the accident progresses and as the operator attempts to respond.
l Thus the operator's informational needs are linked to these plant states.
NUREC/CR-2100 is a Bh*R evaluation undertaken to address appropriate operator actions, the information needed to take those actions, and the instrumentation necessary--and suffi-cient-to provide the required information.
I The sequences evaluated were 1.
Anticipated transient followed by loss of decay-heat removal l
2.
Anticipated transients without scram (ATVS) 3.
Anticipated transient together with failure of HPCI, RCIC, and low-pressure ECCS 4
Large loss of coolant accident (LOCA) with failure of emergency core-cooling systems 5.
Small LOCA with failure of emergency core-cooling systems The RG 1.97 list is based on accidents that result in an isolated NSSS.
The NUREG documents considered accidents that could be prevented or mitigated by using water inventory and the heat sink in the turbine plant.
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f Conclusion Five of the 15 variables identified in the NUREG, but not l
in RG 1.97, are recorcended as Type D, Category 3 additions to the RG 1.97 list.
Four of these variables are in the turbine plant:
the turbine bypass valve position, condenser hotwell level, condenser vacuum, and condenser cooling water flow.
These variables provide a primary measure of the status I
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 recoe= ended.
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ISSUE 12.
VARIABLE E2 E2:
Reacrer Building or Secondary Containment Radiation 3
lssue Definition I
Regulatory Guide 1.97-specifies that " Reactor building i
or secondary containment area radiation" (variable E2) should be monitored ovet 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 Catesory 1.
Discussion.
As discussed in the variable Cl4 position statement (Issue 6), Secondary Containment Area Radiation is an inap-propriate parameter to use to detect ot assess primary con-tainment leakage.
However, for the Mark III containment, the reactor building is essentially part of the primary contain-ment ar.d it is appropriate to monitor that building volume as specified in RG 1.97.
Conclusion It is the position of BL'ROG that' the specified reactor l
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.
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ISSUE 13.
VARIABLE E3 E3:
Radiation Exposure Ratt issue Definition I
E 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 i=portant to safety) be monitored over the range of 10-1 to 10" R/hr for detection and for long-of significant releases, for release assessment, term surveillance.
Discussion I
In general, access is not required to any area of the L
secondary containment in order to service equipment important to safety in a post-accident situation.
If and when accessi-L bility is reestablished in the long term, it vill be done by a combination of portable radiation survey instruments and post-I 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 I
It is BWROG's position that unless plant-specific design I
I.
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-l i
tors.
That is, this parameter should be reclassified as I
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n
'!I Category 3 with a lower range to be selected on a plant-g specific basis.
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I ISSUE 14.
VARIABLE E13 I
E13:
Primary Coolant and Sump I
E lssue Definition Regulatory Guide 1.97 requires installation of the capa-I bility for obtaining grab samples (variable E13) of the con-tainment sump, ECCS pump-room sumps, and other similar auxi-11ary building sumps for the purpose of release esessment, verification, and analysis.
Discussion I
I take into The need for sampling a particular sump must in which it its location and the design of the plant account For all accidents in which radioactive material is installed.
would be in the primary containment sump of a BWR Mark I or this sump will be isolated and will over-Mark II containment, 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 I
as suggested in RC 1.97 only for those designs in assessment, which potentially radioactive water can be pumped out of a For designs in controlled area to an area such as radwaste.
is not allowed on a high-radiation or an which sump pump-out 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
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portions of RG 1.97 provides a much better measurement for these, purposes.
Conclusion 1.
A suppression-pool sample can be used as an alterna-tive to a primary containment-sump sample for plants with Mark I or II containments.
2.
The analysis of ECCS pump-room sumps and other similar auxiliary building sumps is a consideration only if the water is pumped out of the reactor building (e.g., pumped to radwaste).
5 For designs in which sump pump-out is not allowed on a receipt of an accident signal, or in which the water is pumped to the suppression pool, analysis is not necessary.
Provisions for sump sampling and analysis should be in accordance with'each utility's response to NUREC-0737.
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5 6.
CONCLUSIONS The BWR Owners Group RC 1.97 Committee completed an extensive analysis of the regulatory positions proposed in NRC Regulatory Guide 1.97, Revision 2.
The principal goal of the committee was to formulate the position of the BWR Owners Group relative to RG 1.97 requirements.
Toward that end, the committee developed--on the basis of stu' dies con-e ducted by its own representatives and its contractors--a series of positions with respect to interpreting and imple-menting the various provisions of RG 1.97.
The Owners Group concurs with the intent of RG 1.97, which is to ensure that each Bh'R facility 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 RC 1.97, except in those instances when deviations from the RG 1.97 positions are indicated, are desirable, are in accord with the intent of RG 1.97, and are technically justifiable.
The exceptions noted by the Owners Group are generally derived from the incompatibility of an RG 1.97 requirement with the intent of RG 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 from a safety point of view; or from the availa-bility of more effective or more practical ways of achieving a particular monitoring activity.
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SLI - 8121 December 1981 APPENDIX A THERMAL ANALYSES OF IN-CORE THERMOCOUPLES IN BOILING WATER REACTORS (S. Levy, incorporated) t J. C. Gillis g
J. E. Hench 5
E. A. Adams J. E. Eddleman M. A. Beckett
.I I
- s i-Prepared for the BWR Owners Group By 18 S. Levy, Incorporated 1999 S. Bascom Ave., Suite 725 Campbell, California 95008 I
g e3
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ADstract l
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 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 response of thermocouples to core heatup. The thermocouples were assumed I
to be located in the in-core guide tubes, and are heated primarily by ra-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 delay of at least 10 minutes between the start of core uncovery and the time wnen the thermocouple reads 450F a:.ove saturation. It is also probable that operation of relief valves during a small break LOCA would interfere with the thermocouples operation and could render them useless.
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a Summary ar.d Conclusions.
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 5
top of tne 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 thermocouples be located in the thimbles wh'ich 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 j
these thermocouples will not show a temperature 450F above saturation until at least 13 ninutes after the core has started to uncover.
II We have also reviewed a calculation by the staff of the Nuclear Regulatory Commission (NRC) of the response of thermocouples in the in-core thimbles.
The NRC analysis concludes that the thermocouple 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 tae convective cooling effect of boil-off 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.
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FIGURE 1 I
THEPJ10 COUPLE MOUGTED IN THIMBLE AMONG CHANNELS Section 1 Heat Transfar Anai sis of In-Core Thermocouples 1.
f 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 MC that in-core thermocouples could be used to detect core uncovery by showing high temperatures whenever superheated steau appears. The merits of this idea for Pressurized Water Reactors (PWRs) are being debateo elseunere, only SWRs will be considered here.
