ML20094D248
| ML20094D248 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 12/13/1991 |
| From: | SCIENCE APPLICATIONS INTERNATIONAL CORP. (FORMERLY |
| To: | NRC |
| Shared Package | |
| ML13302B823 | List: |
| References | |
| CON-FIN-D-1311, CON-NRC-03-87-029, CON-NRC-3-87-29 SAIC-91-1251, TAC-M68599, TAC-M68600, NUDOCS 9112200020 | |
| Download: ML20094D248 (34) | |
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SAIC 91/1251 TECHNICAL EVALUATION REPORT SAN ONOFRE NUCLEAR GENERATING STATION UNITS 2 AND 3 STATION BLACKOUT EVALUATION TAC Nos.k8599 andi8600 g w.
Science Applications InternationalCorporation An Employee-Owned Company Final December 13,1991 Prepared for:
U.S. Nuclear Regulatory Commission Washington, D.C. 20555 g
Contract NRC-03-87-029 f
ask Order No. 38 j fjp000 l
171n Gand-
. nve. PO. Box 1303, McLean, Virginia 22102 (703) 821-4300 o ~- sa c c sn acam awe cmwan scr on ter ~uns.+ un wg.os.c. svm ce aw o~-m pr, n se one saw r,s w.
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TABLE OF CONTENTS Section fagg a
1.0 B A C KG RO UN D....................................................................
1 2.0 R E V 1 E W PR OC E SS.............................................................. 3 3.0 E V A LU A TI ON....................................................................... 5 3.1 Proposed Station Blackout Duration....................... 5 3.2 Station Blackout Coping Capability......................... 8 3.3 Proposed Procedures and Training.......................... 24 3.4 Proposed Modifications............................................... 26 3.5 Quality Assurance and Technical Specifications... 26 4.0 CON C LUSI ON S........................................................... 2 7 5.0 RE FE REN C E S......................................................................
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r TECHNICAL EVALUATION REPORT SAN ONOFRE NUCLEAR GENERATING STATION UNITS 2 AND 3
- STATION BLACKOUT EVALUATION
1.0 BACKGROUND
-On July 21,1988, the Nuclear Regulatory Commission (NRC) amended its regulations in 10 CFR Part 50 by adding a new section,50.63," Loss of All Alternating Current Power" (1). The objective of this requirement is to assure that all' nuclear
- power plants are capable of withstanding a station blackout (SBO) and maintaining
_ adequate reactor core cooling and appropriate containment integrity.for a required duration. This requirement is based on information-developed under the commission study of. Unresolved Safety issue A-44, " Station Blackout" (2-6).
The staff issued Regulatory Guide (RG) 1.155, " Station Blackout," to provide guidance for meeting the requirements of 10 CFR 50.63 (7). Concurrent with the development of this regulatory guide, the Nuclear Utility Management and Resource Council (NUMARC) developed a document entitled, " Guidelines and Technical Basis for NUMARC Initiatives Addressing Station Blackout at Light Water Reactors," NUMARC 87-00 (8). This document provides deta_iled guidelines and procedures on how to assess each plant's capabilities to comply with the SBO rule. The NRC staff reviewed the guidelines and analysis methodology in NUMARC 87-00 an;; sneluded that the NUMARC document provides an acceptable guidance for addressing the 10 CFR 50.63 requirements. The application -
of this method results in selecting a minimum acceptable SBO duration capability-from two to sixteen hours depending on the plant's characteristics and vulnerabilities to the risk from station blackout. The plant's characteristics affecting-the required coping capability are: the redundancy of the onsite emergency AC-power sources,' the reliability of onsite emergency power sources, the frequency of lf loss of offsite power (LOOP), and the probable time to restore offsite power.
L In order to achieve a consistent systematic response from licensees to the SBO rule and to expeoite the staff review process, NUMARC developed two generic
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9 response documents. These documents were reviewed and endorsed (10) by the NRC staff for the purposes of plant specific submittals. The documents are titled:
1.
" Generic Response to Station Blackout Rule for Plants Using Alternate AC Power," and 2.
" Generic Response to Station Blackout Rule for Plants Using AC Independent Station Blackout Response Power."
A plant-specific submittal, using one of the above generic formats, provides only a summary of results of the analysis of the plant's station blackout coping capability. Licensees are expected to ensure that the baseline assumptions used in NUMARC 87-00 are applicable to their plants and to verify the accuracy of the stated results. Compliance with the SBO rule requirements is verified by review and evaluation of the licensee's submittal and audit review of the supporting documents as necessary. Follow up NRC inspections assure that the licensee has implemented the necessary changes as required to meet the SBO rule.
In 1989, a joint NRC/SAIC team headed by an NRC staff member performed audit reviews of the methodology and documentation that support the licensees' submittals for several plants. These audits revealed several deficiencies which were not apparent from the review of the licensees'submittals using the agreed upon generic response format. These deficiencies raised a generic question regarding the degree of licensees' conformance to the requirements of the SBO rule. To resolve this question, on January 4,1990, NUMARC issued additional guidance as NUMARC 87-00 Supplemental Questions / Answers (11) addressing the NRC's concerns regarding the deficiencies. NUMARC requested that the licensees send their supplemental responses to the NRC addressing these concerns by March 30, 1990.
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2.0 REVIEW PROCESS The review of the licensee's submittal is focused on the'following areas consistent with the positions of RG 1.155:
A.
Minimum acceptable SBO duration (Section 3.1),
B.
SBO coping capability (Section 3.2),
C.
Procedures and training for SBO (Section 3A),
D.
