ML20082G252
| ML20082G252 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 05/31/1991 |
| From: | SCIENCE APPLICATIONS INTERNATIONAL CORP. (FORMERLY |
| To: | NRC |
| Shared Package | |
| ML20082G254 | List: |
| References | |
| CON-NRC-03-87-029, CON-NRC-3-87-29 SAIC-91-6663, TAC-68534, NUDOCS 9108160273 | |
| Download: ML20082G252 (31) | |
Text
Attachment 4
SAIC-91/6663 TECMICAL EVALUATION REPORT COOPER NUCLEAR STATION STATION BLACKOUT EVALUATION TAC No. 68534 SAIG" Science Applications International Corporation An Employee Owned Company Final May 31, 1991 Prepared for:
U.S. Nucleat Regulatory Commission
- WasMngton, D.C. 20555 Contract NRC-03-87-029 Task Order No. 38 g
l S6i 3 / 6 fj ) ') }
Post Once Box 1303.1710 Goodndpe Dnve. McLean. Vorprua 22102 (703) 8214300
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l TABLE OF CONTENTS i
i Section pgg
1.0 BACKGROUND
1 2.0 REVIEW PROCESS.......................................
3 3.0 EVALUATION...........................................
6 3.1 Proposed Station Blackout Duration.............
6 3.2 Station Blackout Coping Capability..............
10 3.3 Proposed Procedures and Training................
22 3.4 Proposed Modifications..........................
23 3.5 Quality Assurance and Technical Specifications..
23
4.0 CONCLUSION
S 24
5.0 REFERENCES
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I TECHNICAL EVALUATION REPORT COOPER NUCLEAR STATION STATION BLACK 0UT EVALUATION-i
1.0 BACKGROUND
On July 21, 1988, the Nuclear Regulatory Comission (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).
t 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 detailed guidelines and procedures on how to assess each plant's capabilities to comply with the SB0 rule. The NRC staff reviewed the guidelines and analysis methodology in NUMARC 87-00 and concluded 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 SB0 duration capability from two to siy'.een 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 loss of offsite power (LOOP), and the prabable time to restore offsite power.
In order to achieve a consistent systematic response from licensees to the SB0 rule and to expedite the staff review process, NUMARC developed two
+
generic response documents. These documents were reviewed and endorsed (9) 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 forzats, provides only a sumary 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 SB0 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 SB0 rule.
.In 1989, a joint NRC/SAIC team headed by an NRC staff member performed audit re.,ews 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 regardino the degree of licensees' conformance to the requirements of the SB0 rule. To resolve tids question, on January 4,1990, NUMARC issued additional guidance as NUMARC 87-00 Supplemental Questions / Answers (10) 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.
2
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 SB0 duration (Section 3.1),
B.
SB0 coping capability (Section 3.2),
C.
Procedures and training for SB0 (Section 3.4),
D.
Proposed modifications (Section 3.3), and E.
Quality assurance and technical specifications for SB0 equipment (Section 3.5).
For the determination of the proposed minimum acceptable SB0 duration, the following factors in the licensee's submittal are reviewed:
a) offsite power design characteristics, b) emergency AC power system configuration, c) deiermination of the emergency diesel generator (EDG) reliability consistent with NSAC-108 criteria (11), 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 SB0 coping capability, the licensee's submittal is reviewed to assess the availability, adequacy and capability of the plant systems and components needed to achieve and maintain a safe shutdown condition and recover from an SB0 of acceptable C ation which is determined above. The review process follows the guidelines given in RG 1.155, Sect 4on 3.2, to assure:
a.
availability of sufficient condensate inventory for decay heat
- removal, 3
4 b.
adequacy of the class IE battery capacity to support safe
- shutdown, c.
availability of adequate compressed air for air-operated valves necessary for safe shutdown, d.
adequacy of the ventilation systems in the vital and/or dominant areas that include equipment necessary for safe shutdown of the
- plant, e.
ability to provide appropriate containment integrity, and f.
ability of the plant to maintain adequate reactor coolant system inventory to ensure core cooling for the required coping duration.
The licensee's submittal is reviewed to verify that required procedures (i.e., revised existing and new) for coping with SB0 are identified and that appropriate operator training will be provided.
The licensee's submittal for a.ny proposed modifications to emergency AC sources, battery capacity, condensate capacity, compressed air capacity, ventilation system for equipment operability, containment isolation 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 SB0 rule, are assessed for their adequacy.
