ML20136H894
| ML20136H894 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 08/16/1985 |
| From: | Stern S Office of Nuclear Reactor Regulation |
| To: | Office of Nuclear Reactor Regulation |
| References | |
| NUDOCS 8508200540 | |
| Download: ML20136H894 (147) | |
Text
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Docket No. 50-458 AUG 161985 i;0TE T0: File J
FROM:
Stephen M. Stern, Project Manager Licensing Branch No. 2 Division of Licensing i
SUBJECT:
DRAFT RIVER DEliD SER SUPPLEMENT i
1 i
j A copy of the enclosed draf t SER Supplement #3 for River Bend Station f
was provided to the applicent to assist in the certification and review of Technical Specifications. A copy of this SER Supplement #3 was supplied to j.
the docket room for ingcdiate insertion into the PDR on August 5,1985.
4 Ortsf enl 8Tenad byr Stephen it. Stern, Nanager Licensing Branch No. 2 Division of Licensing i
Enclosure:
As stated l
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Walter R. Butler 1
Contact:
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ABSTRACT
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Supplement No. 3 to the Safety Evaluation Report on the application filed by Gulf States Utilities Company as applicant and for itself and Cajun Electric Power Cooperative, as owners, for a license to operate River Bend Station has been prepared by the Office of Nuclear Reactor Regulation of the U.S. Nuclear Regulatory Commission.
The facility is located in West Feliciana Parish, near St. Francisville, Louisiana.
This supplement reports the status of certain
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items that had not been resolved at the time of publication of the Safety Evaluation Report, Supplement No. 1, and Supplement No. 2.
River Bend SSER 3 111 a
4 REACTOR 4.6 Functional Design of Reactivity Control Systens In FSAR Amendment 20, the applicant provided revised pages in ord'er for the FSAR to conform to the proposed plant Technical Specifications.
One of the
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revised FSAR pages was Figure 9.3-14 which graphically defines the upper and lower bounds of the allowable sodium pentaborate concentrations and volume.
The previous revision of Figure 9.3-14 was the standard General Electric (GE) figure with the concentrations ranging from approximately 12% to 13.8% and the volume ranging from approximately 4600 gallons to 5160 gallons with a safety margin volume of approximately 250 gallons.
The new figure has a concentration,
range of approximately 9.3% to 13.8% and the volume ranges from 3542 gallons to 5150 gallons with no safety margin.
No explanation was provided for the change.
On the basis of the staff's independent calculations, the lower concentration level of 9.3% is non-conservative with respect to previously approved concentra-tion level and volume levels.
The applicant subsequently provided a revised figure in a submittal dated July 8, 1985, which shows the minimum concentration as 10.5%. This concentration level was compared with other previously approved analyses and found to provide similag_boration rates.
Therefore, the staff concludes that the revised figur ro."vided by the July 8th submittal is accept-able. The applicant has also com itted to revise the figure in the Technical Specifications.
On the basis of the above evaluation, the staff concludes that the design of the reactivity control system meets the requirements of General Design Criterion (GDC) 26, " Reactivity Control System Redundancy and Capability," and GDC 27
" Combined Reactivity Control System Capability," and is, therefore, acceptable.
The functional design of the reactivity control system meets the applicable criteria of Standard Review Plan (SRP) Section 4.6 (NUREG-0800).
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River Bend SSER 3 4-1 l
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5.2 Integrity of Reactor Coolant Pressure Boundary
- 5. 2. 4 Reactor Coolant Pressure Boundary Inservice Inspection and Testing
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This section was prepared with the technical assistance of Department of Energy i
(DOE) contractors from the Idaho National Engineering Laboratory.
5.2.4.3 Evaluation of Compliance With 10 CFR 50.55a(g) for River Bend Station
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This evaluation supplements conclusions in Section 5.2.4.3 of the SER (NUREG-0989), which addressed the definition of examination requirements and
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the evaluation of compliance with 10 CFR 50.55a(g).
The design of the ASME l
Code Class 1 and 2 components of the reactor coolant pressure boundary incor-i porates provisions for access for inservice examinations, as required by Para-graph IWA-1500 of Section XI of the ASME Code.
10 CFR 50.55a(g) defines the j
detailed requirements for the preservice inspection (PSI) and inservice inspec-tion (ISI) programs for light-water-cooled nuclear power facility components.
1 On the basis of the construction permit date of March 25, 1977, this section of l
the regulations requires that a PSI program be developed and implemented using at least the edition and addenda of Section XI of the ASME Code applied to the construction of the particular components.
The components (including supports) 4 may meet requirements set fcrth in subsequent editions and addenda of this Code which are incorporated by reference in 10 CFR 50.55a(b) subject to the limita-tions and modifications listed therein.
The applicant has prepared the PSI Program based on compliance with the requiraments of the 1977 Edition of the Code including addenda through Summer 1978 except for the reactor pressure vessel (RPV) or where specific written relief is requested.
The staff has re-viewed the results of the public meeting with the applicant on May 1, 1984, to discuss the PSI Program, the FSAR through' Amendment 20 (June 1985), the appli-cant's May 15, 1985, response to the staff's request for additional information,
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the PSI Program through Revision 3 submitted on May 15, 1985, and other letters dated June 10 and June 24, 1985.
Th'e RPV examination procedures, calibration blocks, and examinations comply with the requirements of the 1974 Edition of the Code including addenda through Summer 1975 for the vessel shell welds, and the 1977 Edition and addenda through Summer 1978 for safe-end and safe-end extension piping welds.
The preservice examination of the reactor pressure vessel was performed in 1977 by a combina-tion of manual and automated ultrasonic inspection equipment after completion of the hydrostatic test at the Chicago Bridge and Iron nuclear facilities at Memphis, Tennessee.
Automated examinations were performed on shell seal welds in or below the core region and on the nozzle-to-vessel welds with pipe sizes 10 inches in diameter or larger.
In addition, all areas of the N-1 through N-6 nozzle-vessel welds that were examined manually in 1977 were reexamined with_
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automated equipment at River Bend Station.
The safe-ends for the same nozzles and the safe-end extension welds were also reexamined using the automated equip-ment. The applicant states that all RPV examinations predate Regulatory Guide-(RG) 1.150 which was issued in June 1981.
The staff concludes that the preser-vice examinations of the RPV are acceptable because the preservice examinations River Bend SSER 3 5-1 l
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were consistent with-the applicable Code and the commercial practices at the time when examinations were performed.
i As a result of the staff's request for additional information dated March 20, 1985, the PSI Program was completely revised and resubmitted on May 15, 1985.
Therefore, the final program review with respect to the systems and components subject to examination was evaluated based on this submittal.
In_ addition, 4
Appendix C of the PSI Program document contained requests for relief from ASME Code Section XI requirements that the applicant has determined impractical for the ASME Code Class 1 systems and components.
These relief requests were re-vised in letters dated June 10 and June 24, 1985, and were supported by a i-technical justification.
The staff evaluated the ASME Code-required examina-j tions that the applicant determined to be impractical and, pursuant to l
10 CFR 50.55a(a)(3), relief from the impractical Code requirements has been i
allowed wherever the applicant has demonstrated that either (1) the proposed alternatives would provide an acceptable level of quality and safety or (2) com-.
pliance with the requirements would result in' hardships or unusual difficulties without a compensating increase in the level of quality and' safety.
The de-tailed evaluation supporting this conclusion is provided in Appendix L to this report. On the basis of granting relief from these preservice examination re-quirements and review of the applicant's submittals, the staff concludes that f
the preservice inspection program for reactor coolant pressure boundary is ac-ceptable and in compliance with 10 CFR 50.55a(g)(3).
The initial inservice inspection program has not been submitted.
This program i
will be evaluated after the applicable ASME Code edition and addenda can be determined based on 10 CFR 50.55a(b), but before the first refueling outage when inservice inspection commences.
5.2.5 Reactor Coolant Pressure Boundary Leakage Detection Standard Review Plan (SRP) Section 5.2.5 and RG 1.45 discuss the need to moni-or leakage from the reactor coolant pressure boundary to other systems.
This intersystem leakage, as identified in the regulatory guide, is both (1) leakage i
i across components, such as heat exchangers, to other water systems, such as the
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reactor plant component cooling water system, and (2) leakage across passive components,suchasacrossclosedisolQionvalves.
The applicant has provided means to detect the first type of intertsystem leakage, as was previously dis-
$ussedintheSER.
j In FSAR Amendment 21, the applicant has identified a means to detect the second type of intersystem leakage, which is also referred to as i
the high/ low pressure interface leakage, by monitoring the pressure between the two isolation valves.
Detection of high pressure between the two valves is an indication of primary coolant leakage and is alarmed in the control room.
- Thus, the staff concludes that the method for detecting leakage across the high/ low pressure interfaces meets the requirements of General Design Criterion-(GOC) 2, i
" Design Basis for Protection Against Natural Phenomena."
j On the basis of the above evaluation, the staff concludes that the reactor coolant pressure boundary leakage detection system meets the requirements of GDC 2, with regard to protection against natural phenomena, and the guidelines of RG 1.29 (Rev 3), Positions C.1 and C.2, concerning the system seismic classi-fication, and is, therefore, acceptable.
The reactor coolant pressure boundary j
leakage detection system meets the acceptance criteria of SRP Section 5.2.5.
River Bend SSER 3 5-2
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. W SAFETY EVALUATION TMI ACTION PLAN II.K.3.28 VERIFY QUALIFICATION OF ACCUMULATORS ON ADS VALVES RIVER BEhD STATION UNIT 1 DOCKET NO. 50-458 1.
BACKGROUND Safety Analysis Reports (SARs) claim that air (or nitrogen) accumulators for the automatic depressurization system (ADS) valves are provided with sufficient capacity to cycle the valves open five times at design pressures.
General Electric (GE) has also stated that the Emergency Core Cooling Systems (ECCS) are designed to withstand a hostile environment and still perform their function for 100 days following an accident. Licensees and applicants must demonstrate that the ADS valves, accumulators, and associated equipment and l
instrumentation meet the requirements specified in the plant's FSAR and are capable of performing their functions during and following exposure to hostile environments, taking no credit for non-safety-related equipment or instrumen-tation. Additionally, air (or nitrogen) leakage through valves must be ac-counted for in order to assure that enough inventory of compressed air is available to cycle the ADS valves.
If this cannot be demonstrated, it must be shown that the accumulator design is still acceptable.
2.
DISCUSSION The comitment to satisfy the requirement of TMI Action Item II.K.3.28 for the River Bend Station, Unit 1 is discussed in the following submittals.
A.
Gulf States Utilities Company letter from J.E. Booker to H.R. Denton, NRC, dated April 9, 1984, response to a request for additional informa-tion.
B.
Gulf States Utilities Company letter from J.E. Booker to H.R. Denton, NRC, dated May 13, 1985.
3.
DEMONSTRATION OF OPERABILITY The design of the River Bend Station is such that the ADS will be available for 100 days following an accident. Each ADS valve is equipped with a 60 gallon accumulator designed for two (2) actuations at 70 percent of drywell design pressure which is equivalent to 4 to 5 actuations at atmospheric pressure. During normal plant operation, air is supplied from the non-nuclear safety (NNS) main steam system air compressors.
Post-LOCA air requirements are supplied from the Penetration Valve Leakage Control System (PVLCS), a l
nuclear safety related Seismic Category I system.
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- The realignment from the main steam system air compressors to the'P.VLCS is perfomed by the plant operators from the main control room.
4 The PVLCS is manually actuated approximately 20 minutes after a LOCA. Prior to the manual actuation, the system is in an automatic mode and maintains the accumulators at a preset pressure. Following a loss of off-site power, the PVLCS-initiation is delayed to avoid overloading due to starting currents.
The ADS accumulators are designed and maintained with sufficient inventory to permit the required actuations during this period, assuming a leakage of 1 4
SCFH.
FSAR Section 9.3.6.3.1 indicates that the PVLCS accumulators are maintained with enough, air to meet all short-tem requirements of the PVLCS, the MS-PLCS, and the main steam safety / relief valve system.
Technical Specification surveillance requirements associated with the ADS accumulator system and backup system verifies that the PVLCS accumulator pres-i sure is greater than 101 psig at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
l The allowable leakage rate of I SCFH for the ADS air accumulator sub-system is compatible with the Emergency Core Cooling System (ECCS) performance evaluations and assumptions, and the calculations for sizing the ADS air supply system. Additionally no credit was taken for non-safety related equipment or instrumentation when establishing the allowable leakage criteria.
The air. accumulator sub-system is designed to withstand Seismic Category I loads and post-accident environments.
j The ADS air accumulator sub-system is defined as all the components between (and including) the check valve located on the inlet side of the accumulator and the associated main steam safety relief valve.
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EVALUATION 1
18. 1 The primary source of air for the ADS accumulators is from the non-nuclear safety related main steam system air compressors. Backup to this j
system is the nuclear safety related PVLCS. The applicant states that the 1
PVLCS is placed in service approximately 20 minutes after it has been ascertained that a LOCA has occurred. This realignment is accomplished in the main control room. The 20-minute period is approximately equal to the time required for the PVLCS air compressors to be loaded onto the standby power 4
i supplies. The applicant has provided a statement verifying that the ADS i
accumulators have sufficient inventory to assure operability of the ADS valves during this 20-minute. interval.
l The accumulator on each ADS valve has a 60-gallon capacity which is designed j
for two actuations at 70 percent of drywell design pressure. This capability is equivalent to 4 to 5 actuations at atmospheric pressure.
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. The staff concludes that the applicant has demonstrated the long and short term capability of the automatic depressurization system and is therefore acceptable.
4.2 The applicant states that the allowable leakage rate of 1 SCFH is compatible with the ECCS performance evaluations and assumptions, and the calculations for sizing the AOS air supply.
Therefore, accounting for (a) the capacity of the accumulators, (b) that the ECCS is a NSSS (GE) designed system, and (c) that previous submittals have discussed in detail the basis for the allowable leakage criteria, the staff concludes that the allowable leakage criteria of 1 SCFH address the concerns in this area and is acceptable.
4.3 The applicant has provided information acceptable to the staff indicative of the development of surveillance, maintenance, and leak testing programs for the ADS accumulator system and associated alarms and instrumentation.
4.4 The applicant has provided information confirming that:
the backup air supply system, PVLCS, is seismically and environmentally qualified, and the accumulators and associated equipment are capable of performing their functions during and following an accident, while taking no credit for non-safety related equipment and instrumentation.
5.
CONCLUSION Based on the information provided by the applicant summarized in Section 3, and the evaluation performed highlighted in Section 4 the staff concludes that the Gulf States Utilities Company has verified qualification of the accumulator (s) on ADS valves for River Bend Station Unit 1, thereby satisfying the requirements of TMI Action Item II.K.3.28.
6 ENGINEERED SAFETY FEATURES 6.2-Containment Systems 6.2.1 Containment Functional Design 6.2.1.8 Pool Dynamics 6.2.1.8.3 Hydrodynamic Load Assessment Pool Temperature Limit and SRV Inplant Tests In accordance with criterion 5 of NUREG-0763, River Bend steel containment is required to undergo in plant safety / relief valve (SRV) testing, since no steel containment has been subjected to such testing.