1 8
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Physical Description of the Thermacouoles Mounted in Flux Monitor Thimbles After inspection of tne BWR cesign, it hs 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 tne physical situation is shown in Figure 1.
The fuel rods are surrounded by V]
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 thermocouples mounted in the thirr-bles have centered on their time of response during a small break LOCA. In that situatiori the core is initially covered with water and the reactor has (j
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 cegin to heat up.
Heat then flows outward to tre channel wall, to the thimble, and finally t'o the thermocouple.
III Heat Transfer Analysis of the Response Characteristics of In-Core Thermocouples in Small Breaks The response char.eteristics of thermocouples mounted in the thimbles used for in-core neutrcn monitors was investigated by writing planar ene.gy balance equations for:
i) the rods (the fuel bundle was broken into four subgroups) i ii) the channel iii) the thimble iv) the thermocouple.
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E 2
Also, a her.t balance equation was written to calculate the tei..parature o' steam as it rises through the uncovered portion of the core.
i'.1 ether, I
thet,e equ ati on*.i formed a self-consistent set which dete rmir.e s tne L
temperature-time history of the thermocouple.
A.
Energy balance on the thermocouple.
The thermocouple was asssumed to receive heat by radiation from the thimbli l
wall.
This is the only method of heat transfer assumed - convection
- j through the air in the thimble was ignored. The energy equation was then
E B
dTe
_1 _
a (T c4 Tth )
(I) 4 t
t dt MC R3 where I
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1-Ec (21 R3,1-E th
+
t Ec Ac A tc Ath E h t
t t
B.
Energy Balance on the Thimble.
I The thimble receives energy by radiation from the channel wall, and loses energy by natural convection to the steam between the channels, and by
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radiation to the thermocouple. The steam between the channels is assumed to be at the saturation temperature.
The energy balance can be writter:
thh+EnAth(T3at - Tth)
-Th, C (Tc (Tc I
a a
t
-T dTth t
.._ C R2 Mth dt q
where l
I "C
I I ~ "th '
(4)
R2
+
+
=
A Ath Ath E th
, c Ec i
A relative evaluation of R2 and R3 showed that R3 is two orders of magnituce larger than R. Since the temperature differences are about the same, the 2
l thimble's heat loss to the thermocouple is neglected.
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C.
Energy Balance on the Cliannel Wall.
The channel wall receives energy by radiation from the fuel rods, and lose; it both by conve: tion to the steam flow and by rad.ition to the thermocouple thimble. As disc:2ssed below in more detail, the rod bundle i; divided into 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 factors (F j) discussed i.1 i
section E.
The sum of the radiant transfer from all the rod grocos to th3 channel is:
11 Orad = A
- Ilc(Tr1 -Tc)+F2c(Tr2 -Tg) 4 c
+F3c(Tr3-Tc)+F4c(Tr4 -Tc ),
(5)
It 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.
II O
F(T
-T ) + n(TSAT-T )
cony st c c
I The energy balance equation for the channel is then:
dTc 1
Ae Fge(Tr1 -Tg)+F2c(Tr2 -Tc) c dt (mc)c N.)
+F3c(Tr3 -Tc)+F4c(Tr4 -Tc) t 1
+ ii A l
-T )
- nc(TSATc)J A
pc ST c
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FIGURE 2 DIVISION CF R005 INTO R00 GROUPS FOR I
RADIATION MODEL D.
Energy Br. lance 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 'che heat up of the rods by decay heat, the transfer of energy among the rod groups (and channel wall) by ra-Radiation from the diation, and heat transfer by convection to the steam.
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 tile form 4
$3 g(Tri -Trj f.i. =
1 00ECAY-hF A
-(mc)r <
j=1 dt n g
+ ii A (Tri-Tst )
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70
The decay heat is determined from the ViS decay heat curve for times between 150 and 10,000 seconds, ano the initial power before scram.
5 00ecay(s,t)
= (Oo)
.130ft-tscram).203
,f(3)
(g) 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:
cos (4,4[
f(x)
= 1.387
(;o) 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 surface, the inside channel surface and the outside channel i
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.
r.5 R
0 e.8
- F (s/r)
(U) 0 0.022 P Nuir The Reynolds number in this calculation is defined as:
Re, 4 Gr.Aflow, 4 Gst Arjow
- st P pst ad (12)
Equation (12) was modified for the paral'el rod geometry by the factor F (s/r) which depends, as shown by Refere:ce 1 on the ratio of rod pit:h to rod radius (s/r). The resulting heat transfer coefficients ranged b.1-tween 10 and 17 Stu/hr ft2 of.
71
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When the Reynolds number is below 2300, a constant Nusselt number, give, for rod bundles as a function of (s/r) by Sparrow, Loeffler and F abbard is used. (Ref 3)
C. f(s/r)
(13)
Nu
=
For the channel wall, the Nusselt number for turbulent flow is calculated from equation 11, without the F (s/r) correction.
Similarly, for laminar flow, equation (13) is used for the channel without the F (s/r) correction factor.
Radiation heat transfer betwEen the rod groups is calculated using grey body f actors, which account for the fact that some of the radiation incident on a surf ace.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 Qjj = Aj F;j o [Tj4 - Tj )
(IL)
These f actors were developed from the emissivities of the surf aces (as-sumed to be.6) anc the geometric view factors for rod to rod and rod to I
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 I
neighbors, and that the fraction of rediation emitted outside the 25 nearest neighbor rods (or channel surface) which arrived at a given rot after multiple reflections was negligible.
l F.
Calculation of the Steam iemperature and Flow Rate 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 fuci assemblies.
The boil-off rate, for a partially-sabmerged fuel' bundle, was calculated by assuming that all the decay heat from tM portion of the fuel rods below the waterline goes into producing steam. The water I
level is determined by integrating the boil-off rate as the calculation proceeds.
s 72
When the steam leaves the water's surf ace, its temperature will be at saturation. As the sted;n rises through the rod bunc.a it will be heated by contact with the rods. Thus, steam temperature is both a function of tirre 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)
=
GA ow p f
C dx This integration is done numerically using a core divideo into twelve zones. The rod teaperatures are obtained from a heat balance on ai: average roc' in each of the twelve zones.
l 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 i.. Thimble The calculations described above was performed for the foliewing starting conditions:
i 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 'takage.
Constant Reactor pressure of 1000 psia.
8x8 fuel i
I g
n
o 0
I g
These conditions were chosen so that our calculation would correspond to one performed by the fGC which will be discussed later.