Proposed modifications (Section 3.3), and E.
Quality assurance and technical specifications for SBO equipment (Section 3.5).
For the determination of the proposed minimum acceptable SBO duration, the following factors in the licensee's submittal are reviewed: a) offsite power design characteristics, b) emergency AC power system configuration, c) determination of the emergency diesel generator (EDG) reliability consistent with NSAC-108 criteria (9), and d) determination of the accepted EDG target reliability.
Once these factors are known, Table 3-8 of NUMARC 87 00 or Table 2 of RG 1.155 provides a matrix for determining the required coping duration.
For the SBO coping capability, the licensee's submittal is reviewed to assess the availability, adequacy and capability of the plant systems and components neededLto achieve and maintain a safe shutdown condition and recover from an SBO of acceptable duration which is determined above. The review process follows the guidelines given in RG 1.155, Section 3.2, to assure:
availability of sufficient condensate inventory for decay heat removal, a.
b.
adequacy of the class-1E battery capacity to support safe shutdown, 3
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availability of adequate compressed air for air operated valves c.
necessary for safe shutdown, j
d.
adequacy of the ventilation systems in the vital and/or dominant areas that include equipment necessary for safe shutdown of the plant, 1
ability to provide appropriate containment integrity, and e.
1 f.
ability of the plant to maintain adequate reactor coolant system inventory to ensure core cooling for the required coping duration.
l The licensee's submittal is reviewed to verify that required procedures (i.e.,
revised existing and new) for coping with SBO are identified and that appropriate j
operator training will be provided.
The licensee's submittal for any proposed modifications to emergency AC sources, battery capacity, condensate capacity, compressed air capacity, ventilation system for equipment operability, containment isoletion valves for providing appropriate containment integrity and primary coolant make-up capability is reviewed. Technical specifications and quality assurance set forth by the licensee to ensure high reliability of the equipment, specifically added or assigned to meet the requirements of the SBO rule, are assessed for their adequacy.
This preliminary SBO evaluation is based upon the review of the licensee's submittals dated April 17,1989 (13), May 1,1990 (14), September 12,1991 (15), and the information available in the plant Updated Safety Analysis Report (UFSAR) (12); it does not include a concurrent site audit review of the supporting documentation.
Such an audit may be warranted as an additional confirmatory action. This determination would be made and the audit would be scheduled and performed by the NRC staff at some later date.
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3.0 EVALUATION 3.1 Proposed Station Blackout Duration Licensee's Submittal The licensee, Southern California Edison (SCE) Company, calculated (13) a minimum acceptable station blackout duration of four hours for the San Onofre 2 and 3 (SONGS 2/3) Plant site. The licensee stated that no modifications are required to attain this coping duratien.
The plant factors used to estimate the proposed SBO duration are:
o 1.
Offsite Power Design Characteristics The plant AC power design characteristic group is "P1" based on:
Independence of the plant offsite power system characteristics of a.
"I1/ 2,"
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b.
Expected frequency of grid related LOOPS of less than one per 20
- years, i
c.
Estimated frequency of LOOPS due to extremely severe weather (ESW) which places the plant in ESW Group "1," and d.
Estimated frequency of LOOPS due to severe weather (SW) l which places the plant in SW Group "1."
2.
Emergency AC (EAC) Power Configuration Group The EAC power configuration of the plant is "C." SONGS 2/3 is equipped with two emergency diesel generators per unit. One EAC power supply per unit is necessary to operate safe-shutdown equipment following a loss of offsite power.
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o 3.
Target Emergency Diesel Generator (EDG) Reliability The licensee has selected target EDG reliability of 0.95 for all SONGS 2/3 EDGs, based on having a nuclear unit average EDG reliability greater than 0.95 for the last 100 demands. EDG reliabilities have been calculated (14) in accordance with Nuclear Safety Analysis Center (NSAC) 108 and were determined to be greater than 0.98 for each individual EDG.
Review of Licensee's Submittal Factors which affect the estimation of the SBO coping du ation are: the estimated frequency of LOOPS due to ESW and SW conditions, the independence of the offsite power system grouping, the expected frequency of grid-related LOOPS, the classification of EAC, and the selection of EDG target
- reliability.
Using Table 3-2 of NUMARC 87-00, the expected frcquency of LOOPS due to ESW conditions places the SONGS 2/3 site in ESW Group "1," which is in agreement with what was stated in the licensee's submittal ('3).
Using data from Table 3-3 of NUMARC 87-00, the expected frequency of LOOPS due to SW conditions place the SONGS 2/3 site in SW Group "1,"
which is in agreement with what was stated in the licensee's submittal (13).
This calculation was performed with the condition that there are multiple rights of way among the incoming transmission lines, consistent with i
UFSAR Figure 2.1-2 (12).
The licensee stated that the independence of the plant offsite power system grouping is "II/2." A review of the SONGS 2/3 UFSAR (12) shows that:
1.
There is a single switchyard for the site; 2.
During normal operation,230-kV power is provided to the essential buses for each unit through the unit reserve auxiliary transformers from a separate offsite transmission line; 6
E 3.
In the event that one offsite preferred power feeder fails to function, the safety related loads connected to it will automatically transfer to the other offsite power feeder via the companion unit through bus tie circuit breakers.
Based on the above and the criteria stated in Table 5 of RG 1.155, the plant independence of offsite power system group is classified as "12."
Establishment of the proper Emergency AC (EAC) Configuration Group is based on the number of available EAC sources and the number of EAC sources required to' operate safe shutdown equipment following a LOOP.