The ap from the testing requirement for the following reasons:plicant requested relief (1)
Even though River Bend has a freestanding steel containment, the annulus, i
that is, the space between the shield building and the steel containment which forms the boundary of the suppression pool, has been filled with concrete. As a result, this portion of the containment which forms the boundary of the suppression pool is as rigid as the reinforced concrete containment of Kuosheng which has undergone in plant SRV testing.
There-fore, the testing results of Kuosheng can be applied to River Bend.
(2) Perry Nuclear Power Plant also has a freestanding steel containment and the lower portion of the annulus (same as River Bend) is filled with con-crete.
A study was made by Cleveland Electric Illuminating Co. for Perry using a pressure time history from the Kuosheng tests as the forcing func-tion input to the Perry structural models to obtain the response of the 1
containment and internal structures. The resulting response spectra at selected node points are enveloped by the Perry SRV design response spec-tra except in the high-frequency region where similar exceedance as noted in the Kuosheng study appears.
However, detailed investigation indicated that there is adequate design margin for piping and equipment at Perry.
On the basis of the review of the applicant's findings, the staff concluded that Perry need not undergo any in plant SRV tests.
Since River Bend _has a containment very similar to that of Perry, there is no need for River Bend to have any in plant tests.
The staff reviewed the information provided by the applicant and found that the shear wave velocity of River Bend is much lower than that of Perry, which -
1 may have different effects on the response of the containment structure, compo-4 nents, and systems located therein.
In response to this staff concern, the applicant reasoned that the Kuosheng observed pressure trace does not excite lower modes of vibration of the Perry analytical model, nor of the actual i
Kuosheng structure. The response spectra used in the River Bend design based on the General Electric (GE) SRV forcing functions provide significant re:ponses in the lower frequencies. This indicates that the River Bend design used SRV loads which have more energy in the lower frequencies and is, therefore, more River Bend SSER 3 6-1 i
conservative in this region than the Kuosheng traces indicated. On the basis of review and evaluation of the information provided.by the applicant, the staff concludes that there is no need to perform in plant SRV testing at River Bend.
6.6 Inservice Inspection of Class 2 and 3 Components This section was prepared with the technical assistance of Department of Energy (DOE) contractors from the Idaho National Engineering Laboratory.
6.6.3 Evaluation of Compliance With 10 CFR 50.55a(g)
This evaluation supplements conclusions in Section 6.6.3 of the SER (NUREG-0989),
which addressed the definition of examination requirements and the evaluation of compliance with 10 CFR 50.55a(g).
On the basis of the construction permit date of March 25, 1977, 10 CFR 50.55a(g) requires that a PSI Program for Class 2-and 3 components be developed and implemented using at least the edition and ad-denda of Section XI of the ASME Code applied to the construction of the particu-lar components.
The components (including supports) may meet the requirements set forth in subsequent editions of this Code and addenda which are incorporated by reference in 10 CFR 50.55a(b) subject to the limitations and modifications listed therein.
The applicant has prepared the PSI Program based on compliance with the requirements of the 1977 Edition of the Code including addenda'through Summer 1978 except that the extent of examinatino for Class 2 welds in the resi-dual heat removal system (RHRS) and emergency core cooling system (ECCS) are determined by the requirements of the 1974 Edition of the Code with addenda through Summer 1975, except where specific written relief is requested.
The staff has reviewed the results of the public meeting with the applicant on May 1, 1984, to discuss the PSI Program, the FSAR through Amendment 20 (June 1985), the applicant's May 15, 1985, response to the staff's request for additional information, the PSI Program through Revision 3 submitted on May 15, 1985, and other letters dated June 10 and June 24, 1985. As a result of the staff's request for additional information dated March 20, 1985, the PSI Pro-gram was revised and resubmitted in its entirety on May 15, 1985. Therefore, I
the final program review with respect to the systems and components subject to PSI examination was evaluated using this subtittal.
revisions which have been noted are:
The most significant The exclusion of system pressure tests and visual examinations in accord-ance with IWC-1220 has been deleted.
Although the terminology used in Paragraph IWC-1220 of Section XI, Summer 1978 Addenda is ambiguous, the intent of the ASME Code Committee as expressed in Examination Category C-H, "All Pressure Retaining Components " is clear.
Paragraph IWC-1220 should not be used as a basis for excluding systems or portions of sys-tems from the hydrostatic testing requirements of IWA-5000 and IWC-5000 of Section XI.
The number of volumetric examinations was increased to at least 7.5% of the total number of welds in the RHRS, ECCS, and containment heat removal systems that are not exempt based on the ASME Code Section XI, 1974 Edition with addenda through the Summer of 1975.
River Bend SSER 3 6-2 1
Appendix D contains requests for relief from ASME Code Section XI require-ments that the applicant has determined 'not practical for Class 2 systems and components.
These relief requests were revised in letters dated June 19 and June 24, 1985, and were supported by a technical justification:
The staff evaluated the ASME Code required examinations that the applicant determined to be. impractical and, pursuant to 10 CFR 50.55a(a)(3), relief from the impractical Code requirements has been allowed where the appl'icant has able level of quality and safety or (2) compliance with the re the level of quality and safety.results in hardships or unusual difficulties witho clusion is provided in Appendix L to this report.The detailed evaluation supporting this c relief from these preservice examination requirements and review of the appit-cant's submittals, the staff concludes that the preservice inspection program for River Bend Station is acceptable and in compliance with 10 CFR 50.55a(g)(3)
The initial inservice inspection program has not been submitted.
will be evaluated after the applicable ASME Code edition and addenda can beThis progr determined based on 10 CFR 50.55a when inservice inspection commence (b), but before the first refueling outage s.
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River Bend SSER 3 6-3
7 INSTRUMENTATION AND CONTROLS
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7.2 Reactar Protection System 7.2.2 Specific Findings 7.2.2.6 Isolation Devices Isolation devices are used between safety related and non-safety related cir-cuits to protect the safety-related circuits from damage caused by electrical l
faults that could occur within the non-safety-related circuits.
Isolation devices are also used between redundant safety related circuits to prevent electrical faults from adversely affecting circuits from redundant channels /
divisions (i.e., the effects of the fault are contained on one side of the isolation device). The applicant has confirmed that only two types of isola-tion devices are used at River Bend.
These are: (1) Potter Brumfield MDR re-lays (these are rotary-type relays providing coil-to-contact isolation), and (2) optical isolator assemblies (the assemblies consist of input and output printed circuit cards on either side of a ceramic barrier; polished quartz crystal rods embedded in the ceramic material transmit light across the barrier).
The applicant confirmed that relay contact-to-contact isolation is not used at River Bend, and that FSAR Section 7.1.4.1 will be revised accordingly.
The staff audited the test plans and procedures used to demonstrate the quali-fication of both the MDR relays and the optical isolators as acceptable isola-tion devices.
The acceptance criteria for both types of devices were found to be acceptable (i.e., upon application of a fault to one side of the device, no degradation o: curs to circuits on the opposite side of the device).
The appli-cant has stated that the MOR relays and optical isolation devices are seismic-ally and environmentally qualified for their safety related applications at River Bend.
These devices are discussed in detail below.
All MDR relays used as isolation devices at River Bend are mounted within metal enclosures containing a metal barrier that separates the coil section of the relay,and its associated wiring from the contact section of the relay and its associated wiring.
The barrier is grounded, and is designed to prevent faults at the output (contacts) of the device from propagating to the input (coil) of the device. Since the entire relay is housed in a metal enclosure, external faults should not compromise the isolation function of the relay or influence signal integrity.
Complete functional tests were performed on the MOR relays before and after the relays underwent seismic and environmental qualification testing.
The functional test program included contact resistance checks, pickup / dropout voltage testing, contact transfer / delay time tests, dielectric strength / insulation resistance tests and contact current rating tests. The MOR relays tested;successfully passed all functional tests.
The dielectric strength / insulation resistance test and the contact current rating test are further discussed below.
River Bend SSER 3 7-1
The dielectric strength / insulation resistance test consisted of applying 1000 V ac for one minute between the normally closed contacts (wired in series) and the relay chassis (ground), first with the relay coil deenergized, and subse-quently with the call energized (120 V ac, 60 Hz).
The test voltage was applied using a hipotronics testor that includes a light and alarm which are activated if leakage current exceeds 5000 microamps.
After the 1000 V ac was removed, 500 V de was applied acress the same terminals and the insulation resistance to ground was measured.
In each case, the insulation resistance was. greater than 50,000 megohms.
This test demonstrates that no arcing or damage to the relay occurs and that there is no insulation resistance breakdown (including carbon traces) upon application of the 1000 V ac.
The contact current rating tests consisted of cycling (energizing and deenergiz-ing) the relay five times in succession for various output (contact) load con-figurations, including 115 V ac and 15 amps (load current through the relay contacts).
The voltage drop across the contacts was measured before and after the test.
The test results showed no significant increase in the voltage drop across the relay contacts (the increase was less than 2 millivolts for the 115 V ac/15-amp case).
The relay single contact current rating at 115 V ac is 10 amps.
This test demonstrates that a credible fault current applied to the out-put (contact) side of the relay will not result in relay damage, and that the fault will not propagate to the input (coil) side of the device.
The staff considers 115 V ac/15 amps to be the minimum credible fault voltage / current acceptable for qualification of components as acceptable isolation devices.
On the basis of the results of the above tests and the relay mounting configu-ration (metal enclosure with barrier between the coil and contact portions of the device), the staff concludes that the Potter Brumfield MDR rotary type relays (model MOR-4130.1) as installed at River Bend are acceptable isolation devices for use between redundant safety-related circuits, and between safety-related and non-safety related circuits.
The optical isolator assemblies contain either 4 or 8 input and output card pairs, with approximately 4 to 12 individual isolators per card pair, depend-ing upon the specific application.
Quartz rods (light pipes) transmit signal information across the ceramic isolation barrier provided between the input cards and the output cards.
All cards on a given side of the isolation barrier are powered from the same electrical division.
Maximum credible voltage / current tests and 5000-V ac card isolation tests were performed on the optical isolator assemblies.
These tests are discussed below.
The maximum credible voltage / current test was performed for the following input /
output card pairs:
Field Contact Input /High-Level Output Field Contact Input /5-V Logic Output Field Contact Input /12-V Logic Output Field Contact Input / Floating Low Level Output High Speed Input /High Speed Output Analog Input / Analog Output Logic Input /12-V Logic Output River Bend SSER 3 7-2
The maximum credible fault voltage and current values were determined by identi-fying the largest voltages present within plant instrumentation cabinets / panels /
control boards and the largest associated branch fuses / circuit breakers.
These values for River Bend are 125-V ac/30 amps and 140-V dc/30 amps.
The fault voltages were applied to each input / output card pair in each of the following test circuit configurations:
(1) fault voltage applied between each input terminal (wired in parallel) and ground (signal returns and the isolator assembly housing)
(2) fault voltage applied in the transverse mode between the input terminals (wired in parallel) and the returns (wired in parallel)
(3) fault voltage applied between each output terminal (wired in parallel) and ground (4) fault voltage applied in the transverse mode between the output terminals (wired in parallel) and the returns (wired in parallel)
The fault voltages were applied for a one-minute duration for each test config-uration.
For each test case the opposite side of the isolation barrier was monitored (using a memory osc,illoscope) to detect any perturbations that might The acceptance criteria for all tests was that no fault source voltage occur.
appear on the opposite side of the isolation barrier.
The fault voltages were applied via fused (30-amp) connections; no fuses failed during the tests.
The test results showed there were two cases in which a voltage perturbation occurred on the opposite side of the isolation barrier, because of arcing from the input cards to the assembly chassis (common to both sides of the isolation barrier),
causing a momentary increase in ground potential.
The two cases were the high-speed card pair and the analog card pair.
The amplitude of the perturbations was less than 2 V and the duration was less than 100 milliseconds.
Both cases involved test configuration 1 (above) and the application of 140 V dc.
The staff does not consider these perturbations significant with respect to impair-ing the capability of the optical isolator assembly to perform its isolation function.
Following the tests, standard production / operability tests (prepro-grammed automated tests) were performed on the isolator cards that were located on the opposite side of the isolation barrier from where the faults were applied.
All cards were tested successfully (i.e., remained operable following the fault tests).
Isolator cards to which the faults were applied were destroyed during the fault tests.
The 5000-V ac card isolation test consisted of applying 5000 V ac between all input terminals (wired in parallel) and the isolator assembly chassis (ground) for the same input / output card pairs listed above for the credible fault tests.
Subsequently, a standard production / operability test was performed on the output cards to verify that the isolation provided between the input and output sides of the assembly is sufficient to prevent the 5000 V ac applied to the input side of the device from impairing the function of the output cards.
The above test was repeated with the 5000 V ac applied to the output cards and a production /
operability test performed on the input cards.
For all cases, the acceptance criterion (i.e., no damage occurring to any devices on the opposite side of the isolation barrier) was satisfied.
River Bend SSER 3 7-3
On the basis of its review, the staff concludes that the MOR relays and optical isolator assemblies (models 13309947 and 14708804) used to provide physical and electrical isolation between redundant safety-related circuits, and between safety-related and non-safety-related circuits, satisfies the applicable accept.
ance criteria (i.e., an abnormal / fault voltage / current on one side of the isola-tion device does not affect the functional capability of circuitry on the oppo-site side of the device), and therefore, are acceptable.
This resolves Confirm-atory Item 26 as listed in Table 1.4 of the River Bend SER.
It should be noted that this evaluation does not include those isolation devices used in the emer-gency response and information system (ERIS) or the digital radiation monitoring system (DRMS).
These devices are discussed in Sections 7.7.2.3 and 7.6.2.7 of the SER.
7.3 Engineered Safety Features Systems 7.3.2 Specific Findings 7.3.2.7 Initiation of ESF Supporting Systems The River Bend design includes safety-related air conditioning units and unit coolers (listed be4 erin Table 7.1) which provide ventilation and cooling for rooms / areas containing safety-related equipment.
Table 7.1 Safety-related air conditioning units, units coolers, l*a and area serviced 4 ' (,
p s h ;.
Cooler Area serviced Cooler Area serviced j
1HVC*ACU1A*
Control room 1HVR*UC5 HPCS pump room 1HVC*ACU18, Control room IHVR*UC6 RCIC & RHR Division 1 1HVC*ACU2A+
Switchgear/ battery /
equipment room
(
cuble areas 1HVR*UC7 MCC areas i
1HVC*ACU2B, Swichgear/ battery /
1HVR*UC8 Main steam pipe tunnel, cable areas north 1HVC*ACU3A, Chiller equipment room 1HVR*UC9 RHR Division 2 equipment l
1HVC*ACU3g, Chiller equipment room area 1HVR*UCIA",
Containment 1HVR*UC10 MCC areas 1HVR*UC1B Containment 1HVR*UC11A East SGTS area / west l
1HVR*UC2 RWCU pump room equipment area i
1HVR*UC3 RPCCW and CR0 areas 1HVR*UC118 East SGTS area / west 1HVR*UC4 Auxiliary building equipment area general area I
+These air conditioning units start automatically following a LOCA signal
}
[i.e., reactor vessel low water level (level 1) and/or high drywell pressure]
i and load sequence permissive if power is available to the respective emergency buses and an associated chilled water pump it, running.