This SB0 evaluation is based upon the re" ew of the licensee's submittals dated April 17, 1989 (12), August 3, 1989 (13), and March 23, 1990 (15), a telephone conversation between the NRC/SAIC and the licensee staff, the licensee's response to the questions raisted during the telephone conversation dated January 16, 1991 (16), and the information available in the plant Updated Safety Analysis Report (USAR) (14); 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 4
O would be made and the audit would be scheduled and performed by the NRC staff i
at some later date, I
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. 3.0 EVALUATION
- 3.1 Proposed Station Blackout Duration Licensee's submittal The licensee, Nebraska Public Power District (NPPD), calculated (12,13 and 15) a minimum acceptable station blackout duration of four hours for the Cooper Nuclear Station (CNS). The licensee stated that no modifications are required to attain this coping duration.
The plant factors used to estimate the proposed SB0 duration are:
1.
Offsite Power Design Characteristics The plant AC power design characteristic group is "P1" based on:
a.
Independence of the plant offsite-power system characteristics of "I 1/2,"
b.
Expected' frequency of grid-related LOOPS of less than one per 20 years, c.
Estimated frequency of LOOPS due to extreaely severe weather
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(ESW) which places the plant in ESW Group "1,"
and d.
Estimated frequency of LOOPS due-to severe weather (SW)-
which places the plant in SW Group "2."
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-2.
Emergency AC (EAC) Power Configuration Group The EAC power configuration of the plant is "C."
CNS is equipped with two emergency diesel generators, one of which is necessary to operate safe-shutdown equipment following a loss of offsite power.
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3.
TargetEmergencyDieselGenerator(EDG) Reliability The licensee has selected a target EDG reliability of 0.95. The selection of this target reliability is based on having an average EOG reliability of greater than 0.95 for the last 100 demands consistent with NUMARC 87-00, S(ction 3.2.4.
Review of Licensee's Submittal Factors which affect the estimation of the SB0 coping duration are:
the independence of the offsite power system grouping, the estituated frequency of LOOPS due to ESW and SW conditions, the expected frequency of grid-related LOOP 3, the classification of EAC, and the selection of EDG target reliability.
The licensee stated that the independence of the plant offsite power system grouping is "I 1/2." A review of the CNS USAR indicates that:
1.
Offsite power sources are connected to the unit through.two electrically connected switchyards (345 and 161 kV) and one independent 69 kV power line; 2.
The normal source of AC power is from the unit main generator 3
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through the Normal Station Service Transformer (NSST);
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3.
Upon loss of power from the main generator, there is an automatic transfer to the first preferred power source (161 kV sub station),
i through the Start-up Station Service Transformer (SSST); and i
4.
The emergency AC power line (69 kV) through the Emergency Station
[.
Service Transformer (ESST) provides the second choice for preferred AC power. Control Circuitry is arranged so that upon loss of power from both the normal and the start-up power sources the ESF buses will be powered by the ESST via an automatic transfer.
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. -, _ _,_ _.._ __ _.~. _, _
t Based on the above and the criteria stated in Table 5 of RG 1.155, we conclude that the plant independence of offsite power system group is "1 1."
There are two emergency AC power supplies at CNS and only one EAC power supply is necessary to operate safe shutdown equipment following a loss of offsite power.
Therefore, the EAC classification of CNS is "C."
Yhe licensee selected a target EDG reliability of 0.95 based on having a unit average EDG reliability of greater than 0.95 for the last 100 demands. Although this selection is consistent with the criteria given in both the RG 1.155 and NUMARC 87-00, the licensee needs to evaluate the EDG reliability for the last 20 and 50 demands as well.
These statistics are only available on site for review, therefore, we are unable to verify the assignment of the EDG target reliability at this time.
However, based on the information in the NSAC-108, which gives the EDG reliability data at U.S. nuclear reactors for calendar years 1983 to 1985, the EDGs at CNS exprience an average reliability of 0.967 per diesel per year. Using this data, it appears that the target EDG reliability selected by the licensee (15) is appropriate.
With regard to EDG reliability program, the licensee stated (15) that it will utilize NUMARC 87-00 Appendix D, as the guidance document for the CNS EDG maintenance and reliability program. The licensee added that the selected target reliability will be maintained.
With regard to the expected frequency of grid-related LOOPS at the site, we can not confirm the stated results. The available information in NUREG/CR-3992 (3), which gives a compendium of information on the loss of offsite power at nuclear power plants in the U.S., indicates that CNS did not have any symptomatic grid-related LOOP prior to the calenda'r year 1984.
In the absence of any contradictory information, we agree with the licensee's statement.
8 1
The licensee initially stated (12) that the frequency of LOOPS due to the SW and ESW conditions place the site in an offsite power characterittic "P2," and selected an EDG target reliability of 0.975.
In its subsequent submittals (13 and 15), the licensee revised the SW grouping from "3" to "2," the ESW grouping from "3" to "1," and changed the target EDG reliability to 0.95.
The licensee stated that the revised SW and ESW groupings are based on a weather data related to the site. The licensee also provided (16) its calculation of SW and ESW frequency.