Each unit has two dedicated EAC sources, one of which is required after a LOOP. We agree with the licensee's assessment which places the plant in EAC Group "C."
The licensee selected 04) the EDG target reliability of 0.95 based upon having an average reliability of 0.98 for each diesel. The licensee _added that EDG reliabilities have been calculated in accordance with the method described in NSAC 108. Although this is an acceptable criterion for choosing an EDG target reliability, tha guidance of RG 1.155 requires that the EDG statistics for the last'20,50 and-100 demands also be calculated. Without this information,
- it is difficult _to judge how well the EDGs have performed in the past and if there should be any concern. We are unable to verify. the demonstrated start nd load run reliability of the plant EDGs. This information is only available onsite as part of the submittal's supporting documents. Based on the information reported by the licensee in NSAC-108, which gives EDG
- reliability data at US nuclear power plants, the EDGs at SONGS 2/3 did not t=
experience any faUures during the calender years 1984 and 1985. The licensee's selectic,n of the EDG target reliability meets the criteria specified in RG 1.155 and NUMARC 87-00. The licensee stated (14) that SCE will establish a diesel generator reliability program which will be consistent with that clarified in NUMARC 87-00, Appendix D, EDG Reliability Program. This program will be based on NUMARC guidance and will ensure that the 0.95 EDG reliabilities are maintained.
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With regard to the expected frequency of grid related LOOPS at the site, we can not confirm the stated results. The available informauon in NUREG/CR-3997. (3), which gives a compendium of information on the loss of offsite power at nuclear power plants in U.S., indicates that SONGS 2/3 experienced three LOOP events during the years 1973 1980. The report concluded that none of the events were symptomatic of grid related failures. In the absence of any adverse information, we agree with the licensee's statement.
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Based on the above, we agree with the iltensee's claim that the offsite power
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design characteristic of the SONGS 2/3 site is "P1" with a minimum requittu 4
SUO coping duration of four hours.
3.2 Station blackout Coping Capability The plant coping capability with an SBO event for a required duration of four hours is assessed with the following results:
1.
Condensate Inventory for Decay Heat Removal Licensce's Submittal Using the methodology described in NUMARC 87 00, the licensee stated (15) that 74,987 gallons of water would be required to remove decay heat during a four hour SBO event. This estimate is based on the maximum licensed core thermal rating of 3590 MWt for each unit. No cooldown was assumed, as the SONGS 2 and 3 SBO procedure does not require accelertted primary system cooldown to minimize reactor coolant pump leakage.
The licensee stated (13) that the minimum permissible condensate storage ur (CST) level per technical specifications provides 424,000 gallons of water. In a later submistal, the licensee stated (15) that the minimum permissible CST level per technical specifications provides 144,000 gallons of water.
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Review of 1.icensee's Submittal L
Using the expression provided in NUMARC 87 00, we estirnated that i
74,987 gallons of water would be required to remove decay heat during a four hour SBO event, assuming that no primary system cooldown is attempted. This estimate is based on the maximum licensed core thermal rating of 3590 MWt listed in the SONGS 2/3 UFSAR (12). In its calculation of reactor coolant system inventory at the end of a four hour SBO event, the licen ee assumed (15) a cooldown of approximately 30'F. Although we didn't repeat the licensee's calculations, we concur with the licensee that, based on a minimum condensate level of 144,000 gallons, the site has sufficient condensate to cope with a four hour SBO event.
2.
Class 1E Battery Capacity Licensee's Submittal In its original submittal, the licensee stated (13) that the class 1E batteries were determined to have insufficient capacity to meet SBO loads for four hours. The licensee proposed the following modifications to provide the additional capacity to meet the the proposed SBO duration:
(1) Install cable and conduit between DC Buses A and C and DC Buses B and D (but do not connect);
-(2) Modify Station proc,25 to require that during an SBO event, load group A is connected to battery C and load group B is connected to battery D with the installed cable after approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> into the SBO event (exact cross connect time window to. be determined by analysts later).
The licensee later revised its position and stated (14) that it had determined teat with the design margin removed, the existing batteries have sufficient capacity to support the SBO loads for four hours. As a 9
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,a t
result, the licensee stated that the battery load group cross connect modification identified above is no longer required to satisfy the SBO rule.
In a later submittal, the licensee provided (15) a copy of the original battery capacity calculations and load profiles, as well as the new SBO calculation package. The original b<attery sizing calculations were based on the LOVS/SIAS loading conditions with a 25% aging margin and 11% temperature margin corresponding to the minimum technical specification temperature of 60'F. The battery loading conditions under LOVS/SIAS are as follows:
Minutes Design Subsystem 01 1 90 Random Margin A
4S4.39 177.59 30.59 8.56 %
B 411.96 185.16 34.67 26.43 %
01 1 30 30 480 Random C
121.99 118.19 79.89 76.97 17.06 %
D 105.50 101.70 69.70 60 00 28.79 %
The licensee stated that the SBO load profiles are different from the LOVS/SAIS load profiles because of the following:
Operator action to strip the NSSS protection cabinet loads prior to 30 minutes Reduction of the average current drawn by the inverters due to e
voltage averaging The Shutdown Cooling System valves are not required to operate during the first four hours (60 amp reduction for channels C and D) 10
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t Start the EDGs at the end of 260 and 270 minutes for channels A and B respectively Non-operation of the EDG fuel priming pumps after the first minute For the SBO sizing calculations the licensee assumed the same 25%
aging margin and 11% temperature margin as for LOVS/SIAS.