++These unit coolers start automatically on a LOCA signal if power is available at the respective emergency buses.
j River Bend SSER 3 7-4
Unit coolers 1HVR*UC2 through 1HVR*UC10 and 1HVR*UC11A&B do not receive auto-matic start signals.
These unit coolers must be manually started from the control room.
Because some of the unit coolers provide cooling for rooms con-tainin3 engineered safety features (ESF) equipment, the staff raised concerns that tha unit coolers did not automatically start in response to system level initiation signals (manual or automatic) for the respe:tive ESF systems.
The Technical Specification definition of OPERABILITY states that in order for a system, subsystem, train, component, or device to be considered operable, it must be capable of performing its function, and that all necessary attendant auxiliary / supporting items of equipment necessary for the system, subsystem, train, component, or device to perform its function (e.g., electrical power, cooling or seal water, lubrication,, etc.) must also be capable of performing their related support function or functions.
It is the staff's understanding that room cooling is required for ESF equipment to operate properly.
The staff was also concerned that ESF pump room high temperature conditions were not adequately annunciated in the control room.
The applicant has stated that unit coolers 1HVR*UC2 through 1HVR*UC10 and 1HVR*UC11A&B will be run continuously, and therefore, automatic initiation of the unit coolers is not required.
Control room annunciation is provided for certain conditions resulting in unit cooler failure.
Examples are cooling water supply valves closed and loss of power.
However, the staff was concerned that a unit cooler failure could go undetected.
All conditions that could re-sult in unit cooler failure are not/cannot be annunciated.
To resolve this con-t cern, the applicant has included surveillance of unit coolers 1HVR*UC2 through 1HVR*UC10 and 1HVR*UC11A&B as part of the control building and auxiliary build-ing daily logs, with the exception of 1HVR*UC8.
This surveillance consists of plant personnel physically going to the individual unit cooler locations and verifying air flow through the coolers.
The staff concludes that the daily sur-veillance is sufficient to ensure that a unit cooler failure does not go undetected.
Unit cooler 1HVR*UC8 provides cooling to the north main steam pipe tunnel.
This is a high radiation area which cannot be accessed for surveillance during i
t operation.
The applicant has indicated that the area served by 1HVR*UC8 is a small area containing several motor-operated valves and containment isolation valves.
The unit cooler is provided to keep the temperature in this area below the temperature limit of 122*F.
The temperature has been analyzed to go as high as 244*F on unit cooler failure.
River Bend Technical Specification 3/4.7.8 (Area Temperature Monitoring) requires that if the temperature exceeds the temperature limit by more than 30F*, the temperature be restored to within the limit within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, or that all equipment in the affected area be declared inoperable.
Redundant high area temperature alarms are provided in the control room from the safety-related leakage detection system (LDS) if the temperature in the north main steam pipe tunnel reaches 135'F. The staff concludes that adequate provisions have been taken to ensure that the temperature in the north main steam pipe tunnel area served by 1HVR*UC8 remains within acceptable limits.
On the basis of the above, the staff concludes that automatic initiation of unit coolers 1HVR*UC2 through 1HVR*UC10 and 1HVR*UC11A&B is not required, and that the combination of periodic surveillance and area temperature alarms is suffi-cient to ensure unit coolers operability, and therefore, the operability of the associated ESF equipment.
This resolves Confirmatory Item 30 as listed in River Bend SSER 3 7-5
Table 1.4 of the River Bend SER.
It is noted that air conditioning units 1HVC*ACU1A&B, 1HVC*ACU2A&B, and 1HVC*ACU3A&B are also ve daily in accordance with surveillance required by the control building's d log.
The areas served by these unit coolers are com y
operation.
high differential pressure and high discharge temperature for 1HVC*ACU 1HVC*ACU2A&B.
ture limits for those areas served b, all unit coolers listed abo n
exception of the containment unit coolers 1HVR*UCIA&B.
, with the coolers are provided with discharge temperature indication and low flow a The containment unit in the main control room.
7.6 Interlock Systems Important to Safety 6.2._3pecific Findings 3
wg 1. g,. 2. 1 M..
R essure lL ew hessaw S U"' a fIJC NS 7.6.2.5 Y
Information SystemIsolation Between the Neutron Monitoring Syste The rod pattern control system (RPCS) is a subsystem of the rod action c system (RACS) portion of the rod control and information system (RCIS).
RPCS is a redundant system (Divisions 1 and 2) designed to limit the cons The quences of a rod drop accident by restricting control rod movement (i.e tiating rod blocks) to within preestablished patterns.
., ini-from the 120-V ac emergency safeguards buses.
The RPCS is powered located in RACS cabinet 1H13*P651 in the control room.RPCS Division 1 circuitry is ceives inputs from Divisions 1 and 4 of the neutro This cabinet also re-and inputs from non-safety-related sources (e.g., n monitoring system (NMS),
module and the refuel platform).
the operators' rod control cabinet 1H13*P652, which receives inputs from NMS Divisions 2 a non-safety related sources.
NMS Divisions 1 and 3 are powered from reactor protection system (RPS) bus A, and NMS Divisions 2 bus B.
between the NHS and the RCIS, and between non-safety-related circuits and vent electrical faults from affecting redundant divisional The staff has subsequently reviewed all inputs to the RACS cabinets related and not safety related.
using optical isolation devices. All inputs to the RACS cabinets are buffered, both safe These devices are the light emitting diode /
photo transistor type mounted on printed circuit (PC) cards. Where RACS are from the same division (e.g., HMS, mode switch, turbine first-stage pressu rod position multiplexers, scram discharge instrument volume level), only the buffering is provided.
from a non-safety-related source, electrical isolation using qua rod isolator modules (discussed in Section 7.2.2.6 of this supplement) is pro-vided in addition to the buffering.
In addition, RACS inputs from the RCIS itself (e.g., from the rod gang drive system cabinet and the operator's control module) are isolated using the quartz rod modules.
The use of qualified isolation devices at the RACS cabinet boundary prevents electrical faults in non-safety related circuits external to the cabinets from affecting internal safety-related circuits.
isolation provided between the NMS and the RCIS is sufficient because (
River Bend SSER 3 7-6
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i, addition to the buffering, coil-to-contact isolation is provided, (2) all other inputs to the RACS cabinets are buffered / isolated as discussed above, and (3) should a fault within the RCIS degrade the NMS, redundant and diverse in-strumentation is available to accomplish all required protective functions (reactor scram and rod block).
This resolves Confirmatory Item 38 as listed in Table 1.4 of the River Bend SER.
i 7.7 Control Systems 7.7.2 Specific Findings 7.7.2.1 High-Energy Line Breaks and Consequential Control Systems Failures The applicant was asked to determine whether multiple non-safety-related (con-trol) systems failures, resulting from the adverse environment created by a high-energy line break (HELB), could result in consequences more severe than previously considered in the FSAR Chapter 15 accident analyses.
This concern is addressed in IE Information Notice 79-22.
The applicant has performed an analysis of the River Bend Station control systems and high energy piping, and concluded that for all postulated HELBs, the consequences of the break coupled with the effects of all postulated non-safety-related equipment failures, are bounded by (i.e., are less severe than) the consequences of tne events analyzed in Chapter 15 of the River Bend FSAR.
Details of the applicant's analysis and the staff's evaluation of the analysis are provided below.
The applicant identified all non-safety-related/ control systems that could affect reactor critical parameters (e.g., water level, pressure, critical power ratio).
Systems with no controlling functions and systems that do not inter-face with reactor operation or reactor parameters were eliminated from the analysis.
Examples of these systems are lighting, communications, annunciators, the computer, refueling equipment, ventilation systems, mechanical and struc-tural systems (e.g., structural steel, tanks, cranes), and electrical systems which will not impact critical reactor pirameters on loss of power.
For those systems that can affect reactor critical parameters, the applicant ccmpiled a list of system components to be included in the HELB analysis.
Mechanical com-ponents (e.g., tanks and pipes) and instruments providing dedicated inputs to the computer, indicators, alarmt, or position status information were excluded from the list.
Instrument-sensing lines, and position switches that are inter-locked with other equipment were included in the analysis.
Motor control cen-ters (MCCs) were considnred for analysis; however, since none of the remaining components were mounted at MCCs or powered directly from an MCC, MCCs were elim-inated from the analysis.
In general, the final list of non-safety-related/
control system components that could affect critical reactor parameters consisted of valves, switches, transmitters, and controllers.
The applicant then identified all high-energy lines at River Bend using the cri-teria for high-energy lines established in FSAR Section 3.6.
High-energy lines are defined as those which are in operation or are maintained pressurized during normal plant conditions where the maximum temperature of :he fluid in the line exceeds 200'F or the maximum pressure of the line exceeds 275 psig.
High-energy lines that operate above these limits for less than 2% of the time are classi-fled as moderate-energy liges and were excluded from the analysis.
High energy lines that are less than 1# inch in diameter were also excluded.
The exclusion of these lines is acceptable because (1) breaks of moderate-energy fluid system River Bend SSER 3 7-7
piping are not postulated to occur in accordance with Branch Technical Position (BTP) MEB 3-1 (see SRP Section 3.6.2), and (2) the environmental effects of breaks of lines 1 inch in diameter or smaller are less severe than for larger lines considered in the analysis (typically, these are instrument-sensing lines-whose failure can be detected from the abnormal behavior of instruments asso-ciated with the broken line).
Instrument line failures resulting from breaks in larger high-energy lines were considered in the analysis.
The applicant performed a plant walkthrough using maps of the reactor, turbine, and auxiliary buildings in order to subdivide the plant into HELB zones.
Each zone is a separate area of the plant which is bounded by walls, ceiling, floors, etc., so that the environm?ntal effects of a HELB in a given zone are confiaed to that zone, or in some cases, are also confined to adjacent zones.
Certain zones extend between elevations because of open floor gratings or hoist openings between elevations.
Next, the applicant determined those zones in which components that can affect critical reactor parameters are located.
The high-energy Ifnes identified were then assumed to break at all locations (zones) where the non-safety-related/
control components are locatea.
The applicant used a " sacrificial approach" when analyzing the effects of a pipe break in a given zone (i.e., all non-safety related/ control components in that zone were assumed to fall).
All component failure modes were considered to determine the worst-case failures i
I for all components.
Where a HELB could affect non-safety-related/ control components in more than one zone (e.g., a break within a small cubicle can conceivably blow out the door and the environmental effects of the break could affect components in the adjoining larger volume zone), all components in all affected zones were considered to fail in their worst states.
The sacrificial approach covers all potential component failure mechanisms (i.e., pipewhip, jet impingement, humidity, temperature, pressure, and radiation) since this approach assumes that the break will adversely impact all components in the l
respective zone (s).
The applicant has analyzed the worst-case combined effects of each HELB and all consequential non-safety-related/ control systems failures. Where the worst-case failure mode for a component was not readily discernible, all failure modes and their consequences were analyzed.
The consequences of these events were then compared with the accident and transient analyses presented in Chapter 15 of the River Bend FSAR.
The worst-case event was determined to be a break in a high energy line of a moisture separator vent and drain in the turbine building which results in a partial loss of feedwater heating.
The i
. failure of non-safety-related/ control components in this zone can result in a further loss of feedwater heating and a resultant increase in reactor power, and may cause a turbine trip.
The applicant determined that if the turbine trip occurs at a reactor power level elevated from the initial operating value, the reactor may experience a change in critical power ratio greater than that 3
considered in the FSAR Chapter 15 analyses.
However, subsequent analysis per-formed by the applicant has demonstrated that the effects of this accident event, including consideration of a single active failure in a mitigating safety system, 1
are bounded by the Chapter 15 analyses.
The app 1tcant has determined that the combined consequences of all other HEL3s and consequential non-safety-related/
control system component failures are also bounded by the River Bend accident and transient analyses presented in Chapter 15 of the FSAR.
River Bend SSER 3 7-8
-~..=-
i On the basis of a detailed review of the applicant's analysis of 11EL8s and con-i sequential non-safety-related/ control system component failures for several different zones (including the worst-case-event zone), the staff has concluded applicant are acceptable.that the methodology used and the results of the ana Table 1.4 of the River Bend SER.This resolves Confirmatory Item 41 as listed in L
t i
l i
l Alver Bend $$ER 3 7-9 i
a l
i t
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L 8 ELECTRIC POWER SYSTEMS i
8.3 Onsite Emergency Power Systems t
8.3.1 AC Power Systems In Section 8.3.1 of the River Bend SER, the staff stated it would confirm the correction of a typographical error on FSAR Table 8.3-2 regarding deenergiza- -
tion of the low pressure core spray (LPCS) or residual heat removal (RHR) pump in 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and confirm that procedures exist to control this. The staff also stated that it would evaluate a synopsis of the Division I and II diisel generator qualification test results when they are available. The Division I and II diesel generators are manufactured by Transamerica Delaval, Inc. (TOI).
The staff has reviewed the qualification of similar diesels at Shoreham Nuclear Power Station with respect to IEEE Std. 387 and RG 1.9 and has found them acceptable. The TOI diesel generators, however, are also the subject of a detailed generic review which was initiated as the result of failures experi-enced on the Shoreham units. The results of the generic review will, there-fore, govern for qualification of the River Bend units. These results for River Bend are reported below in the section titled, " Qualifications of TDI Emergency Standby Diesel Generators."
FSAR Amendment 20 states that the Division I and II diesel generators were each l
~
given a load capability test at their rated load of 3500 kW for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and that this satisfies the 110% overload requirement of RG 1.108,' Position C.2.a(3) j because it is more than 110% of the machines' qualified load. The staff does not agree that testing the machine to 110% of the maximum qualified load that it will carry meets the RG 1.108 requirement. The requirement is to test the I
machine to 110% of its continuous ratino. The staff, however, is making an exception to this requirement for the Division I and II diesel generators at River Bend because of the concern identified in the TDI diesel generic evalua-tion.
The staff has determined that the diesel generators are capable of
[
delivering 3130 kW continuously and load testing should be limited to this 08/01/85 8-1 RIVER BENO SSER 3 SEC 8
value. Although these tests do not strictly adhere to the guidelines of RG 1.108, they do adequately demonstrate the diesel generator capability to assume the actual load requirecents for accidents and transients as described beliw. The remaining test requirements in RG 1.108 will be conducted on the Division I and II diesel generators as prescribed in the regulatory guide.
Because the Division III diesel generator is net a TOI unit, it wfit be tested l
in accordance with all the requirements of RG 1.108.
With regard to the deenergi:ation of the LPCS or RHR A pump, the applicant has l
since revised the entire loading profile on the diesel generator units which I
the staff had originally reviewed. The most recent diesel generator loading l
for Divisions I and II was submitted by the applicant in FSAR Amendmant 21.
The applicant has reduced the loading on Divisions I and II from an original maximum of 3724 kW down to the current maximun of 2886 kW to demonstrate adequate load margin on its TOI diesel generators. The applicant has accom-f plished this through a combination of transferring loads (Standby Service Water Pump 2C to Olvision III),. delaying the start of loads, manually deerergizing loads, eliminating loads, and assuming reduced power input to loads.