In the IGC calculations, it was assumed that the operator would not consider the thermocouple signiI 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 Dy about + 200F, so the value of 450F is reasonable. The fact that the operator has to keep tre I
change of saturation temperature with reactor pressure in mind is another complicating f actor which will make successful use of the thermocouples less likely.
Figure 3 shows the calculated temperature response for three axial ther-This mocouple positions, tne top of the core,11 f t and 10 f t. e.levations.
graph shows tnat the response times are on the order of 13 minutes. Fig-ure 3 also shows tnat tne optimum location for the thermocouple is near to the top cf the cor,3, although the response time (measured f roh. the start of core uncovery) is not a strong function of position.
After examining L
Figure 3 it was decided to use a thermocouple location i ft from the top of t.1e core for all further ca'culations.
I More detailed information on the response of the system with the thermo-j couple located one foot below the top of the core is shcwn in Figure 4.
I The plane of the thermocouple is uncove"ed about 150 sec after the top of thu core uncovers. The rods begin to heat up adiabatically, but later the rate temprirature rise drops off due to convection and radiation losse3.
As the foam level in the bundles drops, and more and more of the core below the plane of the thermocouple is uncovered, the temperature of the steam passing the thermocouple location rises. The channel wall, thimble am thermocouple all rise in temperature, and the thermocouple is 450F abo /e saturation 780 seconds (13 minutes) after the start of core uncovery.
Figure 4 also shows that the time lag between the thimble and thermocouple temperatures is extremely small, thus direct contact between the thermo-i couple and thimble will not significantly reduce the time delay.
s 1
a b
.m-s o
ggg g'
FIGURE 3 TilERiiOC00PLE TEt4PERATURE TitiE lilSTORY AT TilREE AXIAL P051T10fl5 i
1 50 -
P I
40 0F ABOVE i
SATURATI0tl 30 I
f I
2 ft from Top of Core e
i 20 _
10 -
I ft from Top of Core e
ib0 2b0 3b0 400 5' 0 60'0 70 0 860 0
/
U s
Tit 4E, SECO.'lDS AFTER START OF UtlC0VERY
ll
(,
M.
g M_
s do g
R l
e M
r e
l e
m n
b t
a n
m n
e a i e
t h
h C C
S C
T /
g i
T g
M 0
1(
0 8
M M
0 0
7 M
M e
C s
E i
S E
R R
0 m
O p
Y u
0 R
n M
C m
6 E
E e
F T
/
V O
0C c
P i
N W
O t
~
U H
M S T a
/
0 W
E E
b 0
I l
R a
t R 0 5
O i
O L d
C T E A
u-5 B M
i t
F l
O l
f T
0 E
R 0
M 1
A
/
4 4
T I
M E
T N S
O R
E I
R UG R T E
U A T
I T C F
F 0
A b M
A 0
R L 3
E E
P E M
M L I
E P T
T t
/
M 0
C0 0
/
M 0
R 2
E M
i i
T R
O F
00 M
1 M
0 0
0 0
0 0
5 0
5 0
5 1
1 2
2 M
evo b
n a o M
i s
t e a e r F r u O g
t e a M
D S 8
l l
\\'l l
l'il
\\
l\\
4 V.
Verification of Analysis To check the correctness of the atove calculation, two checks were made.
First, the initial rate of temperature rise should be consistent with the adiabatic rod heat up rate a*. 2% power.
This rate is dTA average bundle decay power
- axial peaking function dt bundle heat caoacity 0.02
- 2438 megawatts
- 948 e awatt / 566 assemblies,, f(x) sec.
64a{7.37LbmU02 +.911 Lbm Z
- 0.12 Btu r
g Lbm F 0
1.30 F/sec.
- f(x)
=
A line corresponding to the adiabatic heat up rate at 1 ft. below TAF h.is been drawn on Figure 4 and it can be seen that the rod temperature rise ra;e approaches it near its time of uncovery'.
I A calculation was al'so conducted to check the correctness of the steam temperature rise calculation.
Figure 5 shows the axial distribution uf I
interior group rod temperatures and steam temperatures at 1000 sec after the start of core uncove'y.
To check the calculated steam temperature:1, r
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 l
is:
~
a + b(x-1/k) + (T$ + b/k - a) e-kx (16)
T
=
st where a and b are the coefficients of the linear temperature profile (Tr
- g a+bx) and k is defined as II
- ned k=
thCp (17)
Using the heat transfer co.!fficient computed from the correlation giv3n earlier (9.42 Btu /Hr-Ft2. oJ), the steam temperature was calculated usi19 the above formula.
Results are plotted on Figure 5 and show close agreement with the machine calculation.
,I
~
l1
E
'd FIGURE 5 CHECK OF STEAM TEMPERATURE CALCULATION j
O COMPUTED R00 TEMP.
A COMPUTED STEAM TEMP.
ASSUMED LINEAR R00 TEMP. PROFILE 51EAM 1EMP.,R0,1LE ea0M eon. ie g
I n
l l.\\.~
N
/
5 1
.l Degrees F Above Bturation E
l 100 I
I i
~
t i.
l l
2 4
e 8
10 12 l
~
FIET FROM BAF g
78
l VI Comparison 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.toccuple response time by the NRC office of Nuclear Regulatory Research.
Thei r calculation assurted 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 ft above B A F) and 3.80F at the 60% core height elr.vation. With these heat up rates their results show that a thermocouple at the 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 wi11 show 450F temperature rise 135 seconds after the 60% plane is uncovered.
E 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 the5e planes uncovering at 110 and 242 seconds respctively.
We conclude that the essential differences between our calculation and t7e NRC's are the extremely high heat up rates they assumed and the fact that l
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 theruocouple response. We believe our assumptions are more realistic, and our results more correct.
R 79
~
I I
I I
af at,0F s
i 8
500-l 100-Rods 3
l (Adiabatic 250.
l l
5 1
Pods (Adiebatic) g g
\\
' T/c I
l g
250.
450F
[
T/C s [
I 5
l i_
50.
l l
Percent of Core Which
- Is Covered I
I
- B i
L I I
I I
Id0 2'00 300 lt I
TIME, SECONDS AFTER START OF CORE UNC0VERY l
FIGURE 6 RESULTS OF NRC CALCULATION
,5 1
~
'I l
.o 13 II 100%
ATsat,0F 500.
80% -
Rods 250.
L50f
~
60%_
II i
Percent Of Core Whicn II Is Covered II 15 5
ld0 20'0 3b0 4d0 TIME AFTER START OF CORE UNC0VERY, SECS.
FIGURE 7 l
PRESENT CALCULATION WITH NRC ASSUMPTIONS I
I
..?
a I
VII.