Our review of the licensee's calculations of SW and ESW frequency indicates that the results are based on a limited weather data which does not provide a good estimate of extreme conditions.
For example, the licensee used a 13-years wind data, (from 1975 to 1987), to estimate the expected frequency of storms with winds between 75 and 125 mph. The maximum wind speed in this data set is 48.4 mph. The licensee used this data point to estimate storm frequency of higher winds.
This estimate (1/13 0.077) of storm frequency is a factor of 6.5 smaller than that provided in Table 3-3 of NUMRC 87-00.
The contribution of the expected frequency of the storms with winds between 75 and 125, using the NUMRC data, is almost 50% of the total estimated frequency of LOOPS due to SW conditions at the site. The licensee's approach only contributes -12%.
Based on a discussion with the NRC staff, who provided the data given in NU M RC, the licensea's estimate of storm frequency is low and does not represent the extreme condition. The staff added that the licensee can use the 13-years data and perfom a Bayesian update of the data given in NUMRC. Otherwise, the NU M RC data should be used.
With regard to the estimation of the frequency of an ESW condition at the site, the licensee used the National Severe Storms Forecast Center Tornado Data to estimate the frequency of storns with winds of greater than 125 mph. The data covered the tornadoes within the 125 nautical miles of Brownsville Nebraska from 1950 to 1980. Using this data, the 9
i
-licensee estimated the tornado winds in excess of:113 mph to have an occurrence-frequency of 2.3S7E-04 per year, or 1 in 4243 years.
The NUMARC data estimate the storm frequency for_ greater than 125 mph as
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1.40E-03 per year, or 1 in 700 yea.s. The staff stated that the data in i
'NUMARC is based on Type-1 (extrene distribution) sustained wind of 124.5 h
sph occurring at Omaha Nebraska.
In addition, the staff stated that the tornado winds can not be used to estimate the ESW sustained winds.
i n
Based on the above the licensee needs to use data provided in NUMARC, f-i.e. ESW group "3" and SW group "3," or perfors n analysis justifying _
the differences with that provided in NUMARC.
In the absence of such l--
analysis, we consider the site offsite power characteristic to be "P2" requiring an EDG target reliability of 0.975 for a coping duration of I
four hours.- (This conclusion is consistent with the licensee's initial
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assessment of the offsite power characteristic, the EDG 'trget
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reliability, and the required coping duration.)
i-i 3.2 Station Blackout Coping Capability The plant coping capability with an SB0 event for the required duration of four hours is assessed based on the following results:
1.
Condensate Inventory for Decay Heat Removal Licensee's Submittal The licensee revised its initial submittal of the condensate inventory calculation by considering the' supplemental guidance regarding the assumption of the recirculation pump seal-leakage during an SB0 event.
In this calculation, the licensee used 25 gpm seal leak rate per pump and estimated that 64,668 gallons of water would be required to remove decay heat during.the 4-hour SB0 event.
the license stated that the minimum permissible condensate ctorage tank (CST) level identified in the USAR provides 100,00?
10
1 gallons of water which exceeds the required quantity for coping with a 4-hour SB0 event.
The licensee stated (16) that it has an a mlysis which confirms that the pressure suppression pool (PSP) b a average temperature would not exceed the heat capacity temperature limit during an SB0 event. This analysis was performed in tandem with the DC power system upgrade in 1987 using the IDCOR Modular Accident Analysis Program (MAAP) code. Assuming an initial PSP temperature of 90'F with no reactor coolant system (R;S) leakage other than the steam release through the relief valves to the PSP, the code calculated a final PSP temperature of 155 F after four hours into the accident. The licensee added that the average reactor pressure in the analysis was 1040 psia. At 1070 psia, the PSP heat capacity temperature limit (HCTL) is approximately 175'F, therefore, no reactor depressurization is needed.
Review of Licensee's Submittal Using the expression provided in NUMARC 87-00, we estimated that
-68,350 gallons of condensate are required to remove decay heat and compensate for the assumed RCS leakage of 61 gpm (18 gpm per pump plus 25 gpm technical specification maximum allowed leakage) during a 4-hour SB0 event. This estimate is based on the maximum anticipated thermal output of 2428 MWt, or 102% of 2381 licensed MWt. The licensee stated that the CNS USAR requires a minimum CST level of 100,000 gallons. The licen'ee needs to verify that this amount (100,000 gallons) of water will be available in the CST during plant operation.
Pending this verification, we consider that the plant has sufficient condensate inventory to cope with an SB0 of four hours duration.
With regard to the PSP final average bulk temperature, we performed an independent evaluation of adiabatic pool temperature rise due to the addition of decay heat.