This l
resolves Confirmatory Item 44.
The kilowatt demand of each load on the diesel generators was calculated by using brake horsepower and the efficiency data supplied by vendors cf the respective equipment. Operator action is assumed at 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> into tFe LOCA load profile to shed automatically sequenced loads and load other rc. quired manually actuated loads. Motor-operated valves are assumed to have completed their stroke by 10 minutes into the load sequence. The staff has reviewed the proposed loading profile of the Olvision I and II diesel generators and finds it acceptable. Therefore, Outstanding Issue 10a is closed.
The load-carrying capability of the Division I and II diesel generators is addressed as part of the TOI generic review. The evaluation of these units is covered below in the section titled, " Qualification of T0! Emergency Standby Otesel Generators."
l 08/01/85 8-2 RIVER BEN] SSER 3 SEC 8
As stated above, the Standby Service Water Pump 2C will be moved to the Divi-sion III (HPCS) diesel generator. Associated with this change, a standby service water pump room vent fan and standby service water pump discharge valve will also be energized from Division III. All the Division III loads will be simultaneously loaded onto the diesel generator with the exception of the itandby service water pump motor which will be sequenced to operate at 30
,econds after the diesel generator circuit breaker closes.
The maximum load on
- he diesel generator will be 2393 kW, which is less than the diesel generator continuous rating of 2600 kW. The staff has reviewed the revised loading of the Division III diesel generator and finds it acceptable.
InSection8.3.1oftheSEgitwasstatedthatallCla.sIEmotorsatRiver Bend are capable of starting and accelerating their driven equipment with 70%
of motor nameplate voltage applied to motor terminals without affecting perfor-mance or equipment life.
FSAR Amendment 19 has changed the 70*.' figure to 80%.
j The staff was concerned that if the 80*. figure applied to all Class 1E motors, the motors would not be capable of starting during delraded voltage conditions.
Thh is based on the appitcant's March 5,1984, letter which provided a voltage pro'lle that showed less than 80*. startirg voltage available to start major Class 1E motors under degraded voltage ccnditions.
In FSAR Amendment 21, the applicant clarified thtt only the motors driving air compressors ILSV*C3A and ILSPC3B require 80% valtage to start, and calculations have determined that the minimum starting voltage available at the mctor terminals is 89.63%. The remaining class IE motors still require only 70*. voltage to start.
This resolves the staff's c:ncern on this issue and is acceptable. Therefore,
~
Outstanding Issue 22 1. closed.
fpl't k(,N k 6
08/01/85 8-3 RIVER BENO SSER 3 SEC 8
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SUPPLEMENTAL SAFE Y ALUATION REPORT RIVERBEND TION UNIT 1 DOCV NO 50-348 8etN4 4'
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'IP b oNac m-to-the-NRC-staM-has-been the reliability of standby emergency diesel generators (EDGs) manufactured by Transamerica Delaval, Inc. (
roI p ru W/w G W M S 4at River Bend and other sites.
Concerns regarding the reliability of large; bore, medium-speed diesel generators manufactured by TDI for application at domestic nuclear plan (A-were first prompted by a crankshaft failure at/Shoreham n August 1983.
However, a broad pattern of deficiencies in crifical je gine components
.d, n.
.c.,/w re4441 O'v1R1 subsequently became evident at[Shoreha(aTd at other nuclear and non-nuclear facilities employing TDI diesel generators. These deficiencies
/.twu%m/
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cture and QA/4C.by TDI.f~4 png) gfh stem from inadequacies in design, manu y
3 River Bend St:thn Unit--r is served by two TDI,m,,odel DSR-48 diesel engines, designatedg:aaarygiresi 7 reto (EDGsI1Aand18. These EDGs a inlineeight-cylinder,four-cycle,turbocha)ged,afte.rcooledengines.
j Each has a rameplate continuous;1oad rating of 3500 )S with an overload rating of 3900 /W, and operates at 450 rpm with a brake mean effective gf pressure (erEp) of 225,sig.
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has been actively involved in the TOI Diesel Generator Owners Group,
- k. ot+Cd t1 an organization fonned by 3Stf and Mother utilities to resolve t
reliability issues stenning from the early problems with TOI engines.
i p g eest With the assistance of the Owners Group,49tt has largely completed a comprehensive program to verify and enhance the reliability of the River Bend diesel (generators for standby nuclear service. The staff's evaluation of this program is provided te. win, b4/OW -
i (t)
- 2.0 5.ag. ad rd.0':ce:d- ^
g, h TOI Owners Group "'Z.
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l On March 2,1984, the 70! Olesel Generator Owners Group submitted a plan totheNRCwhich,throughacombinationofdesignreviews, quality revalidations, engine tests and component inspections, is intended to j
provide an in-depth assessment of the adequacy of the respective utilities' TOI engines to perfonn their safety-related function.
i The Owners Group rogram involves the following two major elements:
(0)
Phase !! Resolution of 16 known generic problem areas intended by the Owners Group to serve as a basis for the licensing of plants during the period prior to completion and implementation of the Owners Group Program.
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Phase II: A design review / quality revalidation (DR/QR) of a large set of important engine components toptsure that their design and manufacture neluding specifications, quality control and quality j
assurance and operational surveillance and maintenance, are j
i adequate.
The Owners Group Program includes provisions for special or expanded engine tests / inspections, as appropriate, to verify the adequacy of the engines and cogonents to perfonn their intended functions.
The 16 known problem areas (Phase ! issues) identified by the Owners Group include'the engine base and bearing caps, cylinder block, crank-shaft, connecting rods, connecting rod bearing shells, piston skirts, cylinder head studs, push rods.
- rocker ann capscrews, turbocharger, jacket wate[ pump, high-pressure fuel oil tubing, air-start valve cap-screws, and engine-1nounted electrical cable.
~
The Owners Group has issued reports detailing its proposed technical resolution of each of the 16 Phase ! issues. These generic reports l
analyze the operational history, including failure history, of each of these components. In addition, these reports evaluate the causes of earlier failures and problems, the adequacy of the components to meet I
functional requirements, and provide recomendations concerniYg needed component upgrades, inspections, and testing.
l 4-1 L
The Owners Group has also issued the DR/QR (Phese !!) report, Revision 1,-
dated March 7, 1985, for the River Bend EDGs. This report documents
)
l the results of the design review and quality revalidation which was performed on all ccmponents critical to the operability and reliability of the engines, including the 16 components identified by the Ownert, Group as known problem areas. The Owners Group performed the design reviews and identified the component quality attributes to be verified.
The actual component inspections to verify the quality attributes were generally performed by GSU. Engineering dispositions made by GSU on the basis of the inspection results were reviewed by the Owners Group.
(l*&
- 24. Engine Inspections and Tests e
e e
The engine disassembly and on performed in support of the DR/QR effort took place in 1984, y' - te preoperational testing. The inspec.
tions included all Phase I components plus inspection of the engine gears and wrist pin bv.t'ngs. Other components were included in the inspection, based on operating experience at other plants and recomendations of the Owners Group as needed to support Phase !!. A sunnary of the inspections perfonned and the results was enclosed with a letter dated May 17, 1985, and was recently updated by letter dated June 21, 1985.
Y W
Y E"rhg engine reassembly, crankshaf t deflection measurements, torsio-3 graph testing, and engine break-in tests were conducted in accordance l
with NRC staff criteria as identified in Section 4.6, " Interim Basis for 1,1 censing," of the staff's generic evaluation of the Owners Group Program l
1 l
1 I
j )
in W Plan which was enclosed by letter dated August 13, 1984, to J. George, Owners Group,Cfro(r A
D. Eisenhut NRCy S.c &^d A description of the preoperational test program of theJBS' engines was Jiust'P' submitted with the letter dated May 17, 1985. Except as noted below, 4WN J5B states that the test program was perfonned in compliance with r
m Re; & te y Gw44e 1.108. The preoperational test program did not include.
2/
fyltaew
% *ttEd
~
a 2-hour overload test pursuant to Sectica C.2.a(3) of RG 1.108 45tl justified the Axception to the criterion (see letter dated May 15, 1985),_ -
on grounds that a 24-hour test at the manufacturer's continuous rating of FSM~
3500 [W exceeds by 10% the maximum load (3130fW as given in, Figures 8.3-2aand2bja eS?"-) at which the engines would actually be run during
\\
p.;g emergency service.
mafntained, therefore, that the 24-hour test at 3500 fW met the intent of the [dgulatory juide.
At the conclusion of the preoperational test program, an engine inspection not involving major engine disassembly was conducted. This inspection a
~
included visual inspection of critical components by removal of access covers and analysis of the engine oil. The inspections and results were i
documented by letter dated June 21, 1985.
1
?
. (I. 3) 2.3 Component Replacement and Modifications Some of the more significant component replacements or modifications implemented to date involve Phase I components and include the following:
The cylinder liners, cylinder heads, cylinder head studs, and block liner landing have been modified to reduce mechanical interference stresses in order to increase the margin against cylinder block cracking.
Original piston skirts were replaced with improved "AE" piston skirts W
Valve pushrods, replaced with improved friction welded design.
)
Turbocharger mounting bracliet was stiffened to reduce vibration.
Cylinder heads have been replaced with newly manufactured " Group III heads" to reduce potential for water leakage into cylinders.
A The jacket water pumps were replaced with pumps with a nodular fron impeller without a keyway.
Fuel injection tubing not meeting acceptance criteria developed by the Owners Group w #eae replaced.
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2.4 Oualified Load g
The adequacy of the Pat crankshaf t was a major focus
'f attention between h&
11weU 1lutt JStr'and the NRC staff. The JS$ crankshafts are,sim lar in design to the replacement crankshafts at Shoreham, which were a/
pproved by the staff for a qualified load of 3300fW on the basis of Ir cycle test at loads equal h */
~
00[W. M differences t
nerators and flywheels to or exceedin between and Shoreham, operation of the Jaff engines at 3130 [ produces nominal torsional stresses in the cranks' hafts which are comparab at Shoreham at7300-[W. However, the factor of safety for the BBS' crank-shaft at 3130 W co Id be up to 14% lower exists at Shoreham at 3300 [W due._to a higher tensile strength wMeh exists in the Shoreham crankshafts and the fact that they have been shot peened.
h JStf has submitted a number of analyses and data to support 3130 [W as an acceptable qualified load level in Ifeu of perforping a confirmatory f
w% M 1
cycle test at that load level on ee-Ret engine. Although3130fWl is less than the manufacturer's continuous nameplate rating of 3500 /W, it exceeds the maximum emergency service load which would lgcedon these engines during an actual design-basis accident (see Table 8.3-2 C fJ.e. y b m g
FAR). -GS9 stated in its letter dated May 17, 1985, that appropriate dwk Y operating procedures have been prepared to ensure that the.S85 engines are not loaded above the " qualified" load.
i
. Failure Analysis Associates, Inc. (FaAA), a consultant to the Owners Group, i
has estimated a factor of safety of 1.39 for the crankshaft at 3130 )(W w *ftEM%
/ 4 m p A c.
and a nominal speed of 450 h.P(66tf letter dated May 16,1985). G9tl,also submitted a report from its consultant, FEV (Research Society for Energy, 9
Technology and Internal Combustion Engines) by letter dated June 12, 1985.
FEV calculated a safety factor of 1.205 for the crankshafts at 3130 [
and 450 which, according to FEV, is within the range nonnally considered adequate by German engine manufacturers. Differences between the FaAA and F_EV.es,timates were attributed by FEV to the use of different S-N (stress vs. cycles) curves. FEVuseda[S-Ncurvebasedonbenchtests of actual crankshafts, whereas FaAA, according to FEV, employed a[S-N curve based on laboratory data.
In response to concerns by the NRC staff concerning the proximity of the nominal speed of 450 h to the 5th-order harmonic resonant speed x
- a..:a of 455 h, GW3 rov ~ided additional information from FaAA by letter dated June 12, 1985, indicating the response to the 5th-order harmonic is small and is excited only by variations i the combustion pressure from cylinder to cylinder. To prevent sustainedyeration under con-ditionsofengineimbalanceandoverspeed.[w111adoptthefollowing An
- HEW W (02-letter dated June 12,1985):
e
1
-g.
)
j A caution statement will be added to the engine operation and surveillance procedures to avoid operation between 453 and 457 During engine operation, exhaust gas temperatures will be monitored to verify that they remain within 2 5 of the average for all cylinders.
Generator-frequency will be monitored and maintained within*60 Hz 2 0.2 Hz.
ggg
- /
Evaluation R& f
[to this fis a Technical Evaluation Report (TER) enti E :h:u :
kff
" Review and Evaluation of Transaurica Delaval, Inc.j 0fesel Engine ReliabilityandOperability--[RiverBendStationUnit1." This TER was prepared by Pacific Northwest Laboratory (PNL) which is under contract Ggt 6 to the NRC to perform technical evaluations of the TDI Owners Group generic program, in addition to plant, specific evaluations relating to thereliabilityofTDIdieselj7 s retained the services of a
several expert diesel consultants as part of its review staff.
The staff concurs with the findings of the PNL TER, and incorporates S ER.,^ >" %&
the TER as part of this 5:':ty I/: h:t h: i ;;rt by reference, at
n 9.
This and the end e xd TER precede completion of the NRC/PNL review of the proposed generic resolution of the Owners Group Phase I issues and of the total DR/QR Program for River Bend.
Final completion of these NRC staff /PNL reviews of the generic resolution of Phase I and issues is anticipated by September 1985. Final letion of the NRC staff review of the total DR/QR program at s anticipated by the first refueling outage. However, the staff and its PNL consultants find that these reviews M
have progressed,sufficiently pedf that all significant issues warranting p
i ention as a basis for issuance of an operating license for JFr have been resolved.
'( 2 1) 4ri Engine Tests and Inspections PNL's review of the engin,e test'and inspection program at RSS is provided M*
in Section 4 of th maria"d PNL concludes that the test program conducted by GSU and other TDI engine owners was adequate to identify problems with engine components and that tests were adequate to verify component ability to meet the load and service requirements. PNL also M b.A finds that component upgrades at were responsive to the Owners Group reconinendations.
e
w - N
. The NRC staff concurs with these findings and rotes the following:
N W ')
b Detailed disassembly and inspection of the JSt engines as part of W
the DR/QR effort were performed ;Mr to preoperational testing.
This differs from the staff position taken in Section 4.6 of the staff's generic Safety Evaluation of the Owners Group Program Plan Y
which called for such inspections to take place ; 2; G z -t t r preoperational testing. The staff, considers the h to be acceptabl.e on the basis that these inspections wer tended to verify the "as-manufactured" quality of the ngines rather than to verify design adequacy. The adequacy of the component designs to perfom' their intended function and to sustain their loading environments without excessive wear and tear has been evaluated as P?,
part of the design review process of the DR/QR program. A major g
element of this design review effort involved review of relevant operating experience of TDI engines in nuclear and non-nuclear service to identify potential problem areas.