Effect of Cranging Reactor Pressure Vessel Pressure All the calculations discussed in the. previous sections assumed that the reactor vessel pressure was constant during core uncovery and heat-up.
During the sort of small break loss of coolant accident where core ther-l mocouples are likely to be useful, however, the pressure will most likely not be constant.
For example, below in Figure 8 is a computed pressure i
trace for the Leib5tadt plant during a Turbine Trip transient. The reactcr vessel pressure rises to the relief valve set point and then drops when tre h
valve is open. During this pressure drop, voids will form in the saturated I
liquid. These voids will raise the water level as illustrated in Figure S.
l The amount by whicn the water level will rise can be determined by a simple approximate, calculation.
g According to Reference 5, the fluid filled cross-sectional area of tr.e Peachbottom II plant between the top and bottom of active fuel is about 220 l
2 3
ft.
The amount of water below the core is about 4100 ft.
Since the 3
Lbm/ft, the mass of density of saturated water near 1000 psia is 46.3 l
water in the reactor is I
Mass of H O = 190,000 v 10,140 Z g
2
.I where Z in the height of actise core which is covered. The quality change for en incremental change in pressure can be obtained from the chain rule:
l dh AP
\\
Ax=
=--
p
\\
l IJnder thesa conditions l
l f"
g AP 0.004 ax
=
l For the 60 Psi char.ge in pressure which Figure 8 shows takes place when the relief valve opens, the change in quality will be 0.022. This corresponds l
l to an increase in volume of I
av = 1894'+ 101 Z I
s 82
2 8
1 VESSE1 Pt@.5 ATSE (PSI) 2 SAFETT v4.vE Fled 300*
3 AFLIEF VPLYE F(CW
~ ~ ~
C8tettsfvfGE YLca
~
5 G
20(1
=
1CK3.
0.
I '-
3 7 tl, I
- 'u 3
4 0.
10.
20.
30.
40.
TIME (2.C3 FIGURE 8 SMALL BREAK PRESSURE HISTORY (Liebstadt)
- Ig 13
- 13 VALVE CLOSED VALVE OPEN
'l II
' l
{l I@c -W.4!ss::#:dNF lll C
- f. _ ---)
CI:
4:
T+-
C(~k
,, (ji )
G
^
- !!kk-Ri.in!:
' !! M 1
b._.
FIGURE 9
\\
LEVEL SWELL EFFECT OF OPEN RELIEF VALVE 83 cII
l 9
l FIGL'RC 10 l
ANTICIPATED EFFECT OF LEVEL SWELL
[
l 5
I E
OPEN CLOSE OPEN CLOSE OPEN CLOSE I
I E
. FUEL !
Temp.
I
/
E I
f l
I I
I f(
A
/
\\ T/C l
TSAT -
/
I i
TIME g
l I
~
r 1
2 Using the core, bypass and annulus fluid cross section of 220 f t, this corresponds to a change in water level of ah = 8.64 + 0.462 Z l
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 easy to predict. If the rods are hot enough, then the rod surf ace will not rewet and very littie heat will be lost. On the other hand, even if the channel wall is hot, the fact that it has a high surface 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 I
but the thermocouple would never read a temperature very far from sateration.
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 deme, 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 after the steam has left the core. The ideal way to do this would be to put a bare thermocouple in the '; team flow just above the core I
exit. Examination of detailed reactor drawings indicates that this would j
be very difficult to do.
An easier alternative would be to put the thermocouple in the steam dome. A thennoccuple 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.
~
l
b I
l b
The analysis developed to investigate thermocouple response in the in-core
- tubes was used to determine the response time of thermoccuples in these two f
locations.
The temperature drop of the steam as it flows through the dryers and separators was calculated (approximately) by t'reating these parts as a uniform temperature heat exchanger:
l 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
=
(m,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 I
d(Tsurf)
(m cp)
[Tst (exist) - Tst (entrance)]
,~
dt (msep )
C I
2 The area of the separator-standpipes-dryers was estimated at 20,000 Ft,
the mass was estimated at 130,000 Lbm.
l Results shown 'n Figure 11 do not show the alternative locations to be promising. As Figure 5 showed earlier, the temperature of the steam at l
the core exit follows the temperature of the top of the rod bundle fairly closely. Since the power is low at the top of the bundle, the temperature l
there rises fairly slowly.
For this reason, a thermocouple in the upper l
plenum would not read 450F above saturation for seven minutes after the l
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 minutes after uncovery.
l l
86 l
l The two response times calculated above for thermocouples in the upper plenum and steam dome are intended to illustrate the lower limit of how 3
fast 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 f actor of two.
t t
t E
E R
I l
l l
B 15
~,,
m m
m m
m m
m' m m
m m
m m
m m
W
'm m
m FIGURE 11
- s TEMPERATURE TIME HISTORIES FOR ALTERNATE LOCATIONS
- NOT INCLU0illG DILUTI0rt BY STAURATED STEMI.
50 -
Upper Plenum Steam Dome Degrees Above 30-Saturation F
20 10 i
i i
i 100 200 300 400 500 600 700 800
/
TIME AFTER START OF CORE UrlC0VERY. SEC s===s mammm am=e sseurs muss rirrf ENF IST
I I
lJ imates of Costs & Exposure for Installation of Incore Thermocouc 3 E
1 and 2 show estimated costs and exposures respectively for in-3gion of 16 thermocouples (TC's) in the BWR core for us B
3 gensing method.
Three cases are considered:
e 4 in each quadrant of the core.
Installatior. Prior to Fuel Load Case 1.
I
- nstallation During an Outage Case 2.
Differential Cost of TC Installation vs. Norma' Failed LPRM ase 3.
Replacement work performed during a refueling outage.
i d A/E fees, 9 gosts include material, labor, overbead, engineer ng an The material costs Mpngency and escalation @ 10%/yr. for 3 years.
/TC which results
@gde $700,000 for 16 strings of qualified LPRM assy. wThis compare most of 543,750/assy.
The additional costs
<0 000/assy for a standard replacemer.t LPRM assy.
In calculating des the TC, and allocated R&D and qualification costs.
RM assy.
ie differential cost in Table 1, Case 3 the cost of a typical LP te 525,000.
ajC was takan as costs and radiation expenses for thermocouple installation can be h
ummarized as:
,I Exposure Man /R l
Min.
Fax.
Cost I
N/A N/A 5 2,093,948 gse1(PriorFuelLoad) 2,470,220 65 450 gse 2 (During Outage) 50 250 1,697,237 Case 3 (
vs. Repl. LPRM)
I 69
B I
Table 2 shows a ain/ max rem exposure r;xpected for installation during l
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 g
I History.
l Some plants could produce rates 2 or 3 times higher than the highest rite on Table 2.