Using an initial pool 11 1
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temperature of 90'F, the final pool temperature of 172'T was calculated. Our calculation indicates that the final temperature would still ue less than the 175'F HCTL limit even though we did not consider any heat transfer to the torus wall. This calculation assumes that the RCS leakage and the associated energy will be dumped into the drywell. Keeping the reactor pressure below 1000 psia allows higher PSP temperature to exist before further pressure reduction be needed. Therefore, we agree with the licensee that, from the technical specification limit on the reactor vessel pressure during the reactor isolation point ef view, the depressurization of the reactor vessel would not be needed during an SB0 event.
2.
Class IE Battery capacity Licensee's submittal The licensee stated that the CNS battery-capacity calculations were performed pursuant to NUKARC 87-00. Section 7.2.2.
These calculations were performed consistent with IEEE Std 485 and utilized 70 F electrolyte temperature correction factor. The results document that the CNS 125-V and 250-V batteries have sufficient capacity to meet the statior, blackout loads for four hours without any " required" load stripping.
Additionally, the AC breaker control loads, required after the four hour SB0 event were included as a part of the battery-capacity calculation.
During the telephone conversation on January 16, 1991, the licensee stated that no load shedding is required to maintain sufficient battery capacity for a 4-hour SB0 event.
Review of Licensee's Submittal The DC power systems (125-V for power and control and 250-V for power) supply DC power to conventional station emergency equipment and safeguard system loads. The licensee stated that the 12 a
installation of new 125 VDC and 250 V00 batteries were completed
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in 1989. The plant USAR states that the batteries have adequate capacity for four hours of operation before battery chargers need to be re energized. This corclusion is based on the licensee's
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battery sizing calculation assuming a minimum electrolyte l
temperature of 70'F. The Itcensee, during the telephone conversation of January 16, 1991, stated that the battery room is j
maintained above minimum room temperature of 72.5'F procedurally, and it alams in the control room if the temperatJre dip; below
{
72'f.
Since the licensee stated that ;he battery calcalations l
followed the IEEE Std 485 method, we consider that all of its i
recommendo, ions int.iuding an aging correction factor of 1.25, and f
a design margin factor of at least 1.10 have been used.
In addition, we assume that the licensee, in its calculations, has f
correctly considered a battery teminal minimum voltage which is consistent with that required for the operation of the equipment
-i supported during an $80 event.
Finally, we should emphasize that f
we did not review the battery load proflies and the battery sizing
{
calculations; no analysis was provided for review.
i 3.
Compressed Air
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Licensee's submittal The licensee stated that compressed air is not relied upon at CNS l
to cope with a station blackout of four hours.
R*' low of Licehsee's Subetttal j
According to the USAR the instrument air system serves no safety fune mn since it is not required to achieve safe shutdown or to L
mitig e the consequences of an accident. Air accumulators are l
provided for each valve where it is required to function for safe shut down of the plant following an accid *nt.
For example, each of the reactor vessel relief valves provided for automatic f
13
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depressurization is equipped with an air accumulator with sufficient capacity to allow five valve operations.
Operation of these valves are required, if reactor depressurization is needed.
It should be noted, however, that the licensee does not intend to depressurize the reactor during an SB0 event.
4.
Effects of Loss of Ventilation Licensee's submittal The licensee stated that NUKARC methodology was used t' 41culate the temperaturc rise in DC switchge r room and the RC, c sm.
The temperature rise in the control room was calculated using a time-dependent (transient) heat up anaifsis.
The results of these calculations, the final room temperatures after four hours, are presented below (15):
Atiut Temperature RCIC Room 121'f DC Switchgear Rooms 127'f Control Room 100'T The licensee added that the control room 6. eat up niculation indicates that it is rot a dominant area r.f oncern.
The HPCI room and the steam tunnel are not considered to as areas of concern.
The licer.see stated that the HPCI system will be available but it is not required to respond to an SBO, therefore, no credit is.; ken for~its operation. With regard to the main steam tunnel, there is no high temperature cutout of the RCIC system based on the tunnel temperature at CNS.
l Reasonable assurance of the operability (RAO) of SB0 response l
equipment in the above listed ieninant areas has been assessed d
using Appendix F to NUMARC B7-00 and/or Appendix F Topical Report.
The licensee concluded that no nodifications or associated 14 l
l l
I 4
procedures are required to provide RA0 in the dominant areas of
- concern, in response to the questions raised during the telephone conversation of January 16, 1991, the licensee stated that the control room temperature was determined via transient response analysis using the HEATING 6 and CONTEMPT LT/028 computer codes.
Heating 6 was used to establish a steady perfolic solution for the roof temperature, whereas CONTEMPT-LT/028 was employed for the actual room heat up calculation.
The licensee provided (16) this calculation for us to review.
In addition, based on a plant-specific analysis, which was performed in tandem with the DC power upgrade in 1987, the licensee concluded that the drywell temperature profile and environment during an SB0 is bounded by the design basis LOCA environment.