1 i
Preoperational testing was performed for engine loads ranging to the full manufacturer's continuous rating of 3500 [W. Because this a
j exceeds the qualified load rating (3130 fW) of the ranksha f ts, i
the staff was concerned about the potential for inducing cracks in 4
i
the crankshafts during the preoperational testing. At the staff's
- n,J
- request, 16n'd'ucted an inspection of the three most highly loaded crankpins in one engine, SD 1A, by fluorescent liquid penetrant and eddy current subsequent to preoperational testing. That inspection was witnessed by one of the PNL consultants and revealed no evi ence offatiguecrackinitiation(seeSection5.3.5ofe E ).'
$WW 1
The exception taken by JStf against performing (the twe-hour overload fo$lh %
Cr
~
test in accordance with kctica C.2.a(3) of "c p htc., Ow;de 1.108 is acceptablbo'thestaff. The 350P load at which the preoperational tests were conducted exceed the maximum continuous emergency service loads which would ever be experienced. The 2-hour overload test would t
provide little if any added assurance of the capability of the engines to operate at 3130-fW qualified load level and might, at the same time, contribute unnecessary wear and tear on the crankshafts.
(), 2) iht Component Problem identification and Resolution g
t Section 5 of t TE" qvn.q.g PNL's review ofJSP?, actions c
to upgrade and/or qualify the 16 engine components known to have had significantproblems(PhaseIcoeponents). The PNL evaluation also considered the pertinent Owners Group Phase ! reports addressing the operating history for each component, Owners Group studies regarding the causes of previous problems, and adequacy of the components to meet functional requirementsjand Owners Group recomendations regarding needed component upgrades, inspections, and testing.
. 64 W a " % this evaluation, the NRC staff and PNL have concluded that each
&M of the Phase I components in they engines is adequate to perfonn its intended function at a " qualified" load rating of 3130 [W. This finding 7
is subject to implementation of an tableenginemaintenanceand surveillanceprogramasidentified[Section5.
y g,1f n-With respect to crankshafts, PNL has concluded in Section 5.3.5.3 of the.
eac' :M *=r-t that the FaAA and FEV analyses substantiate the adequacy of the crankshgts,for operation to 3130 f. As noted by PNL, extensive testing e
reham engines and the absence of any evidence of cracks intheR)WSD1Acrankshaftfollowingpreoperationaltestingprovide 3
Pn k4 additional evidence of the adequacy of theJS5' crankshafts. On this basis, the staff concludes that a confirmatory test for 10" cycles is not needed NY to support 3130 W as the qualified load of the y engines.
(?,3)
.>.t Resolution of Open Issues Identified by PNL
'W:r;.:::d "L. 4ei t, PNL reconsnended implementation NE In Section 5.0 of t..:
M of the following actions pertaining to P,hase ! components ;Me-to
~
nwn h;nn;; :" an operating license:
)
- 'n!,A ^eth c'The idler gear on SD 1A 6 M I~
r ps?fxWA,
(l)
(#J / reload torque on all connecting rod bolts should be verified to be I
in accordance with TDI reconenendations.
e.
(C) g v4p_,9 4 :pc;t';r ;M"1a ba n*d:- :d Odhe turbocharger beari M k W !j a s @
h (s
and nozzle ring of SD 18 and ther a liquid penetrant test be 3
perfortned on welds retaining the core plug (hub nut) of both SD 1A and IB. Verify that TDI SIM 300 has been implemented and that the hub nuts have been staked on both engines.
~
(M, Replacement jacket wate(pumps with modifications recomended by the Owners Group should be installed.
(6)
[5T Owners Groupnecomended inspections of replacement jacket waterO v
pump to be installed on SD 1A should be completed.
3 c f cotter pin holes do not line up at the specified torque, the I
nut washer or put should be. reduced in thickness until the pin holes do match.
h)
Fuel-oil injection tubing which did not meet Owners Group acceptance s
criteria should be replaced with acceptable tubing, i
M
$W f;;;h;;d P'". r;i,c,. t Afr0 submitted an Subsequent to preparation of L:
d67M M eh A updated inspection reEart by letter dated June 21, 1985. -h ;;d = :
g~w %
review of thaw submittal, the staff concludes that each of tfie above items has been successfully closed out.
In the case of the turbocharger thrust bearings, signs of wear were observed following 100 engine starts.
Althou h the bearings were observed to remain in an operable condition, W
Mt JStf e ected to replace th" ^=*i ;:.
15 -
0$fS N /
In Section 5.7.5 of the encic::d e"L
- p;rt, PNL reconinended that liquid penetrant tests be performed on the rib area near the wrist pin, and on the rib at the intersection of the wrist pin boss for all piston skirts from at least one engine. However, PNL concluded that these inspections Jattlas l
could be delayed until the first major engine overhaul or when the pistons,
g become available for inspection, prier th =te, This item corresponds to an Owners Group recocinendation, yet it appears to the staff to have been omitted
'ce,w/ 4 from a computerized. listing of the status relative to each Owners Group recomendation which was provided to the staff by letter dated May 3, amd 1985, with en updated '^++- V &
^*^d June 26, 1985. Although not an imediate issue with resp!.t. *ffJicu$ address this issue ect to issuance of an operating license, the f
staff will require that cr te h-N Y ='. ce o f th e
?
.sla554 final evaluation of the'bR/QR,rogram at AfHh The staff will 1
N# 1 also require at that time, that GJIPiave completed a QA check to verify I
the completeness and accuracy of tracking system, implementing, and procedural documents relating to the implementatio 1
n
,ry reconsnendations in Appendix I of the DR/QR report. 3bere fM M tok his t
tan. Ala//-
EWM exception to an Owners Group recomendation, tMs should be reported iv fth appropriate justification M N e
g b. 'O
-t:T Engine Maintenance / Surveillance Program The NRC staff and PNL have identified development of an appropriate maintenance and surveillance (M/S) program to be a key aspect of the overall effort for establishing the reliability ard operability of TDI
. N engines. W has agreed to implement the M/S program identified in Q p %,t w Appendix II of the RBS DR/QR Report, Revision 1 (see SStf letter dated May 17,1985). Appendix II of the DR/QR Report presents a schedule of M/S procedures recomended by the Owners Groups for implementation fm W -
a t JOS',
Y
~
&:cd e-its evaluation of Appendix II, PNL has made a number of reconnendations which are identified in Section 6 of t@h:
M,
- ksed PNt i cge> E.
Thess-reconnendations address the maintenance items, operational surveillance, and r.tandby surveillance.
PNL notes that its Rim &cf recommendations are intended to augment the M/S plan for PBfi rather than to supplant it.
By letter dated July 29,1985,SSt! connitted to incorporate the PNL reconnendations into its M/S program by August 30, 1985, with the excep-tion of some of the PNL r connendations shown in Table 6.3 of t i
h C hl &f h 9
PNL ra m t.
GSU has proposed a dised table shown as Table 1 of this 3
.i The proposed changes include deletions of PNL reconnendations to perform a visual check every hours of starting air pressure, lube oil tecperature, jacket water temperature, lube oil sump level and fuel oil w-r y
day-tank level. JSt1 would continue to log each of these parameters every MW 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> as reconnended by PNL
'?th the u.gth: that only, inlet y
(rather than inlet and outlet) temperatures would be logged for lube oil temperature.
Furthermore dhA W, each of the subject parameters has an associated
<J y<
annunciator. pStf will test the annunciators every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> rather than every hours as reconnended by PNL.
It is the staff's overall YMW judgment thatKs proposal will not result in a significant reduction MM in the effectiveness of the JST standby surveillance program, and is therefore, acceptable.
YrLY z
At the NRC staff's request,[also comitted to incorporat4ag the following items into its M/S program by August 30, 1985:
(G)
& &'c
/perational and surveillance practices identified in.GS&5 letter dated Jung,12, 1985, concerning the monitoring of engine speed, exhaust gas temperatures, and generator frequency g (O
@p.44 A h) fdditional PNL M/S recomendations discussed in Section 5 of the-er. closed PNL re;;rt and listed below:
D,r) h)
idler gear assemblydwners Group recomendation to clean idler ge3r and hub ting surfaces should be incorporated
.Er dt*
into the JB5 maintenance and surveillance program if not 3
already e m.
This item was not included in the Appendix g
II sumary of the DR/QR report, although it was identified in Appendix I.
f W
on h
idler gear assemblyh^GStf should verify that proper torque specifications are incorporated into the maintenance /
surveillance program. There appears to be a discrepancy g fm n l-between Appendix I (80 20 ft -
Appendix II p 9g (70 20 f t -
) of the DR/QR report. #
l v
L.
N
~ (lIl h*
push rodsM For future purchases of push rods, Mshould
~
perform destructive verification of weld quality by sectioning random samples from each manufacturing lot.
y$
Finally, the has also agreed to perform a QA check of implementing and procedural documents pertaining to the maintenance and surveillance program to ensure the completeness and accuracy of these documents g
relative to the. recommendations of the Owners Groups and PNL. JS will complete this check by August 30, 1985.
A O
_bsd v+ the above, the staff concludes that the GS1 M/S program for engines 1A and IB at RBS is acceptable.
Furthennore, the staff finds that no
[
exception to GDCf17 will be needbd to support issuance of a license for O
fuel load pmr te completion of the afo,rementioned actions by August 30, hbY 1985. This is.d= : the f:M that GSU has completed a comprehensive program of engine inspections, testing, and component upgrades which ensure that the engines are in a good and operable condition. The actions to be completed by August 30,1985)will ensure the adequacy of the plant M/S program to continue to maintain the engines in an operable and reliable condition over the life of the plant.
It is reasonable to expect that certain changes to the M/S p gram may become appropriate in the future based on operating experience. The staff will require that any changes to the M/S program be subject
l l
~
to the provisions of 10 CFR 50.59.
In addition, NRC staff /PNL i
conclusions relating to the adequacy of the crankshafts, engine blocks, and cylinder heads are particularly dependent on certain periodic inspection and/or surveillance checks. Thus, the following elements of the M/S program will be license conditions:
h)
O Crankshafts shall be inspected as follows:
Y, SD 18: During-the first refueling outage, inspect the fillets and oil holes of the three most heavily loaded crankpin journals (Nos. 5, 6, and 7) with fluorescent liquid penetrant and eddy
'b " current as appropriate.
SD 1A and IB: During the second and subsequent refueling outages, inspect the fille [s and oil holes of two of the three most heavily loaded crankpin journals in the manner just 4
mentioned.
SD 1A and IB: During each major engine overhaul, inspect the fillets and oil holes of the two main bearing journals between crankpin Nos. 5, 6, and 7, using fluorescent liquid penetran and eddy current as appropriate. This inspection is# 4<.
in addition to the A
crankpin inspections.
(b)
N Cylinder blocks shall be inspected at intervals calculated using the cumulative damage index (DCI) model and using inspection methodologies described by Failure Analysis Associates, Inc. (FaAA)
. ~
cr i
report entitled Desian Review of TDI R-4 Series Emeroency Diesel JW Generator Cylinder Blocks"(FaAA 9-11.1)) dated Decembe spect cylinder liner loading are&W Lirou pe etantIn./
a any time liners are removed. Visually inspect daily between adjacent cylinder heads and the general block top during any period of
~
continuous operation following automatic diesel generator startup.
(C)
~
.. n t',. -f M The 'NYEdbshall roll the engines over with the air-start system per to any planned starts, unless that planned start occurs within f hours of a shutdown.
In addition, after engine operation, the engines shall be rolled over on air after hours but no more than hours after engine shutdown and then rolled over once again approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after each shutdown.
In the event an engine is removed from
^
service for any reason other than the rolling over procedure 4
v
~
pe4 w J.o expiration of the hour or 24-hour periods noted above, that engine need not be rolled over while it is out of Once the engine is returned to service, the Uce g ' M service.
.c shall roll it over with air once at the time that it is
-lec & Y returned to service. Any head which leaks te te a crack shall be replaced.
l'
" D
( ?,5
.A4 Additional Reporting Recuirements Except as noted belcw, the staff is not imposig ad,di al reporting requirementspertainingtotheTDIdiesel(a yond what is already 10 cfR '
to cPIL to CPP-9 required in the regulations (e.g.,-Peets 21, 50.72, and,50.73), and by the plant Technical Specifications. The exceptions involve any cracks
~
which may be found in the crankshaft or in the engine block between stud holt.s of adjacent cylinders.
Either of these unexpected situations could involve a potentially serious concern regarding the future oper-
$7 E
ability of the-engine.
In these cases, the staff will require by I
E b
condition of the license that any proposed resolution be approved by the ;o I
NRC staff pef e+r to returning the engine to an " operable" status.
J u-g i
I l'
(7. b )
$E M Load Restriction Recuirements E
I E'
L The plant Technical Specificatio3s will limit surveillance testing of c
7
?
$ W 1 Tech m'e a S+se 9 6 f 5
i
$ 8, engines IA and IB pursuant to,Section 4.8.1.1.2 to within a load range 3
,g of 3030/W to 3130f consistent with the qualified load rating of the y ~, j i
E engines.
j I
E 7
S".
e I
u Engine operating procedures, operator training, alarms, etc., to
$[
minimize the potential for overloading the engines bey (ond 3130 jdl eq g ;
g,g are addressed in the next section of this M,e,'~=? Tr. 3. l (l y
g 1
The staff wil AM j
g
+:
.c -
that the following actions be perfonned in the event that the engines 2
g
+
f should be operated in excess of an indicated 3130 WW:
2
.E
- 5. J e
7 4.
.c:
c' 6
k fl7 Momentary transients (not exceeding 5 seconds) gMk d
tr t: changing bus loads t'
need not be considered as an overload.
i l fd
- at For indicated engine loads in the range of 3130)(Q to 3200 )d for to)aperiodlessthantwehours[e,noadditionalactionshallbe 1
required.
For indicated engine loads in the range of 3130[to 3200M for a LO ff37,acrankshaftinspection 1
period equal to or exceeding twe hours pursuantto[ tem elow)shall ba perfomed at the next refueling outage.
@7 y)
For indicated engine loads in the range of 3200 )(Q to 3500)$ for a period less than I hour a crankshaft inspection pursuant to item #T elow)shallbeperformedfortheaffectedengineatthenext refueling outage.
For indicated engine loads in the range of 3200)d to 3500)d for 1
got periods equal to or exceeding one-hour
, and for engine loads
/
V exceeding 3500)3I for any period of timeY(2) the engine shall be b
removed from service as soon as safely possible, (2) the engine 4
shall be declared inoperable, and (7) the crankshaft shall be i
inspected. The crankshaft inspection shall include crankpin journal numbers
, 6, and 7 (the most heavily loaded)j and the two main journals in between using fluorescent liquid penetrant and eddy N
Tl current as appropriate.
q w
6if there are multiple overload events within a given load range) criterion appliesg
WMs In Section 2.0 of the ea-Nad TER, PNL has recommended that fast starts be limited to the number consistent with NRC requirements in order to further minimize wear and tear of the EDGs.