The rates on Table 2 are considered ranges expected for 75%
of operating BWR's.
The total exposure would be spread over a number of workers so as nct to exceed the quarterly allowables for 1 worker.
The following assumptions were used in developing these estimates:
!I E
1.
Installation of TC's would be accomplished by repiccing an L'RM assy. with a naw design which includes a TC in the LP?.M a* sy.
g 2.
The existing wiring and connectors for LPRM's need not be al-tered or replaced.
3.
New uiring for 16 TC's is added using existing sparc electri:al penetrations.
No drywell sh'. eld or primary containment core l
drilling is necessary.
4.
The TC's are wired back to the relay room to 16 signal con-l ditioners and from there to 2 recorders in the control room.
1 The system is separated inte 2 divisions 1I i
90 I
I
l.
5.
For installation of each of 16 LPRM assy. relateo cable anc cor.duit runs inside containment, a five man crew includin-) 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, 2M0/TC is spent inside the drywell and the remaining 38 M0/TC is spent inside contain-ment.
I 6.
The differential exposure between installing TC's vs. the normal failed LPRM replacement activity is the exposure resulting f rom cable installation inside primary containment only.
I ll I
I lI I
- I
,I I
,I l
I I
i
g M
M M
M M
M M
M gtE E 73 Case 1 Cli w 2 C2 " 3 Prior to During Cost in Addition to fuel Load Outage Replatement of Failed LPRMS ITEM gig nit Mit Labor Material
_ Labor Ma tt. rial Labor Material 1.
LPRM Strings & Install 2,560 700,000 6,400 700,000 128 300,000 (16 Strings)
~
2.
Cable (to Control Room) 1,740 4,800 3,720 4,800 3,720 4,800 3.
Penetrations & Assy.
448 140,000 1,380 140,000 1,:18 0 140,000 (Incl. Seal) 4.
Terminal 8 oxes 160 4,000 480 4,000 180 4,000
~
5.
Cable Trays & Installation 3,400 48,000 5,000 48,000 5,000 48,000 6.
Electronics Installation 550 24,000 550 24,000 ISO 24,000 Sub Total 8,858 920,800 17 M30 920,000 11,?58 520,000 Labor @ S20/Mit 177,160 350,600 225,160 Distributed Costs 97,000 193,000 123,838 (Clerical: Doc. etc.)
@ 55% (DL)
Utility Engineering 130,000 140,000 140,000 A/E Fee = 5% (M+L) 55,000 65,000 65,000 Escalation (3 yr 0101) 413,988 500,820 322,439 Continge. icy
~
300,000 300,000 300,000
/
Total
$2,093,948
$2,470,220 51,697,237
=
M
'une gnmi sets
'un
'F"5 W
W W
W D
M T5 E
EEh
Table 2.
I.
Radiation Intensity e
L_q;ation Exposure mR/Hr g
Inside Drywell Min Max 5
At LPRM Flange 100 750 Platform (5' Below Flange) 50 300 Inside Primary Containment 10 50 II.
Estimated Exoosure for 16 LPRM Assy. w/TC.
Min.
Drywell:
12.8 ManR x
x TC 0
HR Prim Contm:
38MD 8 hrs 16 TC 10 mR R
48.64 ManR
=
TC 0
Hr Min. Total 61.44
=
Say 65 Ma'n R Max Drywell:
2 MD 8 hrs 16 TC,750 mR 192 Man R x
=
TC 0
Hr 8
Prim Contm:
38 MD 8 hrs 16 TC 50 mR 243.2 Man R x
x x
=
TC D
Hr TOTAL = 435.2 Man it Say 450 Man R MD = Man Day 8
3
b e.-D I-Table 2 (Contd)
I I
III.
Differential Exposure vs. Replacement of 16 Failed LPRM Prim. Contm. Exp.
= 50 Man R Min.
=
I
=250 Man R.
a Max.
=
I I
I I
I I
I I
I I
I I
I I
I I
I I
~
I e4
X.
Conclusions t
Based on the preceeding analyses we conclude:
1.
If thermocouples are mounted in BWR cores for use as ccre uncover y indicators they will not respond for at least 10 minutes after uncovery in a small break LOCA.
2.
Because BWR's have other level gages, the operator will be given conf licting information d aring this 10-13 minutes.
That is, his ccre thermocouples would say he is not in trouble, while his level gages say he
.i.s,.
3.
The analysis performed by the NRC calculates a quick response of the core thermocouples because of two assumptions made - first ti.at convective heat transfer ciay be neglected, and second that the uncovered rods (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.
8 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.
g Locating the thermocouple in the upper plenum or steam dome probably ye will not reduce the time dalay. Furthermore, this has not yet been prosen 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 a
450 man-rem.
p
g 1
I REFEREricts.
1.
Convective Heat and Mass Tiansfer, W. M. Kays and M. E. Crawford..
McGraw Hill Publishing Co., 1978.
g 2.
"8WR 4/5/6, Standard Safety Analysis Report", General Ele G ric Co.
3.
5parrow, E. M., A. L. Loeffler, Jr., and H. A. Hubbard, Trans. ASME, g
J. Heat Transfer, pp. 415-422, Nov. 1961.
4
" Calculations of Combined Radiation and Convection heat Transfer in l
Rod Bundles Under Emergency Cooling Conditions", K. H. Sun, J. M.
Gonzalez and C. L. Tien ASME paper 75-HT.-64, 1975.
g 5.
" Gray - A Program for the. Calculations of Radiation Heat Transfer Gray Body Factors in Boii ng Water Fuel Bundles", J. M. Sorensen, D.
A. Mandell, R. Be. Selew, J. P. Dougherty.
6.
Core Design and Operating Data for Cycles 1 and 2 of Peach Bottom 2,
.l EPRI Topical Report NP-563, June 1978.
g l
7.
Turnage, Anderson, Davis and Miller " Advanced To Phase Flow In-strumentation Program Quarterly Progress Report for Jan-March 1980",
NUREG/CR-1647 (Sept. 1980) g 8.
Turnage, Anderson, Davis and Miller, " Advanced Two Phase Flow Instrumentation Program Quarterly Progress Report for April-June, 1980, NUREG/CR-1768 (Oec. 1980).
9.
Turnage, Anderson, Davis and Miller, " Advanced Two Phase Flow Instrumentation Program Quarterly Progress Report for ' July-Sept.
I 1980, NUREG/CR-1903 (Mar. 1981).
I I
I I
96 I
I
W I
APPENDIX A The dimensions used in this analysis are shown be' low:
I 148 ins.
Rod bundle axial length I
0.416 ins.