Although no design margin is used, a 5 amp load has been added to all load profiles to accommodate future design modifications. In addition, the battery load profiles for each channel are extended to determine the maximum duration that the existing batteries can support the required SBO loads. The battery loading conditions under SBO are as follows:
Subsptem 01 1 + 30 30 260 260 261 Karutom A
483.10 163.70 130.60 206.20 30.59 01 1 30 30 270 27L 271 Random B
409.90 170.50 130.20 205.60 34.67 01 1 30 30 751 Random C
114.30 110.10 69.40 16.97 01 1 30 30-860 Random D
98.60 94.70 60.90 0
Based on the loading conditions identified above, the licensee concluded that the each of the existing batteries has sufficient capacity to support the required SBO loads for four hours.
Review of Licensee's Submittal l'
We reviewed the battery sizing calculation provided by the licensee.
We found the licensee to have properly identified and clearly stated all 11
e of the assumptions and limitations associated with the analysis. The calculations assumed an aging factor of 1.25, a temperature factor of 1.10 (or 60'F electrolyte temperature) and a design margin of 1.0. The analysis is based on the actual connected load values and as such does not allow for any future load growth. There are four 125 VDC battery channels in each unit. The licensee's calculations show that all batteries marginally meet the four hour SBO loads.
According to the UFSAR (12), battery channels A and B are sized for 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> of operation, while subsystems C and D are sized for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. No battery load profiles were provided in the UFSAR. It is our understanding that the LOVS/SIAS battery load profiles and capacity calculations contained in the licensee's submittal dated September 12, 1991 are represented in the UFSAR.
Based on a review of the licensee's battery capacity calculations for SBO loads, we conclude the following:
We found the assumption of zert parcent design margin to be inconsistent with IEEE Std 485 guidtnce, which states a 10% to 15%
design margin needs to be considered. We performed a sizing calculation of batteries channels A, B, C and D with a minimum voltage per cell of 1.81 (which is less conservative than the 1.84 volts per cell used by the licensee) and found that only batteries C and D will have sufficient design margin to conform with the guidance of IEEE Std 485.
The licensee used a reduced vital bus inverter current due to averaging the initial battery open circuit voltage with the end of duty cycle voltage. This use of a reduced inverter current is non-conservative. The licensee needs to consider the inverter citrrent need associated with the end of duty cycle voltage.
The licensee needs to clearly state what functions / instrumentation will be lost by shedding the proposed loads, and why the loss of this 12
information will not affect the operatois ability to monitor the status of the plant during the four hour coping period.
3.
Compressed Air Licensee's Submittal The licensee stated (13) that air operated valves relied upon to cope with an SBO for four hours can either be operated manually or have sufficient backup sources independent of the preferred and class 1E power supply. The licensee added that valves requiring manual operation or that need backup sources for operation are already identified in plant procedures.
In a later submittal, the licensee stated (15) that an existing handswitch in the control room will be used to control operation of the atmospheric dump valves (ADVs), and as such, local operation of these valves is not required. Pressurized gas is supplied to each powe" operated atmospheric dump valve (ADV) in the form of bottled nitrogen which, upon a loss of pressure in the normal instrument air supply to the ADVs, automatically supplies nitrogen to the dump valves. Each accumulator is required to maintain sufficient nitrogen gas for each ADV to have at least 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of pneumatic operation, if manual operation were required, however, the emergency lighting (powered by its own separate 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> battery pack) in the ADV area is sufficient to perform ADV operation via a handwheel during an SBO event.
Review of Licensee's Submittal-According to the UFSAR (12), the auxiliary feedwater lines in the.
turbine driven auxiliary feedwater pump train are equipped with DC motor-eperated control and isolation valves.
With regard to steam relief to the atmosphere, the licensee stated that it will be accomplished remotely from an existing handswitch and hand.
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indicating controller in the control room. Battled nitrogen tanks with an eight hour capacity will automatically supply nitrogen to the ADVs i
1 upon a loss of power. In addition, the capability exists for local manual operation of the ADVs. Based on these facts, we agree with the licensee's assertion that the ADVs can be operated successfully during an SBO event, therefore the plant does not require additional backup compressed air during an SBO event.
4.
EfIcets of Loss of Ventilation Licensee's Submittal The licensee stated (15) that time-dependent heat transfer analyses was used to determine room temperature rise in plant compartments following an SBO. This method was based on a specific lumped parameter model and assumes only poured concrete walls as heat sinks. The licensee contends that this model is overly conservative because it predicts only the steady state compartrrent temperature and does not allow credit for heat which will be dissipated in plaster walls, ceilings and compartment air mass. In addition, as part of the analysis, SBO temperature rise calculations based on NUMARC 87 00 methods were also provided.
The licensee identified the following as dominant areas of concern:
1)
AFW Pump Room 2)
Distribution (Inverter) Rooms (4 for each unit) 3)
Switchgear Rooms (2 for each unit) 4)
Control Room Cabinet Area (Common) 5)
Control Room (common) 4 In its room heatup analyses for the Distribution and Switchgear rooms, the licensee only analyzed (15) the rooms with the highest heat load (Switchgear Room #302A and Distribution Room #3108).
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The areas that were considered but eliminated as DACs were the batterv rooms and the atmospheric dump and steam relief valve areas. The battery rooms were dismissed as DACs because NUMARC 87 00 guidance does not consider battery rooms as DACs. For San Onofre 2 and 3, the atmospheric dump and steam relief valves are located outdoors, and were not considered DACs.
The control room loss of ventilation calculation was only performed for one hour, as it was assumed that after one hour the control room HVAC would be provided by the non blacked out_ unit's diesel.