Consistent with the staff's position on the frequency of fast starts as identified in NRC Generic Letter 84-15, the plant Technical Specifications, Section 4.8.1.1.2.a.
will limit fast starts from ambient conditions during surveillance tests to at least once per 184 days. All other engine starts and loading associated with surveillance testing in-Section 4.8.1.1.1.2.a may b.e preceded by an-engi.ne prelube period and/or other wamup procedures reconinended by the manufacturer.
hN W Operating Procedures giM In a,NRC staff letter dated July 23, 1985, GBU was
-';=ad to develop procedures which provide proper' guidance and instruction to operators against overloading the TDI diesel generators above the qualified load level. The staff stated that these procedures should address, but not necessarily be limited to, the following:
(U) kd No single operator error should cause the loading of more than one TDI engine in excess of its qualified load rating.
(O h
Procedures and training in place at River Bend should preclude operator action that would cause the TDI EDG load to exceed the qualified load.
i
[df)
The training program should adequately address the technical concerns 1
associated with the qualified load limit on the TDI EDGs.
. f:.I)
If a situation were to occur that would, for some unspecified failure, cause the EDG to exceed the qualified load, the procedures and training shcald provide the necessary guidance to reduce the load below the 1
qualified load within see hour.
(h Distinctive and unique instrumentation and alarms should be ---
installed to warn operatcrs when the engines are loaded above I
the qualified load.
ph J#has agreeo by letter dated July 29, 1985 to review j
W its procedures and to make any necessary cha s prigr : -plant
/W criticality p0rsuant to the above criteria. 3S& urther noted that I
) ith a distinctive sound have already M*# instrumentation and w
n f.e/?
installed to warn operatcrs if the engine loads xceed 3130 kw. e:::d -
g g
k these actions, the staff concludes that the BSS' operating procedures for the TDI engines will provide the appropriate guidance and instruction to operators.
(3)
-+:6 Conclusions This and the aa W ::d NL evaluation precede final completion of the NRC/PNL review of the proposed generic resolution of the Owners Group Phase I issues and of the total DR/QR program at River Bend. The NRC staff and PNL conclude that these reviews have progressed sufficiently
/
So peh that all significant issues warranting priority attention as a 10 basis for issuance of an operating license for River Bend have been adequately resolved.
Accordingly, the NRC staff concludes that the TDI diesel generators Mu.4 did at 3STwill provide a reliable standby source of onsite power in GD C.
accordance with Gene-M Dedy C-hinn-17. This finding is subject 7
8 3 1(2 O h..- 4
/
to (1) license conditions identified in Section 3,4-of this HE*
pertaining to the engine maintenance / surveillance ((M/S)Oorogram, (2) spec
- g. 3.
- 39 reporting requirements identified in Section M,
1 n
restriction requirements as identified in Section ad, and (4) a license g
condition making operation beyond the first refueling outage subject to NRC staff apprTWal tased on the staff's final review of the Owners Group generic findings and of the overall Q
gg t t River Bend. This finding is also based in part upon JStf connitments in its letter dated July 29, 1985 to complete the following actions:
j ho (1)
Incorporate additional item identified in ection ft into the M/S program for EDGs IA and IB by August 30,1985g (2)
Perform QA check to ensure completeness and accuracy of implementation and procedural documents relating to the pS prqgram for EDGs IA and W. ! y b, -
Csee Section Gr4 of this ISER).
IB by August 30, 1985 (3)
Review and revise as nec,essary E(G 1A and IB operating procedures as s
describedinCection3.7ofthisp@..r.
te plant criticality.
y.3.s U r i
t 8.3.2 OC Power Systems In FSAR Amendment 19, the applicant deleted a listing of much of the Division -
III instrumentation which is used to monitor the status of the Division III de system and which the staff had previously reviewed and found acceptable.
It appeared that this might have been an unintentional edit: rial error.
FSAR Amendment 21 reinstated the instrumentation which had been deleted. This, therefore, is acceptable.
In a letter dated July 15, 1985, the applicant provided a proposed FSAR amend-
~
ment which revised the Division III (HpCS) battery loading profile and changed' the resulting battery endurance from 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
The staff has reviewed these changes and finds them acceptable. The River Bend Technical Specifica-tions have incorporated the revised information in Section 3/4.8.2.1.
i 8.4 Other Electrical Features and Requirements for Safety 8.4.1 Adequacy of Station Electric Distribution System Voltages (1) In Section 8.4.1(1) of the SER, the staff stated it would confirm the adequacy of the final relay setpoints for the second level undervoltage i
protection.
In a letter dated July 24, 1985, the applicant provided the I
setpoint calculations for the first and second levels of undervoltage protection. The setpoints for the Division I and II vital buses are 2970 i
V (74.3% of equipment-rated voltage) for the first level and 3740 V (93.5%
of equipment-rated voltage) for the second level.
The setpoints for the a44 Division III vital bus 14 3045 V (76.1% of equipment rated voltage) for the first level and 3777 V (94.4% of equipment rated voltage) for the second level. The staff has reviewed these setpoints and their tolerances provided in the applicant's letter and finds them acceptable. Therefore, Confirmatory Item 46 is closed.
r FSAR Amendment 19 revised figures indicate the Division III under-voltage protection logic is not arranged in the 2-out-of-3 coincidence logic as described in the applicant's March 5, 1984 1etter and reported in 4
08/01/85 8-4 RIVER BEND SSER 3 SEC 8
I
.~
the SER.
FSAR Amendment 21 provided a revised response to the description of the Division III (HPCS) first and second levels of undervoltage protec-tion. The first and second level undervoltage protection scheme senses voltage at the incoming side of the normal supply breaker.
The first level of undervoltage protection is arranged in a 1-out-of-2 logic with a l
time delay of approximately 2 seconds.
The second level of undervoltage protection is arranged in a 2-out-of-2 coincidence logic and utilizes two separate time delays.
The first is approximately 10 seconds (to override motor starting transients).
Follow-ing this delay, an alarm in the main control room alerts the operator to -
the degraded condition. The subsequent occurrence of a LOCA signal immediately separates the Divi'sion III bus from the offsite power system.
l The second delay is approximately 60 seconds. After this delay, if the l
operator has failed to restore adequate voltages, the Class IE system is automatically separated from the offsite pwer system.
The 2-out-of-2 coincident logic used for the second level undervoltage protection allows one relay to be taken out of service for test and calibration while an effective 1-out-ci-1 protective logic is retained.
The staff finds that the design of the second level undervoltage protection as described above satisfies the provisions of Branch Technical Position (BTP) PSB-1 and is, i
therefore, acceptable. Therefore, Confirmatory Item 46 is closed.
1 (4) The staff indicated in Section 8.4.1(4) of the SER that it would confirm the adequacy of the applicant's verification tests.
These tests have not
~
yet been completed. The staff will review and provide its confirmation of the acceptability of these tests and their results in a future SER supple-ment when the results are available, but no later than before startup from the first refueling outage.
i 8.4.2 Containment Electrical Penetrations FSAR Amendments 19 and 20 provided some revisions to the description of the containment electrical penetration protection at River Bend.
For low-voltage control circuits, a category of circuits was added that had been analyzed and found not to require backup protection. These circuits are current transformer i
08/01/85 8-5 RIVER BEND SSER 3 SEC 8
i i
l leads used on differential protection circuits, and trip coil circuits in circuit breakers.
In a letter dated July 24, 1985, the applicant provided j
The current l
justification for the lack of protection on these circuits.
transformer leads on differential protection circuits are acceptable because a
{
high current exists on these circuits only momentarily when a fault is sensed and is quickly cleared by the differential protection circuit. An open circuit t
i on the current transformer secondary which could cause high voltages will also cause a trip of the protection circuit which will in turn eliminate the over-The lack of redundant protection on trip coil circuits is acceptable voltage.
t because these circuits are fed from an ungrounded 125-V de power supply, and the portion of the circuit passing through the penetration is confined to only -
.one leg (positive or negative) of the power supply.
The only type of failure the penetration circuit would be exposed to is an electrical ground which would not cause fault current to flow unless there N simultaneously existing fault on the opposite leg of the power supply. This is unlikely to occur because a ground-detection alarm is provided on the 125-V de system which alerts the operator to the existence of the first ground on the system so that he may track down and remove it to maintain the system ungrounded.
Another revision to the penetration protection is the addition of a category of l
low-voltage control circuits which are deenergized during plant operation.
7 With the exception of the emergency response facility (ERF) system (portable equipment installed during shutdown), the equipment in this category will all be listed in the River Bend Technical Specification to ensure they remain deenergized during plant operation.
If the circuits have provisions for These locking them in the deenergized state, they will also be locked open.
provisions are acceptable. The other remaining electrical penetration revi-sions made in FSAR Amendments 19 and 20 have been reviewed and are also acceptable. Therefore, Confirmatory Item 71 is closed.
08/01/85 8-6 RIVER BENO SSER 3 SEC 8
[
]
Physical Identification and Independence of Redundant Safety-Related i
8.4.5 Electrical Systems b
In Section 8.4.5 of the SER, the staff stated that 4.16-kV/13.8-kV cabling in[
conduit is not routed in close proximity to Class 1E ladder-type trays except This statement was based on a where the cables exit from the subject tray.
FSAR Amendment 20 has subsequently similar statement in FSAR Chapter 8.
l The staff has reviewed tha separation details for l
deleted this statement.
these circuits contained in River Bend drawings 12210-EE-34ZE-7 and j
12210-EE-34ZH-6 and finds that they comply with the requirements of IEEE Std. 384 and RG 1.75 and are, therefore, acceptable, I
In a previous supplement (SSER 2), the staff evaluated the use of red-j colored jacketed cables in unscheduled non-Class 1E circuits (these colored l
cables are normally only used to identify Class IE circuits), and found them FSARAmendmentC acceptable with the restrictions outlined in FSAR Amendment 16.
These are in
]
20 has added additional categories where these cables are used.
direct-burial cable installations and inside the makeup water intake structure, in various types of raceways, where there are only non-safety-related circuits The FSAR states that there are no safety-related Category I circuits at these j
locations, and no safety-related circuits are installed in direct-burial cable l
]
The staff finds that these exceptions to cable color coding will not trenches.
j decrease the effectiveness of the color-coding system used at River Bend and
]
are, therefore, acceptable, l
8.4.6 Non-fety Loads on Emergency Sources
~
In SSER 2 the staff stated a need to review the applicant's evaluation with f
j l
l regard to the acceptability of non-Class IE slide wire transducers and li In a letter dated July 5, 1985, the applicant provided its evalua-j t
switches.For the slide wire transducers, a qualif ted resistor limits the avail-tion.
able fault current to a small value which has no detrimental effe Class 1E power supply should a short or ground occur on the unqualified trans l
For the limit switches, a short or a ground on the limit switch is the ducer.
same as if the switch were closed, which also has no detrimental effect on 4
RIVER BENO SSER 3 SEC 8 8-7 08/01/85
Class 1E power supply. Both the slide wire transducer and limit switch circuits as designed are, therefore, acceptable.
O In FSAR Amendment 20, the applicant added non-Class 1E motor heaters to the I
list of non-Class 1E loads powered from Class IE power supplies.
The motor heaters are powered from a Class 1E 120-V panelboard.
There is a single Class IE circuit breaker in the 120-V feed to the motor heater.
In a letter dated July 5,1985, the applicant stated that for Westinghouse motors the heater is qualified Class IE and for Reliance motors the heaters are also considered to be Class IE. For Seimens-Allis motors, the applicant has committed to install a second overcurrent protection device in the 120-V feed to the motor heater, In the interim, the applicant has committed to keep these circuits deenergized.
j Section 3/4.8.4.4 of the River Bend Technical Specifications requires that upon j
installation of the second overcurrent protective device, the circuit breakers in the circuit be listed in the Technical Specifications and they be periodic-1 ally tested. With these provisions, the staff finds this item acceptable.
Therefore, Confirmatory Item 49 is closed.
i f
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[
l 1
1 l
1
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.i 4
08/01/85 8-8 RIVER BENO SSER 3 SEC 8
9 AUXILIARY SYSTEMS 9.2 Water Systems 9.2.5 Ultimate Heat Sink In FSAR Amendment 16, the applicant identified a reduction of the diesei gen-erator loading resulting from delayed starting of the ultimate heat sink (UHS) fans based on the ultimate water temperature rise in the UHS basin.
In crder to ensure that the basin water temperature would not rise above the design am-bient temperature, the applicant, in a submittal dated May 20, 1985, committed to have installed before startup following the first refueling outage a UHS basin temperature monitoring system.
This system is to determine the average basin water temperature with a continuous readout and alarm in the control room.
The applicant has stated that because of the time needed to design, procure, install, and test the temperature-monitoring system, installation of the moni-toring system cannot be completed before power operation.
By submittal dated July 18, 1985, the applicant committed to provide the design of the temperature monitoring system for staff review and approval before its installation.
As an interim measure, the applicant has committed to manually taking daily basin water temperature readings with an increasing frequency based upon the actual water temperature. At a water temperature between 75'F and 80*F, the reading will be taken every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />; when the water temperature exceeds 80*F, the reading will be taken every 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
The UHS and the standby service water system are declared inoperable when the basin water temperature reaches 82'F.
The basis for the deferral of the installation of the UHS basin water tempera-ture monitoring system is the staff's judgment that the interim procedures provide a level of safety comparable to the design of the new system for the short period of operation of one cycle.
On the basis of its review, the staff concludes that the UHS design is accept-able pending the following conditions:
~
(1) The applicant will submit the design of an acceptable temperature-monitoring system for staff review before the first refueling.
(2) The applicant will have installed the temperature-monitoring system and proposea modification to the Technical Specifications (both to delete the interim Technical Specifications and to incorporate the new design into the Technical Specifications) before startup af ter the first refueling outage.
In FSAR Amendment 20 and the July 18th submittal, the applicant provided the design of a new system to be installed within the UHS.
The new system is a hypochlorite feedj.Qg the recirculation system.
In the submittal dated Jury 18, idl 198Dhe~afisiWe~ ant stated that the hypochlorite feeding system is designed to control organic growth in the UHS. A concentration level of 3.0 to 5.0 ppm of free chlorine will be injected into the UHS basin and verified by sample ana-lysis when (1) makeup water is added to the UHS, (2) the standby service water River Bend SSER 3 9-1
=
system is operated or tested, or (3) microbological growth is detected.
This system consists of a hypochlorite feed tank, a positive displacement feed pump, a recirculation pump, and piping.
The piping in the UHS is plastic, except for the piping near the standby service water pumps.
The hypochlorite system is designed to inject 25 gpm of sodium hypochlorite into the UHS for about 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> per day for 3 days per week to maintain the minimum chlorine level in the UHS.
This system is not safety related and failure of this system will not adversely affect the UHS or the standby service water system. Thus the requirements of General Design Criterion (GDC) 2, " Design Basis for Protection Against Natural Phenomena," and guidelines of RG 1.29 (Rev. 3), Position C.2, are satisfied.
i In FSAR Amendment 16, the applicant modified the operation of the UHS fans from automatic initiation with the starting of the diesel generators to manual ini-tiation from the control room 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> into design-basis accidents in order to reduce the diesel generator loadings.
The applicant indicated in a submittal dated May 14, 1985, that manual initiation of the fans 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after the com-mencement of thi design-basis accident would not have any adverse consequences.