Rod diameter I
0.034 ins.
Cladaing thickness Fuel Rods per bundle 64 0.135 ins.
Rod to wall gap Channel cross section 5.52 x 5.52 ins.
Chaniel wall thickness
.120 ins.
Rated Reactor Thermal Power 2436 megawatts Thimble diameter 0.70 ins.
Thimble thic' ness 0.080 ins.
e E
E E
1-97
~
8
e I,
APPENDIX B I
TABLE 1: BWR VARIABLES (NRC Regulatory Guide 1.97, Revision 2)
A Variables: those vanables to be monitored that provide the primary information required to permit the control com cperator to take specific manuaUy controUed actions for which no automatic controlis provided and that are required cr safety systems to accomphsh their safety functions for design basis acetdent events. Primary information is informa-that ts essential for the direct accomplishment of the specified safety functions; it does not include those vanables a
are associated with contingency actions that may also be identified in wntten procedures.
A nable included as Type A does not preclude it from being i.ncluded as Type B, C. D, or E or vice versa.
5 Category (see Regulatory Variable Rag Position 1.3)
Purpose PWt specific Plant specific I
Information required for operator action E B Variables: those variables that provide information to indicate whether plant safety lunctions are being accomplished.
Plant safety functions are (1) reactivity control, (2) core cooling,(3) maintaintng reactor coolant system integnty, and (4) taining containment attegnty (including radioactive effluent control). Vanables are listed with designated ranges and try for design and qualification requirements. Key variables are indicated by design and qualification Category 1.
R tuity Control tron Fluu 10% to 100% fuu power 1
Function detection; accomphshment (SRM, APRM) of mitigation ntrol Rod Position Fuu in or not full in 3
V:nfication RCS Soluble Boron Concen-O to 1000 ppm 3
Venfication tion (Sam ple)
Core Coohng Bottom of core support plate to i
Function detectiore accomplishment Iolant Levelin Reactor lesser of top of vessel or center-of mitigation; long-term surve Uance line of main steam line.
I'"< ' ' *-
= * '>
water level M taining Reactor Coolant
- m Integrity RCS Pressure 15 paa to 1500 psig i
Function detection, accomplishment 2
of mitigation;venfication well Pressure 0 to design pressure 3 (psig) 1 Function detection, accomplishment 2
of mitigation;venfication e
IFa'un thermocomptes per queorant. A minimum of one measurement per quadrant as required for operation.
Whm a vanable is tasted be omre than one snarpons, the instrumen tation requirementa may be integrated and Caly one measurement pr(Mded.
Design pressure is that value oorvropondang to ASME code values that are obtaaned at or below code allowable values ror matenal design I
99
~
j I
TABLE 1 (Contmuod)
I C.t. ~.e Regulatory 3
Variable Range Position 1.3)
Purpose TYPE B (Contmuedl t
Drywet! Sump Level Bottom to top I
Function detection; accomplishment Maintaining Containment integrity 2
Pnmary Contamment Pressure 10 psia to destsn presaure' I
Function detection. accomphshment of mitagation, venfication I
Primary Contautment Isota-Closed-not closed I
Accomphshment ofisolation tion Valve Position (esclud-ing check valves)
TYPE C Variables: those vanables that provide iriformation toindicate the potential for bemg breached or the actual breach of the barners to fisnon product releases. The barners are (1) fuel cladding, (2) pnmary coolant pressure boundary and(3) con-tainment.
I i
Fuel Qadding I
Radioactivity Concentration or I/2 Tech Spec limit to 100 times l
Detection of breach l
Radiation Level m Circulating Tech Spec bmit, R/hr en Primary Coolant I
Analysis of Pnmary Coolant to uCi/sm to 10 Ci/gm or 3*
Detail analysis; accomphshment of -
(Gamma Spectrum)
TID 14844 source term in matisation; venfication, long-term coolant volume survedlance BWR Core Thermocouples:
200*F to 2300*F l'
To monitor core cooling Reactor Coolant Pressure i
Soundary RCS Pressure' 15 psia to 1500 psis I
Detection of potential for or actual s
I breach, accomplishment of mitiga-tion;long term surveillance Pnmary Contamment Area I R/hr to 10' R/hr 3 '
Detection of breach; venfication g
2 Radiation g
' Sampling or monitoring of radioactive liquids and gases should be performed an a manner that ensures procurement or representative samples. For gases, ine cnteria of ANSI NI3.I snould be oppised. For liquids. provtsions should be made for samphng from wou mised turbu-lent sones, and samptsng hnes should be designed to minsmite plateout or deposition. For safe and convenient sampling. the provisions snould include:
I
- b. Sample containers een container +ampling port connector compatibdity.
[
- c. Capabihty or sampling under onmary cintain pressure and nesstrwe pressures.
- d. Handhnt and transport capabihty, and
- e. Prearrangement toe analysts and snaerpretation.
l s
The maaimum value may be rectaed upward to satisfy ATWS requirements.
4Minimum of t'*o monitors at _det) esp arated locations.
I
,,8 ecto, sho. d r.spon. to 3.mma esd.. tion p otons _t in.n..ne,g range, rom a... to...
_tn an.n.rty respons..
.,ac.
of t *0 percent at any specific photon energy from 0 I %teV to J Mev. Overall system accuracy should he within a factor of 2 over tne entire l
range.
l.97 9 100
~
I E
l TABLE 1 (Continued)
Category (see I
Regulatory Variable Range Position 1.3)
Purpose YPE C (Continued)
Steactoe Coolant Pressure Boundary (Continued)
I(Dryweu Drain Sumps Level 2
Bottom to top i
Detection of breach; accomplishment Identified and Unidentified of trutigation; venficataon;long-tera Leakage) sune:Uance Suppreuion Pool Water Level Bottom of ECCS suction ime i
Detection of breach;accompbshment to 5 ft above normal water of trutzgation, venfication,long term level suneWanee Dry well Pressure?
O to design preuure' (psig) 1 Detection of breach;venfication ntainment t
5 5 RCS Preuure 15 psia to 1500 psig 1
Detection of potential for breach; accomp! shment of mitigation IPnmary Containment Preuure*
10 psia pressure to 3 times design 1
Detection of potential for or actual 3
preuure for concrete.4 times breach; accomplishment of mitiga-design pressure for steel tion Containment and Drywell O to 309 (capabibty of operating i
Detection of potential for breach; 3
Hydrogen Concentration from 12 psia to design pressure )
accomphshment of mitigation O to 107 (capabd2ty of operarms I
Detection of potential for breach; I Centamment and Drywc!!