The licensee stated (15) that a containment heatup analysis during an SBO has not been performed. The licensee added that the containment l
heat loads resulting from a Reactor Coolant System leakage of 11 gpm are well below the heat loads assumed in the LOCA/ HELD analysis, and thus, no additional analyses were performed.
l The results of the licensee's time dependent room heatup analyses and l
the and corresponding result using NUMARC 87 00 are summarized in Table 1.
The licensee stated (13) that reasonable assurance of the operability of SBO response equipment in the above DACs has been assessed using Appendix F to NUMARC 87 00 and concluded that no modifications or associated procedures are necessary to provide reasonable assurance of l
equipment operability during an SBO event.
1 Review of Licensee's Submittal i
l We assume that the computer code used by the licensee in its tim,e-l l
dependent heat transfer analyses has afready been verified and validated through the licensee's own q ality assurance program. As j
we did not have access to the computer code used by the licensee in its j
calculations, the assumptions and results of the licensee's calculations were reviewed and compared to the NUMARC 87-00 calculated temperatures. The licensee stated that the Control Room'will have 1
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Table 1: Summary af hic Room licatup Analysis Results Licensee's Time dependent NUhtARC 874)
Inillal Temp.
Analysis Result (H Steady State Rctrn
(* F) 1 hr 4 his Temp ('D Switchgear Room 95 96.8 101.4 Distribution Room -
95 118.5 138.2 Computer Room 72 163.9 192.8 ATW Pump Room 1 04 107.4 114.2 Control Room Cabinet Area 75 111.1 '
140.6 Control Room Area 75 114.6
- 151.9 The licensee stated that HVAC would be available to the Control Room within one hour.
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f HVAC available after one hour. The plant UFSAR states (12) that there is a common control room shared by both units. This room is cooled by a single train of normal HVAC and two 1004 capacity redundant subsystems of emergency HVAC. One emergency subsystem is on l
emergency power train A and the other is on train B. For the control room to have an emergency HVAC train available during an SBO, each subsystem has to be connectible to the same emergency power supply train from each unit. However, we were unable to confirm this connectability from the information available in the plant UFSAR (12).
The !!censee needs to verify that such connectability exists.
Our review of the information provided by the licensee reveals the following concerns:
AFW Pump Room:
Upon review of the licensee's heatup analysis for the AFW pump room, we found the assumed heat loads, areas, and calculating assumptions to be reasonable. In addition, the calculated final temperature was consistent with the final calculated temperature using NUMARC 87 00 methodology. Based on the above, we accept the licensee's calculated SBO temperature for the AFW pump room.
j Containment:
The licensee concluded that the containment heatup during an SBO was enveloped by the LOCA/ HELD analysis, based on the expected heat loads resulting from an assumed RCS leakage of 11 gpm The licensee's assumption of 11 gpm RCS leakage is non-conservative. The licensee needs to recalculate the expected containment heat loads resulting from an assumed RCS leak rate of 111 gpm, consistent with the guidance, and verify that the expected temperature in the containment is enveloped by the LOCA/ HELD temperature profiles.
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Control Buildine Rooms:
(Switchgear Room, Distribution Room, Computer Room, Control Room, Control Room Cabinet Area) i Our review of the remaining rooms evaluated by the licensee, all of which are located in the Control Building, resulted in several concerns with regard to the licensee's methodology and assumptions. Our concerns are as follows:
The licensee used normal operating design temperatures as the initial temperatures in its room heatup calculations. In many cases these temperatures were non conservative (i.e. Computer rooin -
72'F, Control room and control room cabinet area 75'F). The licensee needs to use as an initial temperature the maximum temperature allowed by technical specifications. The licensee can choose a lower temperature as an initial temperature if it provides administrative controls to ensure that the room temperature will not exceed this temperature under any circumstances during normal plant operation.
For its heatup calculations, the licensee assumed that the air temperature in the surrounding rooms did not changa during the SBO event. The licensee needs to confirm that this is the case, and for those rooms in which the temperature is expected to rise during an SBO event, the licensee needs to use the maximum expected temperature for these rooms.
Throughout the calculations, the licensee assumes a concrete thermal conductivity of 1.04 (Btu /hr ft 'F). This value has previously been considered too high and therefore non-conservative for SBO analysis. A more appropriate and accept'able value of 0.7 needs to be used.
The licensee assumed non conservative and inconsistent values for the total volume area which was taken by beams, raised floors, 18
suspended ceilings, equipment, supports, etc. These values ranged from 27o to IDE The licensee needs to either measure these a eas directly, or use a conservative assumption such as 107e if these areas are not known.
The licensee needs to provide a technical justification for its o
2 assumption of a constant hair f 1.47 BTU /hr-ft.oF for all rooms and all heat conducting surfaces. Natural Convection Heat Transfer Coefficients for air are affected by surface orientation (i.e. vertical or horizontal), air properties, system geometry, and air to-surface temperature difference. Depending on these parameters, the value 2
for hair could range from 0.1 to 10.0 BTU /hr-ft.'F The licensee needs to use a justifiably conservative (i.e. low) value of hair for this analysis if a single constant value is to be used throughout the calculations.
The use of 3/4 inch and 1 inch thick gypsum plasterboard as being equivalent to one or two foot thick concrete is incorrect for heat transfer calculations. The gypsum plaster does not provide as high a heat capacity as concrete. All of the analyses which credit gypsum as having the heat capacity of concrete need to be reperformed either with 'he gypsum surface area removed or explicitly accounted for with its own thermal properties and wall thickness.