The applicant indicated that the water temperature would rise approximately 2.2F' per hour without the fans operating.
On the basis of the applicant's commitment to install a UHS basin water-temperature-monitoring system, the license condition, the installation of a seismic Category I, Class IE, basin water temperature monitoring system by the first refueling outage, and the interim measures, the staff concludes that manual initiation of the UHS fans before basin water temperature reaches 82*F 1
is acceptable.
Therefore the requirements of GOC 44, " Cooling Water," as related to the ability of the UHS to accept the heat rejected by the plant, are satisfied.
On the basis of the above evaluation, the staff concludes that the UHS meets GOC 2 and 44, as related to protection against natural phenomena and the capa-bility to reject the heat loads from safety-related components under emergency conditions including a single active failure, and is, therefore, acceptable.
The UHS meets the acceptance criteria of SRP Section 9.2.5.
9.2.7 Standby Service Water System
~
In its SER, the staff stated that each loop of the standby service water system (SSWS) is powered from its associated diesel.
The A and C SSWS pumps in the A loop are powered from the Division I diesel generator and the B and 0 SSWS pumps in the B loop are powered from the Division II diesel generator.
In FSAR Amendment 16, the applicant removed the C'SSWS pump and the associated instrumentation and controls from the Division I diesel generator and proposed powering it only from the Division III (HPCS) diesel generator. Thus the C SSWS pump only operates when the Division III diesel generator operates.
The applicant provided a failure modes and effects analysis which demonstrates the ability of the SSWS to withstand any single failure and provide sufficient cooling water to ensure a safe shutdown for all design-basis events.
The staff has reviewed the revised failure modes and effects analysis and concludes that there is no single failure which will result in insufficient SSWS cooling water.
In its SER, the staff also stated that each SSWS pump was capable of handling 50% of the cooling water for design-basis accidents and, therefore, only two River Bend SSER 3 9-2
g$'
gW s
Althoughthesepumlpsareratedas50%
pumps were needed for safe shutdown.
for design-basis accidents, whose the single failure ik the Division III (HPCS) diesel generator three pumps are needed for a safe shutdown.
This is accept-i s
able because with the single failure of the HPCS diesel generator and the resulting loss of the C SSWS pump, there will still be three SSWS pumps available.
1 i
Each SSWS loop returns the cooling water to the ultimate heat sink, which is a i
forced-draft cooling tower. The Division II powered pumps return the water to an area of the cooling tower which is served by the Division II fans.
The Division I and III powered pumps return the water ta an area of the cooling i
j tower which is served by the Division I powered fans.
A crosstie between the i
redundant loops enables the A and C SSWS pumps to supply water to the components i
and systems which would normally be serviced by the 8 and D SSWS pumps.
Because of the independence of the operability of the cooling tower fans and the SSWS pumps, the possibility exists that the SSWS pumps in one loop and the cooling i-tower fans associated with the other loop may be inoperable concurrently.
Thus,'
the appropriate number of SSWS pumps and fans may be operable, but the " system" may not be able to adequately remove sufficient heat to safely shut down the 4
4 plant.
The applicant has provided an acceptable Technical Specification which requires the two operable SSWS pumps to be aligned to the loop with the two operable cooling tower fans whenever either of the following conditions exists:
}
(1) Two SSWS pumps in the same loop are inoperable and at least one fan in the other loop is inoperable or (2) Two cooling tower fans in the same loop are inoperable and at least one SSWS pump in the other loop is inoperable.
On the basis of the acceptable Technical Specification concerning the alignment of the cperable SSWS pumps and the cooling tower fans, the staff concludes that i
the standby service water system meets GDC 44, as related to the capability of 1
transferring heat loads from safety-related components to the ulti~ mate heat sink under emergency conditions including a single active failure, and is, therefore, acceptable.
9.3 Process Auxiliaries f
l' 9.3.3 Equipment and Floor Drainage Systems i
In its SER, the staff stated that the floor drains were pumped from the ECCS l
compartments and safety-related areas to the radwaste system. By FSAR Amend-ment 20, the applicant has provided a new operating mode for two of the floor drainage systems in the auxiliary building which routes the water to either the suppression pool or to the radwaste system.
The areas affected by this change are the reactor plant, closed, cooling water system; the steam tunnel area which includes the leakoffs associated with the reactor core isolation cooling (RCIC) system; some of the components serviced by the normal / standby
'L service water system; the standby gas treatment system; the floor drains in the auxiliary building crescent area at elevation 7Q; some unit coolers; MSIV g* g positive leakage control system; HVAC systems for the reactor, auxiliary, l
turbine, and containment buildings; some compressor / dryer systems; some fire protection sprinkler drains; and miscellaneous area floor drains for such -
4 areas as elevators, instrument racks, hatches, and electrical terminal boxes.
The auxiliary building crescent area contains emergency core cooling system
}-
(ECCS) piping which could leak.
Leakage from this piping could reduce the inventory in the suppression pool.
j 1
River Send SSER 3 9-3 L
With this new operating mode, the two affected systems have been identified as the suppression pool pumpback system (SPPS).
Since this is only a new operat-ing mode of a previously approved system, the staff concludes that the SPPS meets the requirements of GDC 4, " Environmental and Missile Design Bases."
The SPPS consists of two sumps, each of which has two pumps.
The pumps, iso-lation valves, and level-detection instrumentation are seismic Category I and Class 1E powered.
The piping from the isolation valves to the suppression pool interface at the high pressure core spray return line is seismic Category I, Safety Class 2.
The rest of the piping is not seismic Category I, but is seis-mically supported.
Therefore, the staff concludes that the SPPS meets the requirements of GDC 2, " Design Basis for Protection Against Natural Phenomena,"
and the guidelines of RG 1.29, " Seismic Design Classification." The SPPS is operated either manually from the control room or automatically from the level sensors.
By installing this new operating mode, the applicant has not deleted the option of pumping the water to the radwaste system.
The use of this system to pump the water to the suppression pool provides additional time for -
the operator to identify the source of leakage while maintaining suppression pool water level and preventing excessive buildup of water in the auxiliary building.
Selection of the option to pump back to the suppression pool is by means of opening a motor-operated valve.
Opening this valve automatically closes the air-operated valves to the radwaste system.
The air-operated valves are fail-closed valves which prevent inadvertent pumping to the radwaste system during a loss-of coolant accident (LOCA).
On the basis of the above evaluation, the staff concludes that the SPPS meets the requirements of GDC 2 and 4, with regard to protection against natural phenomena, environmental conditions, and missiles, and the guidelines of RG 1.29., Positions C.1 and C.2, concerning the system seismic classification, and is, therefore, acceptable.
The SPPS meets the acceptance criteria of SRP Section 9.3.3.
9.3.5 Standby Liquid Control System In its SER, the staff concluded that the standby liquid control system was ac-ceptable based, in part, on the similarity between the FSAR Figure 9.3-14 and the GE standard figure which identifies the acceptable bounds of tank volume and sodium pentaborate concentration levels.
(This issue is also discussed in Section 4.6 of this supplement.) By FSAR Amendment 20, the applicant provided a revised Figure 9.3-14 which identifies a lower concentration, smaller tank volume, and no safety margin in the total tank storage capacity. On the basis of the staff's independent calculations, the lower concentration level of 9.3%
is non-conservative with respect to previously approved concentration and volume levels. The applicant provided a revised figure by submittal dated July 8, 1985, which shows the minimum concentration as 10.5%.
This concentra-tion level was compared with other previously approved analyses and found to provide similar boration rates.
Therefore, the revised figure provided by the July 8th submittal is acceptable.
The applicant has also committed to revise the figure in the Technical Specifications.
The staff concludes that the design of the standby liquid control system meets the requirements of GDC 26, " Reactivity Control System Redundancy and Capa-bility," and GDC 27, " Combined Reactivity Control System Capability," and is, River Bend SSER 3 9-4
l therefore, acceptable.
The functional design of the standby liquid control system meets the applicable criteria of SRP Section 9.3.5.
9.4 Air Conditioning, Heating, Cooling, and Ventilation Systems
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9.4.1 Control Building Ventilation System (Control Room Area Ventilation System)
In its SER, the staff stated that the' control building ventilation system in-i cludes the control building chilled water system.
The chilled water system consists of.two redundant, closed-loop chilled water trains with each train capable of meeting the total chilled water needs of the control building.
Each train contains two 50% capacity electric-motor-driven centrifugal liquid i
chillers with both trains (all four chillers) powered from the essential ser-vice buses so that emergency power is available from the diesel generators if offsite power is lost.' By FSAR Amendment 20, the applicant proposed to auto-
~
matically initiate one of the two water chillers on each train and to auto-
^
matically start the second chiller upon failure of the lead chiller in the respective ventilation train in order to reduce the electrical loading on the Division I and Division II diesel generators.
]
In a letter dated May 16, 1985, the applicant has provided the results of an i
analysis of the control building heat loads assuming the loss of a Division I or Division II diesel generator as the single active failure, for all design-basis events.
This analysis indicates that the heat load will be significantly reduced because of the reduction in equipment and instrumentation being powered 1
as a result of the loss of a Division I or Division II diesel generator.
(The loss of the Division III diesel generator will have no effect in that it powers no safety-related equipment in the control building.) With both Division I j
and II diesel generators operating, one 50%-capacity water chiller would be i
automatically initiated in each train, for a total of 100% capacity, and~
thereby meet all of the chilled water requirements for the control building.
With the single failure of one of the automatically initiated water chillers, the second chiller in the train with the failed chiller would automatically l
start.
If the single failure is a ventilation train, there is sufficient time for the operator to manually initiate the second chiller in the operating
}
ventilation train.
~
Having one automatically initiated water chiller in each of the two redundant chilled water trains and having the second chiller in each train automatically initiated upon failure of the lead chiller in the respective ventilation train is acceptable.
This does not change the staff's conclusions as previously stated in the SER.
1 9.4.6 Miscellaneous Building heating, Ventilation, and Air Conditioning (HVAC)
Systems In its SER, the staff stated that there were six miscellaneous building HVAC systems.
By FSAR Amendment 20, the applicant added eight more miscellaneous l
building HVAC systems, as follows:
(7) motor generator building (heating-and ventilation system)
(8) domineralized water pumphouse (heating and ventilation system) 1 River Bend SSER 3 9-5 e
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(9) circulating water pumphouse and switchgear room (heating and ventilation system)
(10) cooling tower switchg,aar house (heating and ventilation system)
(11) clarifier area switchgear house (heating and ventilation system)
(12) hypochlorite area switchgear house (heating and ventilation system)
(13) blowdown pit (heating and ventilation system)
(14) auxiliary control building (heating, ventilation, and air conditioning system)
These additional miscellaneous building HVAC systems are located in non-safety-related buildings and are designed to provide a suitable environment for per- -
sonnel and equipment operation.
None of these systems has any safety-related function, nor does failure of any system comprise any safety-related system or components.
Failure of any system will not prevent safe shutdown of the reac-tor. Therefore, no system is designed to seismic Category I standards or to Quality Group A, B, or C standards.
Thus, the guidelines of RG 1.29, " Seismic Design Classification," Position C.2, are satisfied and the requirements of GDC 2, " Design Basis for Protection Against Natural Phenomena," are satisfied.
These systems are not designed to control release of radioactive material; therefore, GDC 60, " Control Releases of Radioactive Materials to the Environ-ment," is not acceptable.
These additional miscellaneous building HVAC systems meet the recuirements of GDC 2 and the guidelines of RG 1.29, Position C.2, and are, therefore, accept-able. These additional systems meet the acceptance criteria of SRP Sec-tion 9.4.3.
River Bend SSER 3 9-6
(bDW$
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Chemical Engineering Bran 6h/ Fire Protection Section SupplementalSafepyEvaluationReport j
River Berd S ation Unit No. 1
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Do,cke No. 50-458 II. Fire Protection Program Requirements A.
Fire Protection Program In our SER we stated that the fire protection program is described in the applicant's Fire Protection Evaluation Report (FPER).
In fact, the fire protection program is described in Section 9.5-1 and Appendices 9A and SS of the applicant's Final Safety Analysis Report (FSAR), as opposed to a separate FPER. The SER should be su cor-rected. This correction does not affect our safety evaluation.
~
V.
General Plant Guidelines
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A.
Building Design in our SER we stated that 3-hour fire rated penetration seals are provided for penetrations of fire rated walls and floor / ceiling assemblies in accordance with BTP CMEB 9.5-1, Section C.5.c (3).
By letter dated June 28, 1985, the applicant requested deviation from this position to the extent that it requires sealing inside conduits larger than 4 inches in diameter at the fire barrier pene-tration and sealing inside conduits 4 inches or less in diameter at the barrier unless the conduit extends at least 5 feet on either side of the barrier and is sealed either at the barrier or at both ends. The applicant proposes to seal conduits at the fire barrier or at the first opening on both sides of the barrier regardless of
.w conduit size or distance from the barrier.
By letter dated July 26, 1985, the applicant submitted the results of fire tests on conduits sealed in accordance with the proposal that were exposed to the ASTM E-119 Standard Time Temperature Curve in accordance with the ANI/MAERP test method. The test report also documented the test assembly's perfonnance against the requirements of IEEE 634-78. NFPA 803, and ASTM E814-81.
The fire test demonstrated that conduits sealed in accordance with the applicant's proposal prevent smoke and hot gas propagation through the conduits throughout the 3-hour test period. Moreover, none of the unexposed side thermocouples exceeded the acceptance criteria temperature specified by either ANI/MAERP, IEEE 634-78, or ASTM E814-81.
4 Following the fire exposure, the test assembly was subjected to 3 hose stream tests. None of the seals were penetrated by water during these tests.
Based on our evaluation, we conclude that the applicant's proposal to seal conduits at the fire barrier or at the first opening on both sides of the barrier regardless of conduit size or distance from the barrier will provide an equivalent level of protection to'that
i achieved by compliance with Section C.S.a.(3) of BTP CMEB 9.5.-l.
The applicant's conduit sealing proposal is, therefore, an acceptable deviation from BTP CMEB 9.5-1, Section C.5.a.(3).
In our SER we stated that radiation shielding materials are non-combustible and met Section C.5.a.(9) of our guidelines. However, in FSAR Amendment 20 the applicant identified eight areas where a combustible material is used for radiation shielding.
In all cases, the combustible radiation shielding material is enclosed by steel plates with thicknesses between U2 and 3 inches and is, therefore, isolated from ignition sources. Moreover, the material does not expose any safety related or safe shutdown components. Therefore.
we have reasonable assurance that the combustible radiation shielding does not present a threat to rafe shutdown.
Based on the above evaluation, we conclude that the use of combustible radiation shielding in the eight areas listed in FSAR Amendment 20 is an acceptable deviation from BTP CMEB 9.5-1 Section C.5.a.(9).
By letters dated June 13, 1985 and July 26, 1985 the applicant requested deviations for not completing the fire wrap for cables in the control hilding before 5 percent power is exceeded, and in the fuel building until the full power operation milestone:
a.