Review of Licensee's Submittal Our review of the effects of loss of ventilation is limited to the licensee's provided heat up calculations for the control room and that available in the plant USAR.
For areas other than cortrol room we accepted the licensee's results pending future
- audit / verification. During the telephone conversation on January 16, 1991, the licensee stated that both RCIC and switchgear room heat-up calculations were performed using NVKARC 87 00 method with an assumed initial tempar ature of 104'f. Based on this statement, we consider that the licensee's conclusion regarding the operability of RCIC system to be appropriate.
Howaver, in the case of the switchgear room which houses the operating inverters, the licensee needs to verify that the e pipment inside the inverters will remain operational during the SB0 event.
The licensee needs t.) consider the temperature inside the cabinet to be 15' to 20' higher than the sur junding temperature. Our 15
~
e understanding is that the inverters are generally qualified for an ambient air temperature of 104*F.
The CNS control room heat up calculation is an extremely detailed analysis using both the llEATING 6 and CONTEMPT LT/28 computer codes. HEATING 6 is used to calculate the control room roof maximum temperature distribution after exposure to four days of 1%
maximum summer days. CONTEMPT LT/28 is used to calculate the transient control room temperature using the HEATING 6 temperature profile results for the roof, ceiling, and the area between the ceiling and the downstr4&m of the acoustic drop ceiling, and including ill control room walls, floor, heat source as well as air leakap This calculation models every detail of the control room boundary heat transfer surfaces with the exception of plastic laminate and the objects and humans within the control room.
Assumptions are generally conservative, but no heat transfer path is ignored.
Sources of input information are recognized and commonly used texts and reference materials. When an information is not openly available, the author provides documentation of cata received from manufacturers.
The two computer codes, HEATING 6 and CONTEMPT LT/28 were used on a recognized national service bureau, Power Computing Center, or on the licensee computer both of which maintains quality assurance records and configuration control on their codes.
The codes are correctly applied and computer output, with input echo, is included in the calculation.
However, a number of comments have resulted from the review of this calculation which are delineated below.
1.
The assumed 1% high external air temperature of 94*f and corresponding low of 76'F taken from the ASHRAE Handbook data for Omaha, Nebraska is not appropriately conservative.
Based on NUREG/CR 1390 (17), the maximum temperature for a 0.99 probability level (once every 100 years) at this city is ll6'F. The maximum temperature for the 0.50 probability level (once every two years) is 101'F.
c i
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i 2.
The personnel heat load used for this analysis was 110 watts per person. This is too low due to the nature of activities in the control room during an SB0 event. An acceptable heat load per ASHRAE handbook would be 230 250 watts per person.
3.
This analysis uses a control room initial air temperature of
- 73. 4'F. This value is non conservative unless the licensee bs appropriate technical specifications and/or administrative controls that would require plant shut down if this temperature is exceeded.
Since the CNS control room
{
only has one HVAC train, the possibility of a failed or degraded HVAC must be consideres nd a higher initial control room temperature needs to be used. ' Historical measured temperature data may also be a source of the higher bounding temperature value.
If there is no technical specification limit on the control room temperature, and no historical maximum temperature has been experienced, an initial temperature in the range of 85 to 90'F may be used by the licensee in a re analysis.
4.
The licensee uses a concrete thermal conductivity of 1.05 Btu /hr.ft.'F in this analysis.
References consulted by the reviewer and typical FSAR containment and sub compartment analyses all use a value of 0.7 (same unit) for concrete thermal conductivity. Although the higher value is conservative for maximizing the roof initial temperature in the HEATING 6 calculation, it is non-conservative va!9e in one CONTEMPT calculation, since the precominant heat transfer medium from the room are concrete walls and floor.
5.
Although small in magnitude, the use of air leakage by the licensee in this calculation is not in keeping with the conservative nature of an SB0 analysis.
To credit the thermal effects of air leakage on the control room temperature, the licensee needs to perform a more detailed 17
i
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analysis of all potential leakage paths including
- a infiltration and leakage from the control room and all possible air flow paths, air source temperatures, and the influence of HVAC ducting.
In lieu of such an undertaking, the licensee needs to eliminate the air leakage aspect of this analysis, f
i 6.
The CONTEMPT computer code model of the control room initializes this room with a 40% sir humidity.
Containment i
and sub compartment analyses have shown that the value of i
initial air humidity can affect the thermal response of the atmosphere because of the relatively high stored energy capacity of a small amount of water vapor relative to air.
The licensee needs to adequately justify this assumption by performing sensitivity studies with different initial humidities and demonstrating the conservatism of the value selected from the viewpoint of maximizing the four hour SB0 l
control room temperature.
i Although numerous non conservative values were used in this analysis, we have concluded that if the-licensee were to use a l
higher initial room temperature of 88.5'F, (a mid-temperature between the 73' and 104'F), and consider other corrections identified above, the final control temperature will still be less than 120'F. However, the licensee neeos to provide a procedure for opening the control cabinet doors within 30 minutes from the onset of an $80 event consister.t with the NUMARC guidance.