The licensee needs to provide a technical justification for the selection of a al of one minute and a Ax of one inch (0.0833 feet)in the methodology. A sensitivity study in which these parameters are varied would provide evidence that these particular values af al and Ax are suitably conservative for this analysis.
The licensee assumed four people would occupy the control room during an SBO event with a heat source of 250 Blu/hr person..The heat load assumed by the licensee is non conservative. A more appropriate value of 250 Watts (853 Blu/hr) needs to be used, as recommended by the ASHRAE handbook In addition, the licensee needs to justify the assumption that only four persons will occupy 19
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I the control room during an SBO. Our experience suggests that a value of ten persons is more appropriate.
Assuming a heat load of 250 Watts per person for ten people results in a total personnel heat source of approximately 8500 Btu /hr, compared to 1000 Btu /hr assumed by the licensee.
In its control room heatup analysis, the licensee assumed a total heat source of 90,000 Btu /hr consisting of 1000 Btu /hr from personnel,17,%5 Btu /hr from lights and 71755A Btu /hr from equipment. Based on our experience with similst two unit sites with shared control rooms, this heat load appears to be too low.
Based upon the loads identified (15) by the licensee for each inverter and information contained in the plant UFSAR (12), we conclude that the control room heat load identified by the licenece is non-conservative. Our calculations indicate that the total load is more than a factor of two larger than what was assumed by se licar we.
Thus, the licensee needs to provide justification for its assume -
control room heat load and perform a new control room heatu}s analysis,if necessary.
The licensee states (15) that the control room panels face the Control Room Cabinet area. In its heat transfer analyses, the licensee assumed that 50% of the heat loss from the Control Room panels are dissipated to the Control Room cabinet area and that 100% of the heat loss is dissipated to the Control Room area. This assumption is non conservative. The licensee needs to assume that 100% of the heat loss is dissipated to both the Control Room area and Control l
Room Cabinet area.
I t
Based on the concerns raised above, the licensee needs to re assess the temperature rise analyses for all Control Building rooms containing SBO equipment (i.e. Switchgear Room, Distribution Room, Computer Room, Control Room, Control Room Cabinet Area) and verify that there is reasonable assurance of the operability of SBO equipment in these areas.
E 20
5.
Containment Isolation Licensee's Submittal The licensee stated (13) that the plant list of containment isolation valves (CIVs) has been reviewed to verify that valves which must be capable of being closed or that must be operated (cycled) under station blackout conditions can be positioned with indication independent of the preferred and blacked out unit's class 1E power supplies. The licensee stated that no plant modifications and associated procedure changes were determined to be required.
The licensee stated (14) that it has included two additional criteria for exclusion of CIVs, as follows:
(1)
Valves which are redundant to an isolation valve which meets the NUMARC exclusion criteria. This is based on NUMARC's response to Question 101 in Enclosure D of their October 27,1988 letter.
(2)
Valves that are "always" or "normally" closed but not " locked closed".
In a later submittal, the licensee provided a list of valves which it had determined could not be excluded using the five exclusion criteria of R.G.1.155 and an explanation of how these valves would be assured of being closed during an SBO event.
Review of Licensee's Submittal Using information contained in UFSAR Table 6.2 35 (12) we reviewed the list of plant CIVs to determine those which could not be excluded from consideration using the five criteria of R.G.1.155. Our review identified the containment sump recirculation line valves outside containment, HV 9302 and HV 9303, as the only valves which could 21
~ Q~.i A.,.
not be excluded. These penetrations contain a motor operated butterfly valve which is normally closed and fails as is upon loss of AC power.
In its response to a question, the licensee stated (15) that these valves will not be open during the normal plant operation. The licensee added that the valves are normally closed, they are not tested and their position is monitored during every shift. We consider the licensee's justifications with regard to the exclusion of these valves to be consistent with the intent of RG 1.155.
In addition, the list of valves which the licensee concluded (15) in its September 12,1991 submittal could not be excluded using the five exclusion criteria of R.G.1.155 were examined. Our review indicates that with the exception of the containment sump recirculation line valves addressed above all other valves identified by the licensee, either have a fall closed valve or a check valve in the penetration line which allows exclusion under RG 1.155 guidance.
Thus, we conclude that all valves which must be capable of being_
closed or that must be operated (cycled) under station blackout conditions can be positioned with indication independent of the preferred and blacked-out unit's class 1E power supplies.
6.
Reactor Coolant Inventory Licensee's Submittal The licensee stated (13) that the ability to maintain adequate reactor coolant system (RCS) inventory to ensure that the core is cooled has been assessed for four hours. The generic analyses listed in Section 2.5.2 of NUMARC 87-00 were used for this assessment. The expected rates of reactor coolant inventory loss under SBO conditions did not result in core uncovery in an SBO of four hours.
In a later submittal, the licensee stated (14) the SONGS 2/3 RCP seals were designed to have no significant degradation as a result of a four 22
t% e hour SBO event, and as such, RCP seal leakage was assumed not to increase during an SBO event. The licensee stated that the vendor data, including actual test results, demonstrates that the RCP seal leakage will not increase during an SBO event.
In its analysis, the reactor is assumed (15) to be operating at 100% power for 100 days at normal operating conditions at the time of the occurrence of SBO. Normal operating conditions include primary pressure of 2250 psia, RCS cold leg temperature of 557.5'F, RCS hot leg temperature of 608'F and RCS water volume of 82,000 gallons.
The initial RCS leakage assumed by the licensee during SBO is 11 gpm which is reduced during the coping period as RCS pressure decreases.