3 Oxygen Concentration t for from 12 psia to design preuure )
accomphshment of mitigation inerted containment plants)
I Containment Effluent s3 Radio-10* fiiw to 10 a JCilcc 3
Detecti,an of actual breach, accom-activaty Nnble Gases (fron pbshment of mitigation; venfica-identified release points includ-taon ins Standby Gas Treatment I System Vent) 4 7
Radiation Exposure Ratet(m-10 R/hr to 10' R/hr 2
Indication of breach I side buildings or areas, e g.,
auxdiary building, fuel hand-ling budduig, secondary con-tainment. which are m direct I crntact with pnmary con-tainment where penetrations and hatches are located)
I_ith Cineral Des.cn Critenen 64 Provisinas shnuto tre made to monitar allidentMe J pathways for releue of gueous redsuscrive matenals to the enevons in conformance wnetarins nf indiv Juel efnuent stresms is only reuuwed where such siteams are releued brectly ento the I
wenvirument. ti tw.s or more stream.s a.e comh.ne2 g nne to relea e from a tsmmon Jacharge poent, muniennng of the comhined stream as conseCred to meet the untent of this regulatory guade p enJej su6h monotonne has a range sJequate to meuure worst <ase releases.
Ie'audatinum noble saa (b $n reoduct mie'ures to Iomf a mia meatures. mith oversit system secu
'Momten should he carat >4e of detecting anJ ree s%eing rsJioactive guenus efnuent c *ncentrations with compotatinns ranging from fresh tions mas he espresseJ sa terms'of u i 3) qui elents ne sa terms of ans nable gas euci,Jehi le is nat enreeteJ test a single manitoring Jence
= sit have sufncient range ers encremr us tne entee canae TroviJed an this regu!stnes agede anJ that multiple companents or systems wd! oe nerJ23. Esassing equerment mas he use1 a.. monitor on, partion of the stated range within the eavspment Jesagn esteng 1.97 10 101 s
l L
TABLE 1 (Continued)
Category (see
-I Regulatory Variable Range Position 1.3) '
Purpose TYPE C (Continued)
Con *ainment (Continued) 3 Efnuent Radioactmty - Noble 10 uCi/cc to 103 uCi/cc 2'
Indication of breach I
Cases (from buildess as indicated above)
I TYPE D Variables: those variables that provide information to indicate the operation of individual safety systems and other systems important to safery. These vanables are to help the operator make appropnate deensions in ustng the individual sys-tems importar.t to safety in mitigating the consequences of an accident.
Condensate and Feedwater System Main Feed *ater Flow 0 to 110'c der:gn now
3 Detection of operation. anajysis of cooling Condensate Storage Tank Level Bottom to top 3
Indication of available water for Primary Containment Related Systems Suppression Chamber Spray 0 to 110'*c desyn now
2 To monitor operation Flow I
2 Dryweu Pressure 12 psia to 3 psig 2
To monitor operation 3
0 to 1107 desgn pressure Suppression Pool Water Level Top of vent to top of west well 2
To monitor operation Suppresunn P:nl %ter 30*F to 23G'F To monitor operation Temperaare Drywet! Atmosphere 40*F to 440*F 2
To monitor operation Tem perature Drywell Spray Flow 0 to 110'.~c design now
2 To monitor operation Main Steam System Main Steamitne Isolanon 0 to 15"of water To provide indication of pressure Valves
- Leakage Centrol O to 5 psid boundary maintenance System Pressure Pnmary System Safety Relief Closed-not closed or 0 to 50 psig 2
Detection of accident; boundary Valve Positions. Including ADS tntegnty indication or Flow Through or Pressure in Valve Ltnes t s.. e. n.... i..... _ n......... im..... _. e........
! 97 11
~
m
r o
I TABLE 1 (Continued)
I Category (see Regulatory Variable Range Position 1.31 Purpose YPE D (Continued)
Safety Systems
!solati:n Condenser System
- Top to bottom 2
To monitor operation SheU. Side Water Level Ilsilati:n Condenser System Open or closed 2
To monitor status Vahe Position RCIC Flow 0 to 110% dengn Dow
2 To monitor operation-HPCI Flow 0 to 110% oengn now
2 To monitor operation Core Spray System Flow 0 to 110ce design now
2 To monitor operanon LPCI System Flow 0 to 110% design now
2 To morutor operation SLCS Flow 0 to i10% design now
2 To morutor operation SLCS Storage Tank Level Bottom to top 2
To monitor operation esidual Heat Removal (RHR) stems RHR System Flow 0 to 110% design'0ow
2 To monitor operation RHR Heat Exchanger Outtet 32*F to 350*F 2
To monitor operation Temperature oling Water System Coobng Water Temperature to J 2* F to 200* F To monitor operation IESF System Components Cooling w ter Flow to ESF 0 to 110% dengn Cow
2 To monitor operation a
System Components Iadwaste Systems igh Radioactivity Liquid Tank Top to bottom 3
To monitor operation evel j
Ventilation Systems mergency Ventilation Damper Open<!osed status 2
To monitor operation tsation l
l wer Supplies i
tatus cf Standby Power and Voltages, currents, pretsures 2
To monitor system status l
Otact Energy Sources important o Safety (hydraube, pneumatac)
Status indasuon of as 5:sade, Power s.c. buws. d.c. Duses inverter output auses, and oneumeric supplies.
I 1.97 12 103
TABLE 1 (Continued)
TYPE E Variables: those vanables to be monitored as required for use in determming the magnitude of the release of radio.
active materials and continually assessing such releases.
I Category (see Replatory Variable Range Position 1.3)
Purpose I
Containment Radiation 7
Primary Containment Area 1 R/hr to 10 R/hr l '
Detection of significant releases; 2
Radiation High Range release assessment;long term survedlance; emergency plan actuation Reactor Building or Secondary 80 R/hr to 10' R/hr for Mark I 2'
Detection of sigmficant releases, Contamment Area Radiation
- and !! containments release assessment,long term i R/hr to 10' R/hr for Mark III l' 7 survedlance contunment Area Radiation 2
7 Radiation Exposure Rate 10 R/hr to 10' Rihr 2
Detection of sagmficant releases:
I (inside buddtngs or areas where release assessment;long-term access is required to service survedlance equipment important to safety)
I Airborne Radioactive Materials Released from Plant Noble Cases and Vent Flow Rate 4
3 Drywell Purse, Standby Gas 10 uCi/cc to 10 uCi/cc 2'
Detection of sigmficant releases:
Treatment Systeri Purge O to i10% vent iesign Dow'8 release assessment (for Mark I and 11 plants)
(Not needed if efi'.uent discharges I
and Secondary Contain-through common ptant vent)
[
ment Purge (for Mark Ill 3B plants)
Secondary Containment 10 yCi/cc to 10' uCi/cc 2'
Detection of sigmfacant releases.