L l
The licensee did not perform heat-up calculations for HPCI and steam tunnel rooms. HPCI will automatically starts upon reactor vessel low low water level, and the plant-specific analysis took advantage of HPCI operation for its capability to remove heat-before dumping a' colder steam into the torus. Without HPCI j
operation a higher torus temperature would be expected.
In I
addition the operators will not trip the HPCI operation until-it i
18 1
L
. -, -,,.. ~., _ _. _, _ _ _ _ _. ~
4 trips automatically upon the high reactor vessel water level signal. Therefore it seems that it is necessary to perform a HPCI room heat up calculation to be consistent with the analyzed condition. With regard to the stkam tunnel, the high temperature could also affect the operability of the DC operated HPCI or RCIC turbine steam supply valve. These valves are normally open at the beginning of the incident and they can remain open throughout the incident. However, if they are required to be closed as part of the containment isolation integrity, their operations can not be assured without ar, essessnent of valve operability at the expected high temperature. Therefore the licensee needs to perform a heat-up calculation for the steam tunnel area and assess the equipment operability, or provide justification why this calculation would not be needed.
With regard to the drywell heat-up during an SBO, calculations performed by the licensee did not include RCS leakage in the drywell. The licensee argued qualitatively, that this leakage will not significantly impact the calculated final temperature of 185'f. This calculstion was performed while keeping the reactor vessel pressure at an average of 1040 psia during the event. Our experience with similar BWRs indicates that there is a high probability the drywell temperature at CNS will exceed the design limit of 281*F during the four hour SB0 event, if no reactor vessel depressurization is attempted. Therefore, it appears that reactor depressurization would be needed to prevent high drywell temperature.
5.
Containment Isolation Licensee's Submittal The licensee stated the plant list of containment isolation valves has been reviewed to determine those valves which must be capable of being closed or that must be operated under Station Blackout 19 I
c i
i e
conditions with indication, independent of the preferred and j
blacked out class IE AC power supplies.
No plant modifications and/or procedure changes were determined to be required to ensure i
that appropriate integrity can be provided under SB0 conditions.
For this review CNS utilized the five exclusion categories as i
identified in NUMARC 81 00. CNS also utilized the following i
additional exclusion criteria:
1.
Normally closed failing as-is, and 2.
Valves normally open, AC powered, failing as is, and failure position is acceptable, if not desirable.
In response to the questions raised during the telephone conversation on January 16, 1991, the licensee provided (16) the list of CIVs which were excluded by the above criteria.
Review of Licensee's Submittal Our review of the valves excluded using the additional criteria indicates that they are all AC operated, and are either normally closed or open. All the valves identified are part of the RHR or core spray systems.
The licensee's basis for excluding these valves is that the said systems could not operate during an SB0 because AC power is unavailable. Hence, valves in these systems would remain in their pre existing positions during an SBO, and there is no reason to attempt system operation until power is
~
restored. The pre-existing positions are specified by the system operating instructions. Control room indicator lights would, verify the proper valve position prior to the SB0.
If either system were required when AC power is restored, valve operation would be as directed by the Emergency Operating Procedures.
20 1
Although the licensee's arguments seem reasonable, it does not provide assurance of adequate containment integrity should that be needed during the accident.
The assurance of appropriate containment integrity requires that the operators be aware of CIVs positions at all times.
Since during an SB0 the AC operated valves will not have position indications in the control room, the licensee needs to list in an appropriate procedure all ClYs that cannot be excluded by the five criteria given in RG 1.155 and are either normally closed or open and fail as-is upon loss of AC, and identify the actions necessary to ensure that these valves are f
fully closed, if needed. The valve closure needs to be confirmed by position indication (remote, local, mechanical, etc.).
6.
Reactor Coolant Inventory Licensee's Submittal The licensee stated that the ability to maintain adequate reactor coolant system inventory has been assessed for four hours, the generic analyses listed in section 2.5.2 of NUMARC 87 00 were used for this assessment and are applicable to the specific design of CNS.
The expected rates of reactor coolant inventory loss under SB0 conditions do not result in more than a momentary core uncovery in an SB0 of four hours. Therefore, make-up systems other than those currently available under SB0 conditions are not required to maintain core coolir.g.