The licensee stated (15) that it has tested the RCP seals and the results indicate that no appreciable sealleakage would exist at the end of a four hour SBO. Therefore, the RCP seal leakage during an SBO will remain within the 11 gpm total RCP seal leakage allowed by technical specifications and no additional RCP sealleakage needs to be assumed.
At the end of the coping duration the licensee assumed a primary pressure of 1300 psia, RCS cold leg temperature of 53PF, RCS hot leg temperature of 557.5'F and a reduced RCP seal rate of 6.5 gpm. The licensee stated that during the four hour coping period, the pressurizer level slowly decreases as RCS pressure drops, however, the pressurizer does not empty during the entire four hour coping period. The final RCS water volume, neglecting Safety Injection tank inventory, will be 76,000 gallons. This remaining volume is greater than the volume of water the licensee stated was required to cover the core of 20,000 gallons 3
(2674ft).
The licensee also performed a reactor inventory calculation assuming a 25 gpm leak rate from each RCP seal (100 gpm totaD ~he results of this higher leak rate analysis also demonstrate that the reactor core would remain co"ered during a four hour SBO event.
Review of Licensee's Submittal The licensee's use of a generic analysis without specific justification of its applicability to the plant is not acceptable. We performed an independent evaluation of RCS inventory using information available in the plant UFSAR (12) and the licensee's submittals.
The licensee's assumed RCS leakage of 11 gpm in its RCS inventory calculation is non conservative and inconsistent with the guidance provided in NRC Ceneric bue 23. In order to conform to the guidance, the licensee should consider 25 gpm per reactor coolant pump in addition to the '; gpm technical specification leakage.
Using the information provided by the licensee above and assuming a total leak rate of 111 gpm, we calculated the volume of water remaining in the core at the end of a four hour SBO to be 5717 ft. This 3
3 o cover the core reported by exceeds the required volume of 2674 ft t
the licensee. Thus, despite our lack of agreement with the licensee's approach, we conclude that the core will not be uncovered during a four hour 500 event.
NOTE:
The 25 gpm RCP seal leak rats was agreed to between NUMARC and the NRC staff pending resolution of Generic Issue (GI) 23. If the final resolution of GI 23 defines higher RCP seal leak rates than assumed for the RCS inventory evaluation, the licensee i
needs to be aware of the potential impact of this resolution on its l
analyses and actions addressing conformance to the SBO rule.
3.3 Proposed Procedure and Training Licensee's Submittal The licensee stated (13) that plant procedures have been reviewed and that changes necessary to meet NUMARC 87 00 will be implemented in.the following areas:
R6
E..
1 i
i Station blackout response - SBO response procedure 502313.1 will be l
reviewed and modified as necessary per NUhiARC 87-00, Section 4.2.1; AC power restoration procedure 502/3-13.1," Station Blackout" will be revised per NUhiARC 87 00, Section 4.2.2-Severe weather SCE will develop a severe weather response procedure per NUhiARC 87-00, Section 4.2.3 Coping Procedures - minor procedure changes will be implemented in the SBO response procedure to ensure that all of the provisions of NUhf ARC 87 00, Section 7 are included.
The licensee added that procedure changes associated with any modifications required after assessing coping capability per NUhiARC 87-00, Section 7, will be completed within two years after the notification provided by the staff in accordance with 10CFR 50.63 (c)(3).
Review of Licensee's Submittal We neither received nor reviewed the affected procedures, although several procedure changes have been identified as being required to maintain containment integrity under SBO conditions. We consider these procedures to be plant-specific actions concerning the required activities to cope with an SBO. It is the licensee's responsibility to revise and implement these procedures, as needed, to mitigate an SBO event and to assure that these procedures are complete and correct, and that the associated training needs are carried out accordingly.
... o 3.4 Proposed Modification Licensee's Submittal The licensee did not identify any modifications to assure a four hour coping capability as being necessary.
Review of Licensee's Submittal Our evaluation found several areas where the licensee needs to perform re-evaluations, some of these may result in modifications / changes to the existing equipment.
3.5 Quality Assurance and Technical Specifications Licensee's Submittal The licensee stated (15) that when compiling the SBO analysis it compiled a list of all equipment that would be required to operate during the four hour SBO coping duration. The licensee added that the QA classification of each component on this list was reviewed to ensure that the classification was consistent with the provisions of RG 1,155, Regulatory Position 3.5. The' licensee concluded that all equipment on the list was identified as Quality Class 11 and is covered under 10 CFR 50 Appendix B.
Review of Licensee's Submittal l
The licensee did not provide any information on this issue for us to review, therefore, we cannot confirm the adequacy of the evaluation. The licensee l
needs to include its review of QA needs for the SBO equipment as part of the l
plant SBO supporting documentation for future NRC audit review.
With regard to Technical Specifications, the licensee did not state how the plant SBO equipment complies with the guidance of R.G.1.155, Appendix B.
l 26
'...n i
4.0 CONCLUSION
S Based on our review of the licensee's submittals and the information available in the UFSAR for San Onofre Unit 2 and 3, we find that the submittal
~
conforms with the requirements of the SBO rule and the guidance of RG 1.155 with the following exceptions:
1.
Class 1E Battery Capacity Based on a review of the licensee's battery capacity calculations for SBO loads, we condude the following:
We found the assumption of zero percent design margin to be inconsistent with IEEE Std 485 guidance, which states a 10% to 15%
design margin needs to be considered. We performed a sizing calculation of batteries channels A, B, C and D with a minimum voltage per cell of 1.81 (which is less conservative than the 1.84 volts per cell used by the licensee) and found that only batteries C and D will have sufficient design margin to conform with the guidance of IEEE Std-485.