l' Purge (for Mark I, II, and 0 to 110% vent design Dow release assessment
!!! plants)
(Not needer!if ef0uent discharges through common plant vent)
Secondary Containment 10 WCi/cc to 10' uCi/cc 2'
Detection of sismficant releases; l0 j
(reactor shield building 0 to 110% vent design Dow release assessment I
annulus, if in design)
(Not needed if efnuent discharges l
! W through common plant vent) sa Ausdiary Budding 10 WCi/cc to 103 yCi/cc 2'
Detection of s2snificant releases; I
=
(including any buddtng 0 to !!O% vent design flow'8 release assessment;long term containing pnmary system (Not needed if efnuent discharges survedjance gases, e.g., waste gas decay through common plant vent) tank)
Common Plant Vent or Multi-10 fi/cc to 10 uCi/cc 2'
Detection of sagruficant releases.
4 3
purpose Vent Dischars:ng 0 to 110.i vent design Dow
release assessment. long term I
Any of Above Releases (if surveillance
[
drywell or SCTS purge is y
included) 10'* fi.cc to IO* uCilec I
I 1.97 13 10'.
g 5
I TABl.E 1 (Continued)
Category (see i
Regulatory Varistde Range Posinon 1.3)
Purpose TYPE E (Continued)
Airtiorne Radioactive Materials Celeased from Mont (Continued)
I Noble Cases and Vent Flow Rate (Contanued)
All Other Identified Release 10 uC /cc to 10 uCi/cc 2'
Detection of significant releases; 4
2 I
Points 0 to 110fe vent design flow
release assessment;1ong-term (Not needed if effluent discharges surveillance through other monitored plant vents)
Partaculates and Halogens I
2 AllIdentified Plant Release 10'3 Wi/cc to 10 uCi/cc 32 Detection of significant releases; Points. Samphng with Onnte O to 110% vent design flow
release assessment; tong-term Analysts Capability surveillance I
activity Environs Radiation and Radio-Radiation Exposure Meters Range. location, and quahfica-Vertfy significant releases and local I
(fixed locations) continuous indication at non criteria to be developed to magnitudes sattsfy NUREC 0654, Seenon II.H.5b and 6b requirements for emergency radtological monitors 83 Airborne Radiohalogens and 10'* uCt/cc to 10'3 uCt/cc 3
Release assessment. analysts Particulates (portable sampling with onsate analysis capabthry) 3' Release assessment, analysts Plant and Environs Radistson
~ 10'3 R/hr to 10' R/hr, photons 8
83*
(portable instrumentauon) 10'3 rads /hr to 10* rads /hr, beta radiacons and low-energy photons Plant and Environs Radio-Multichannel samma-ray 3
Release assessment, analysts actavity (portable instru-snectrometer I
mentation) l l
l l
To provide information regarding release of radioactive halogens and partaculates. Conteuous collection of representative samples followed 12 by onsite laDoratory measurements of samples for radaohalogens and particulates. The desagn envelope for shielding. handhng, and analyncal time at sampier design flow, an average concentration of to pCi/cc of radsosodanes l
l purposes should assume JC minutes of integrated sam I gCe/cc of particulate radiosodmes and particulates other than radioeodines, and an in gaseous of vapor form, an average concentration o i
average samma photon enersy of 0 s MeV per dasantegration.
'3For esdmatina release rates of radioactive matertala r'eleaand dunns an accident.
8*To monster radiation and airborne radioactivity concentrations in man, arena throughout the facdity and the sate envvons wfiere it as impractacal to unstall stataonary monstors capsele of covering both normal and occadent levela.
i I
I 105 1.97 14 a
TABLE 1 (Continued)
I Category (see l
Regulatory 5
Variable Range Position 1.3)
Purpose TYPE E (Continued)
Is Meteorology Wmd Dtruction 0 to 360* (r.5* accuracy mth a 3
Release assessment aerlection of 15*). Stamns speed 0.45 mps (1.0 mph). Dampmg ratio I
l between 0 4 and 0 6 di. stance con-sunt 12 meters y
l Wind Speed 0 to 30 mps(67 mph):0.22 mps 3
Release assessment l
(0.5 mph) accuracy for end speeds less than 11 mps (25 mph) mth a startmg thashold ofless than 0.45 mps (1.0 mph)
I Estimation of Atmos-Based on vertical temperature 3
Release assessment phenc Stability difference from pnmary system.
5'C to 10*C ( 9'F to IE*F) and I
$15'C securacy per 50. meter miervals ( =0.3*F accuracy per 164 foot mtervals) or analogous I
range for alternative stabthey estirnates Accident Sampling'
- Capa-I belity (Analysis Capebel-ity On Site)
Pnmary Coolant and Sump Grab iarnple 3* I '
Release assessment; venfication; l
analy sis y
Gross Activity 10 uCi!ml to 10 Ct mi Gamma Spectrum (Isotopic A.nalyns)
+
I Boron Content 0 to 1000 ppm
=
Chlonde Content 0 to 20 ppm Dissolved H>drogen or o to 2000 ce(STP)/Lg Total Gas' '
I Dissolved Oxygen s 0 to 20 ppm pH I to 13
+
Contamment Air Grab Sample 3*
Release assessment; venficat2on.
l I
analysts 5
Hydrogen Content 0 to 10%
0 to 30% for inerted containments Oaygen Content 0 to 30%
Gamma Spectrum (Isotopic analysis)
+
'8Cuidance on meteoroto I
Propams in Support of Nuciens Iower Plants.w mensveements a t=v's de'eioped in a Propo**d Revision I to Regulato y Cuade 1.23. "Meteorotoszcal r
I The time for taung and analysing samples should De 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> ce less from the time the decision as made to sample. escept for chloride which shoulJ De witmn 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
I An insta0ed capaDQaty naould tw provides for ottaseing contaanment eump ECCS pump room aumps, and other samdat suadiary ou0 dins sump 4:ause samples.
I Applies only to pnmary coolant, not to sump.
l.97 15
L I
APPENDlX C ABBREVIATIONS ADS automatic depressurization system I
APRM average-power range monitor' ATWS 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 diesel generator I
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 I
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,
L
g M
=
,o.
r 9 '.
t RPV reactor pressure vessel RWCU reactor water cleanup unit SBGT standby gas creatment SCS suppression chamber spray SGTS standby gas treatment system SLCS standby liquid control system g
SRM source range monitor 6
li gi 3
I.
1 i
l' I
Hl I
5 l
l I
I i
108 s
i
..