Revies; of Licensee's Submittal Reactor coolant make up is necessary to replenish the RCS inventory losses due to the recirculation pump seal leakage (18 gpm per pump per NUMARC 87-00 guideline), and the maximum allowable technical specification leakage (estimated to be 25 gpm). Therefore, the RCS loses 6) gpm, and on the average boils off 230 gpm for a total inventory loss of 2,91 gpm. The licensee 21 1
stated that only RCIC system will be used to maintain RCS inventory. The RCIC pump is run by turbine, normally takes suction from the emergency condensate tank, and can provide 416 gpm of make up and cooling water. The RCic system, by itself, can not maintain the RCS inventory above the active core early in the incident. The HPCI system is available and starts automatically on low low 99ssel water level to maintain the core covered. The combinatfor, tsults_in a momentary enre uncovering. Hence, we agree with the licensee that the core will not be uncovered longer than momentarily during a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> SB0 event.
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"The 18 ans recirculation sumo seal leak rate was agreed to between NUMARC and the staff pending resolution of generic Issue (GI) 23.
If the final resciution of GI 23 defines higher seal leak rates than assumed for the RCS inventory evaluation, the licensee needs to be aware of the potential impact of this resolution on its analyscs and actions
- addressing conformance to the 500 rule."
3.3 Proposed Procedures and Training Licenste's submittal The licensee stated that the following plant procedures will be-reviewed per guidelines in NUMAkt 87-00, Section 4:
1.
Station blackout response guidelines, 2.
AC power restoration, and 3.
Severe weather.
The licensee stated that these procedures have been reviewed and thn changes necessary to meet NUMARC 87 00 guidelines will _be implemented.
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Review of Licensee's submittal We neither received nor reviewed the affected SB0 procedures.
These procedures are 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 SB0 event and to assure that these procedures are complete and correct, and that the associated training needs are carried out accordingly.
3.4 Proposed Nodifications Licensee's Submittal The licensee stated that no modifications are necessary to cope with a station blackout for four hours.
Review of Licensee's Submittal Our review identifies one modification in terms of procedural change to direct the operators to open the control room cabinet doors within 30 minutes of an SB0 event consistent with the guidance provided in NUMARC.
The requirement for this change is emphasized in control room heat-up calculation review.
3.5 Quality Assurance and Technical Specifications The licensee did not provide documentation on how the plant complies with the requirement of RG 1.155, Appendices A and B.
23
s.:
4.0 CONCLUSION
S Based on our review of the licensee's submittals and the information available in the USAR for Cooper Nuclear Station, we find that the submittal conforms with the requirements of the SB0 rule by following the guidance of RG 1.155 with the following exceptions:
1.
Offsite Power Characteristics a.
Extremely Severe Weather cateaorv The licensee changed the site ESW grouping from '3" to *1' and claimed that the new grouping is more representative of the site thanthat(*3")providedinNUMAP.C. Our review of the licensee's analysis indicates that the ESW frequency estimate is based on the expected tornado winds in excess of 113 mph, which the licensee found to have an occurrence frequency of 2.357E-04 per year, or 1 in 4243 years. The data provided in NUMARC gives a value of 1.40E-03 per year, or 1 in 700 years, and it is based on the expected sustained wind of 124.5 mph at Omaha Nebraska, according to the NRC staff who provided the data in NUMARC. The staff stated that the tornado winds can not be used to estimate the ESW sustained winds. Therefore, we consider the site ESW grouping to be "3" as indicated in NUMARC.
b.
Egyff_e Weather Cateoory The licensee also revised the SW grouping from "3" to "2."
Our review of the licensee's calculations of SW frequency indicates that the results are based on a limited weather data which does not provide a good estimate for extreme conditions. The licensee used a 13 years wind data with a maximum recorded wind _ speed of 48.4 mph (only one data point at this speed) to estimate the expected frequency of storms with winds between 75 and 125 mph.
The use of this data point to estimate of storm frequency predicts 24 l
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a value (1/13 0.077) which is a factor of 6.5 smaller than that provided in Table 3 3 of NUMARC 87-00.
It is our judgement that the licensee's estimate of storm frequency is low and does not represent the extreme condition.
The licensee can use the 11-years date and perform a Bayesian update of the data given in NUMARC.
In absenet. of such analysis, we consider the site SW group to be '3" as indicated in NUMARC for multiple rights of way, c.
Dargency Diesel Generator Taroet Reliability / SB0 Duration Based on the above, the site offsite power characteristic is "P2" requiring an EDG target reliability of 0.975 for a 4-hour SB0 duration.
The Itcensee needs to revise the EDG target reliability to 0.975, as originally selected, for its submittal to be consistent with the 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> coping analysis, 2.
Effects of Loss of Ventilation a.
Control Room Although numerous non conservative values were used in this analysis (see the text for detail), we have ccicluded that if the licensee were to use a higher initial room temperature of 88.5'F, (a mid-temperature between the 73' and 104'F), and consider other corrections identified, the final control temperature will still be less than 120'F. However, the licensee needs to provide a procedure for opening the control cabinet doors within 30 minutes frm the onset of an SB0 event consistent with the NUMARC
- guidance, b.