The licensee used a reduced vital bus inverter current due to averaging the initial battery open circuit voltage with the end of l
duty cycle voltage. This use of a reduced inverter current is non-conservative. The licensee needs to consider the inverter current l
need associated with the end of duty cycle voltage.
The licensee needs to clearly state what functions / instrumentation l
will be lost by shedding the proposed loads, and why the loss of this information will not affect the operators ability to monitor the status of the plant during the four hour coping period.
27
o 6 2.
Effects of Loss of Ventilation Our review of the temperature rise calculations provided by the licensee identified several concerns which invalidated the licensee's results for those rooms contained in the Control Building (see Section 3.2). Based on the concerns raised above, the licensee needs to re-assess the temperature rise analyses for all Control Building rooms containing SBO equipment (i.e. Switchgear Room, Distribution Room, Computer Room, Control Room, Control Room Cabinet Area) and j
verify that there is reasonable assurance of the operability of SBO i
equipment in these areas.
With regard to the control room and Control Room Cabinet Area, we were unable to confirm this connectability from the information available in the plant UFSAR (12). The licensee needs to verify that such connectability exists.
With regard to the containment, the licensee concluded that the containment heatup during an SBO were enveloped by the LOCA/ HELD analysis, based on the expected heat loads resulting from an assumed RCS leakage of 11 gpm. The licensee's assumption of 11 gpm RCS leakage is non conservative. The licensee needs to recalculate the expected containment heat loads resulting from an assumed RCS leak rate of 111 gpm, cc.isistent with the guidance, and verify that these expected loads are enveloped by the LOCA/HELB analysis.
3.
Proposed Modification Our review has identified several areas where the licensee needs to perform re-evaluations, some of which may result m modifications / changes to the existing equipment.
l 28 j
(
'..o l
.s l
4.
Quality Assurance and Technical Specifications I'
The licensee stated (15) that it has reviewed the QA classification of all required SBO equipment and has concluded that the classification was consistent with the provisions of RG 1.155, Regulatory Position 3.5.
The licensee did not provide any information on this issue for us to review, therefore, we cannot confirm the adequacy of the evaluation.
The lleensee nceds to include its review of QA needs for the SBO equipment as part of the plant SBO supporting documentation for future NRC audit review.
With regard to Technical Specifications, the licensee did not state how the plant SBO equipment complies with the guidance of R.G.1.155, Appendix B.
.D
's on
5.0 REFERENCES
1.
The Office of Federal Register, " Code of Federal Regulations Title 10 Part 50.63," 10 CFR 50.63, January 1,1989.
2.
U.S. Nuclear Regulatory Commission, " Evaluation of Station Blackout Accidents at Nuclear Power Plants Technical Findings Related to Unresolved Safety Issue A 44," NUREG 1032, Baranowsky, P.W., June 1988.
3.
U.S. Nuclear Regulatory Commission, " Collection and Evaluation of Complete and Partial Losses of Offsite Power at Nuclear Power Plants,"
NUREG/CR 3992, February 1985.
4.
U.S. Nuclear Regulatory Commission," Reliability of Emergency AC Power System at Nuclear Power Plants," NUREG/CR 2989, July 1983.
5.
U.S. Nuclear Regulatory Commission, " Emergency Diesel Generator Operating Experience, 1981 1983," NUREG/CR 4347, December 1985.
6.
U.S. Nuclear Regulatory Commission, " Station Blackout Accident Analyses (Part of NRC Task Action Plan A-44)," NUREG/CR 3226, hiay 1983.
7.
U.S. Nuclear Regulatory Commission Office of Nuclear Regulatory Research,
" Regulatory Guide 1.155 Station Blackout," August 1988.
8.
Nuclear hianagement and Resources Council, Inc., " Guidelines and Technical Bases for NUhiARC Initiatives Addressing Station Blackout at Light Water Reactors," NUhiARC 87-00, November 1987.
9.
Nuclear Safety Analysis Center,"The Reliability of Emergency Diesel Generators at U.S. Nuclear Power Plants," NSAC-108, Wyckoff, H., September 1986.
10.
Thadani, A. C., Letter to W. H. Rasin of NUhiARC, " Approval of NUhiARC Documents on Station Blackout (TAC-40577)," dated October 7,1988, f
on
. r o se e
11.
Thadani, A. C., letter to A. Marion of NUhiARC, Publicly Noticed hiecting December 27,1989," dated January 3,1990, (Confirming "NUhiARC 87 00 Supplemental Questions / Answers," December 27,1989).
12.
San Onofre Nuclear Generating Station Units 2 and 3 Updated Final Safety Analysis Report (UFSAR).
13.
hiedford, hi. O., letter to NRC Document Control Desk, " Response to 10 CFR 50.63, ' Loss of all Alternating Current Power,' San Onofre Nuclear Generating Station," Docket Nos. 50-361,50 362, dated April 17,1989.
14.
Nandy, F. R., letter to NRC Document Control Desk, " Supplemental Response to 10 CFR 50.63, ' Loss of all Alternating Current Power,' San Onofre Nuclear Generating Station," Docket Nos. 50-361,50-362, dated April 17,1989.
15.
R. hi. Rosenblum, letter to NRC Document Control Desk, " Station Blackout Analysis for San Onofre Nuclear Generating Station," Docket Nos. 50-361, 50-362, dated September 12,1991.
e 31
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