DC Switchaear Room We considered the licensee's heat up calculation for this room to be correct, pending future verification; no analysis was provided for review.
However, since this room houses the operating l
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.t inverters, the licensee needs to verify that the equipment inside the inverters will remain operational during the 590 event.
The licensee needs to consider the temperature inside the cabinet to be 15' to 20' higher than the surrounding temperature. Our understanding is that the inverters are generally qualified for ambient temperature of 104'F.
c.
HPCI and Steam Tunnel Areas The licensee did not perform heat up calculations for HPCI and stets tunnel rooms. Our evaluation of the licensee's submittal indicates that HPCI was credited in the plant-specific analysis for its capability to remove heat before dumping a colder steam into the torus. Without HPCI operation a higher torus temperature would be expected. With regard to the steam tunnel, the high temperature could affect the operability of the DC operated HPCI or RCIC turbine steam supply valve.
These valves are normally open and if they are required to be closed as part of the containment isolation integrity, their operations can not ce assured without an assessment of valve operability at the expected high temperature. Therefore the licensee needs to perform heat-up calculations for the steam tunnel and HPCI areas and assess the equipmentoperabilityintheseareas,orprovidejustification(s) on why no calculations would be needed.
d.
Drywell Heat-up The licensee 'ated that a plant-specific analysis indicates that the drywell temperature will be 185'F during an 580 event. This calculation was performed while keeping the reactor vessel pressure at an average of 1040 psia during the event, and it'did not consider any RCS leakage.
The licensee argued qualitatively, that this leakage will not impact the calculated final temperature significantly. Our experience with similar BWRs, indicates that there is a high probability the drywell temperature at CNS will 26
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exceed the design'11mit of 281'f during the four hour $B0 event if no depressurization is attempted.
Therefore, reactor
.depressurization would be needed to prevent high drywell temperature.
3.
Contalnment '! solation The licensee used two criteria in addition to the five criteria given in NUMARC 87 00 and RG 1.155.
These excluded valves are all
[
AC operated and they are either normally open or closed. The licensee needs to list in an appropriate procedure all CIVs that cannot be excluded by the criteria given in RG 1.155 and are either are normally closed or open and fail as is upon loss of AC, and identify the actions necessary to ensure that these valves are iully closed, if needed. The valve closure needs to be confirmed by position indication (remote, local, mechanical, etc.).
l 4.
Quality Assurance and Technical Specifications The itcensee did not provide documentation on how the plant complies with the requirement of RG 1.155, Appendices A and B.
Y 27
a..
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 Comission, " 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 Comission, " 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 Comission, " Reliability of Emergency AC Power System at Nuclear Power Plants," HUREG/CR-2989, July 1983.
5.
U.S. Nuclear Regulatory Comission, " Emergency Diesel Generator Operating Experience, 1981 1983," NUREG/CR-4347, December 1985.
6.
U.S. Nuclear Regulatory Comission " Station Blackout Accident Analyses (Part of NRC Task Action Plan A 44)," NUREG/CR-3226, May 1983.
7.
U.S. Nuclear Regulatory Comission Office of Nuclear Regulatory Research, " Regulatory Guide 1.155 Station Blackout," August 1988.
8.
Nuclear Management and Resources Council, Inc., " Guidelines and Technical Bases for NUMARC Initiatives Addressing Station Blackout at Light Water Reactors," NUMARC 87-00, Nove....ar 1987.
9.
Thadani, A. C., Letter to W. H. Rasin of NUMARC, " Approval of HUMARC Documents on Station Blackout (TAC-40577)," dated October 7, 1988.
10.
Thadani, A. C., letter to A. Marion of NUMARC, " Publicly-Noticed Meeting December 27, 1989," dated January 3,1990 (confiming "NUMARC B7-00 Supplemental Questions / Answers," December 27,1989).
28 i
(.
i a
s 11.
Nuclear Safety Analysis Center, "The Reliability of Emergency Diesel Generators at U.S. Nuclear Power Plants,' NSAC-108. Wyckoff, H.,
September 1986.
12.
Kuncl L. G., ' Response to Station Blackout Rule, 10CFR50.63.
Cooper Nuclear Station." Docket 50 298, April 17, 1989.
13.
Trevors, G. A., " Updated Response to Station Blackout Rule," August 3, 1989.
14.
Cooper Nuclear Station Updated Safety Analysis Report 15.
Trevors, G. A., " Supplemental Response to the Station Blackout Rule,"
March 23, 1990.
16.
Horn, G. R., " Station Blackout Information Request, 10CfR50.63, Cooper Nuclear Station, NRC Docket 50 298, DPR 46. TAC #68534," January 31, 1991.
17.
NUREG/CR-1390, ' Probability Estimates of the Temperature Extremes for the Contiguous United States," May 1980.
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