In the control building, the fire wrap is for the standby w
In the event that pumps ISWP*2B, C and D are not available due to a fire, pump ISWP*2A is capable of providing all cooling water required for safe shutdown from 5 percent power. Fire zones C2A, B and C have fire detection and suppression. A fire watch will be established until the fire wrapping is completed in accordance with Tech-nical Specifications. We will condition the license to assure that the fire wrap will be installed prior to exceeding 5 percent of rated power. We find this deviation acceptable, b.
In the final building, the fire wrap is for the spent fuel cooling system. The completion of fire wrapping for the Division I and II cabling for the spent fuel pool cooling system is currently scheduled to be completed prior to full power operations. This is well in advance of any anticipated off-loading of spent fuel from the reactor.
Therefore the fire protection requirements for wrapping will be completed in advance of the need for the spent fuel pool cooling system. Should there be some unfore-seen reason to off-load irradiated fuel prior to achieving full power operation (and prior to completing the instal-lation of the wrap), then a fire watch will be implemented in accordance with the Technical Specifications until the wrapping is complete. No justification has been given for not completing this item before 5 percent rated power is exceeded. We will condition the license to assure that this fire wrap is installed prior to exceeding S percent of rated power. We find this deviatinn acceptable.
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Fire Protection of Safe Shutdown Capability B.
i In our SER we stated that the. applicant was assuming no repairs in order to go to cold shutdown within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
However,.in FSAR Amendment 20, the applicant identified two components that could J
require repairs.
For a fire in the main control room, air compressor l
ILSV*C3A may have to be started by use of jumpers at standby motor control center 1EHS*MCC2L if additional air is required for cycling the ADS /SRVs. Since these valves have a cualified air accumulator to provide for cyclic operation, it is anticipated that the air compresser j
will not need to be jump started until well inte the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, if at i
all. The second repair is required to maintain cold shutdown. This repair entails either manually. opening valve IE12*F009 or to jumper -
the valve open at the standby motor control center IEHS*MCC26, in order to permit operation of the RHR in the shutdown cooling mode.
l This operation does not need to be performed until near the end of the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. period. The applicant has comitted to maintain the l
materials for these repairs onsite and in a separate fire area and to L
have procedures in effect to implement these repairs.
Based on the applicant's comitments, the limited number of repairs, and
-the anticipated arrount of time available to make the repairs, we-conclude
)
that the repairs to achieve and maintain cold shutdown are acceptable, i
~
i During the site audit, we observed that area-wide automatic fire i
suppression was not provided in the following areas:
i ET Electrical Tunnel PT Pipe Tunnel i
AB Auxiliary Building Piping and Electrical Tunnel l
C-2A - Control Building Cable Chases i
C-2B - Control Building Cable Chases j
C-2C - Contro1' Building Cable Chases
^
t C Control Building Elev. 70 i
Each of these areas is equipped with an area-wide fire detection 1
j system; a cable-tray fire suppression system; portable fire extinguishers; manual hose stations; and a.1-hour fire rated barrier j
around one shutdown division.
If a fire were to occur.in any of the i
areas, it would be detected in its early stages by the fire detection i
system. The fire brigade would then extinguish the fire.
If room j
temperatures rose significantly, the cable-tray sprinkler system would i
-activate. Water from this system would protect vulnerable cables and would limit fire spread. During the time delay between the advent of j
a fire and its eventual control,. damage would be confined.to this area j
by the fire-rated perimeter construction. Also, because one shutdown-1 division is protected by a fire barrier, there is reasonable assurance that safe shutdown could still be achieved and maintained. Therefore, area-wide automatic fire suppression is not necessary. Based on our evaluation, we conclude that the absence of area wide fire suppression i-in the above areas is an acceptable deviation from Section C.S.b of BTP CMEB 9.5-1.
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C.
Alternate Shutdown Capability The lighting for the control room.and the remote shutdown panel area are Class IE, however, there are operator actions which are required in the event of a control room fire that are neither in the control room nor in the remote shutdown panel area.
The applicant has provideo eight hour battery powered lights for other areas.
In a submittal dated June 11, 1985, the applicant has cenr'ittec to perform all operator actions s.hich are not performed in the main control rocn er at the remote shutdown panel area within eicht hours. The only exception is the operation or repair of vaise ;Eit'F009 an RHR isolotion vcive. The creration of this valve is r.ct necessary until approaching ccid shutdcwn. The guidelines identified the neea to be able to be in cuic shutccwr in -
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, thus this valve neec not be operated for approximately 66 hcers after the fire.
This is sufficient time for the operators to use portable lights, as necessary, to locate and operate the valve.
Therefore, we conclude that operation of valve 1E1L*F009 after the eight hours of emergency lighting is acceptable.
In a submittal dated July 19, 1965, the applicant stated that all circuits necessary for alternate shutdown frem cutside of the control room are in cen.pliance with the guicelines of I & E Bulletin 85-09. Ccepliance with the guidelines of the bulletin is based on having fuses in the circuits which are separately fused and isolated from the control room circuits in order to safely shutdown the plant in the event of a main control room fire.
Based on meeting the guidelines of I & E Bulletin 85-09 and en the applicant's commitment to complete the necessary operator actions within eight hours, we conclude that the alternate shutdown capability is acceptable and complies with the guidelines of Section 9.5.1 of the Standaro Review Plan.
By letter dated May 28, 1985, the applicant requested deviations for not completing the alternate shutdown system for the control roon until the 5 percent power milestone.
In this letter, the applicant stated that the modifications necessary for alternate shutdown in the event of a control room fire would not be completed before receiving a license because of the time required to procure, install, and test the modifi-cations. These modifications include installing 22 transfer and control switches, revising plant procedures, and re-training operators.
By letter dated June 13, 1985, the applicant stated that the plant will be in compliance with the guidelines of the BTP CHFB 9.5.1 Section C.5.6 with respect to alternate shutdown prior to exceeding 5 percent power. Based on the alternate shutdown not being availcble in the event of a fire in the main control roon, we require that a condition be placed on the license, as follows:
1
. The applicant shall complete all mudifications to provide a means to safely shutdcwn the plant, in the event of a fire in the main control room, from outside of the control room, including revision' of the plant procedures and re-training of the operators, prior to exceeding 5 percent of rated power.
The applicant has cocnitted to station a continuous fire watch in the control room at core load until t,he alternate shutduwn systen is fully completed and operational.
Okration of the plant up to 5 percent nr rated po aiic saf ety of the public is not increased.
has comitted to station a contiruces fire watch in the cuntrol room,.
we iino that adequate interin fire protection measures have beer provideo.
~
lherefore, the applicant's request for deviation from our guidelines The alternate shutdown system for the control room should be granted.
should be completed prior to exceeding the 5 percent power milestone.
VI. Fire Detection and Suppression Fire Detection In our SER we stated that the fire detection system is designed in A
accordance with NFPA 72D, " Standard for the Installatien, Mainten-Informa-ance, and Use of Proprietary Protective Signaling Syst 28, 1985, the applicant verified that' the By letter dated June system had been tested and found acceptable for listing by 3
We find this acceptable.
Uncerwriters Laboratories. Inc.
B.
Fire Protection Water Supply System In our SER we stated that the fire pump installation was designed and installed in accordance with NFPA 20. " Standard for the Inst During our site audit, we observed that Centrifugal Fire Pumps."
butterfly valves were installed in the suction lines to the fire pumps.
The use of butterfly valves in fire pump suction lines is not ir.
accordance with NFPA 20. The applicant verbally comitted to replace By letter dated June 28, the butterfly vulves wtth approved OS&Y valves.
1985, the applicant informed us that all of the butterfly in accordance with NFPA 20. We now consider this item closed.
In our SER we also stated that in addition to a fire service jockey pump, the fire protection watcr supply systam has a hydro-pneu tank to maintain system pressure.We find that the fire service jockey pump along such a tank.
adequate to maintain pressure in the fire protection water supply system and meet the guidelines. fire service jockey pur..p without r h ccetrialie.
4
. In our SER we also stated that the water supply for fire protection.is taken frcm two 265,000-gallon water storage tanks and found the size of these tanks to be an acceptable deviation from the guidelines of Section C.6.b(11) of BTP CNEB 9.5-1 which requires a minimum capacity of 300,000 gallons per tank.
In fact, each tank has a working capacity of 241,000 gallons. This capacity is sufficient to supply the greatest spritikler or deluge system demand of 1400 9pm plus 500 gpm for hose streams for two hours with a uorgin of 13,000 gallcos, in tddition, the tanks are filieo autcmatically by the shalltv. v.cIl trakeup pump at a rate of 800 gpr s. hen the water level talls i tett Loku the overflow level. Based en the asc11cble water capacity una the outcretic rakeup, we find the existing tanks to be an acceptable de%1ction from the guide-lines of Section C.C.b(11) at blF CMEB 9.5.1.
C.
Sprinkler ana Stand Pipe Systems In our SER we stated that manual hose statiens are located throughout the plant in accorcance with NFPA 14, " Standard for the Installation of Standpipe and Pese Systems," and that, with the exception of the electrical tunnel, all areas of the plant car te reached with an effective hose streau with a reyinum of 75 feet of hose.
In the electrical tunnel, we concluccd that the applicant demonstrated that adequate flow and pressure is available from the water supply systen if 150 feet of hose is used. By letters dated hay li, 1985, and July 26, 1985, the applicant identified seven additicnal areas where 150 feet of hose is used.
The plant water distribution system is capable of supplying hose streams in these areas with adequate quantity of water and pressure through 150 feet of hose.
In addition, sufficient space is available in each of the areas for accessibility and to ensure that the fire hose can be used in close proximity to the hose station.
Based on the above evaluation, we conclude that the use of 150 feet of fire hose in the electrical tunnel and the seven areas identified in the applicant's May 17, 1985 letter is an acceptable deviation from Section C.6.c of BTP CMEB 9.5-1.
VII. Fire Protection for Specific Plant Areas D.
Switchgear Rooms During our site audit we observed that curbs were nut installed to prevent water from flowing between the Division 1 and Division 2 switchgear rooms. By letter dated June 16, 1985, the applicant informed us that curbs ho w been installed between Fire Areas C-14 and C-15 to prevent water flow between the Cen *ol Building switch-gear rooms. We find this acceptable.
l
! l XIII. Summary of Deviations from BTP CMEB 9.5-1 The following deviations from the guidelines of BTP CMEB 9.5-1 have been identified and are as follows:
- 1.. Sealing Inside Conduits (Section V.A) 2.
Steel Plate Enclosed Ccmbustible Radiation Shielding (Section V.A) 3.
fion-labelec Fire Doors (Section V.A) 4.
Lack of Area-wide Fire Suppression Systems ($ection V.B) 5.
Use of Water Curtains to Separate Fire Arees (Section Y.2) 6.
Fire kater Supply Tank Size (Section VI,8) 7.
Fire Hose Stations With 150 Feet of Hose (Section VI.C) 8.
Carpet in the Control Room (Section Vll.L' Based on our evaluation, we find that the applicant's fire protection program with approved oeviations is in conformance with the guidelines of BTP CMEB 9.5-1, Sections III.G, III.J and 111.0 of Appendix R to 10 CFR 50, and GLC 3 and is, therefore, acceptable.
l l
e
River Bend Station Unit 1 Fire Protection License Condition 1.
The licensee shall implement and maintain in effort all provisions of the approved fire protection program as described in the Final Safety Analysis Report for the facility (or~as described in submittals dated i
) and as approved in the SER dated ---------(and Supplements dated ----------) subject to provisions 2, 3, 4, 5, and 6 below.
2.
The licensee may make no change to the approved fire protection program which would significantly decrease the level of fire protection in the plant without prior approval of the Commission. To make such a change the licensee must submit an application for license amendment pursuant to 10 CFR 50.90.
3.
The licensee may make changes to features of the approved fire protection program which do not significantly decrease the level of fire protection without prior Comission approval provided (a) such changes do not otherwise involve a change in a license condition or technical specification or result in an unreviewed safety question (see 10 CFR 50.59), and (b) such changes do not result in failure to complete the fire protection program approved by the Commission prior to license issuance. The licensee shall maintain, in an auditable form, a current record of all such changes, including an analysis of the effects of the change on the fire protection program, and shall make such records available to NRC inspectors upon request. All changes to the approved program shall be reported annually to the Director of the Office of Nuclear Reactor Regulation, along with the FSAR revisions required by 10 CFR 50.71(e).
4.
Prior to exceeding five percent of rated power. Gulf States Utilities Company shall complete the fire wrapping of electrical raceways in i
the Control Building.
l 5.
Prior to exceeding five percent of rated power, Gulf States Utilities Company shall complete the fire wrapping of electrical raceways in the Fuel Building.
6.
Prior to exceeding five percent of rated power, Gulf States Utilities Company shall complete all modifications required to provide a means to safely shutdown the plant, in the event of a fire in the main control room, from outside of the control room, including revision of the plant procedures and re-training of the operators.
i 13 CONDUCT OF OPERATIONS 1
13.5 Station Administrative Procedures 1
l 13.5.2 Operating, Maintenance, and Other Procedures 13.5.2.2 Operating and Maintenance Procedures Program In Section 13.5,2.2 of SER, the scaff described the review and approval of the applicant's operating and maintenance procedures program through FSAR Anend-ment 11.
The applicant transmitted FSAR Amendments 16 and 20, which included j
the applicant's changes to FSAR Section 13.5, " Procedures." The staff reviewed.
these changes and determined that the applicant's operating and maintenance i
procedures program continues to meet the relevant requirements of 10 CFR 50.34, and remains consistent with Regulatory Guide (RG) 1.33, ANSI N18,7-1976/ANS 3.2, and SRP Section 13.5.2, " Operating and Maintenance Procedures."
i 13.5.2.3 Reanalysis of Transients and Accidents; Development of Emergency
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l Section 13.5.2.3 of the SER described the staff's_ review of the Procedures Gen-eration Package (PGP) and identified one item (indicated as Confirmatory Item 60 in Table 1.4 the SER) that had to be completed before the applicant's program for developing procedures could be approved.
This item was the identification and justification of safety-significant differences between the River Bend plant-specific technical guidelines and the NRC-approved BWR Owners Group tech-nical guidelines. These differences and justifications were provided in a let-ter from the applicant, dated January 15, 1985.
Supplemental information was provided to the staff on February 11, 1985.
a j
The staff's review consisted of evaluating the-justification for each deviation j
from the generic technical guidelines using plant-specific procedures, supple-mented with several telephone discussions with the applicant.
The procedures submitted by the applicant have several plant-specific setpoints, operator action levels, and procedure references which are to be determined.
During the routine prelicensing inspection program and before fuel load, the staff will confirm that the information required ta complete each procedure is incorporated into the procedure.
Justifications for several deviations included commitments by the applicant to change plant procedures based on, in most cases, improvements identified during the plant's procedure verification and validation effort.
These procedure changes were identified in deviations discussed on pages 7, 10, 16. 17, 19, 20, 27, 35, 39,.and 52 of Attachment 1 to the applicant's January 15', 1985 letter.
In letters dated April 17, May 15, and July 15, 1985, the applicant satisfac-torily identified and justified these changes to its plant procedures.
The j
applicant is expected to incorporate the technical ' content of these letters in f
i River Bend SSER 3 13-1
_.-._._-.__.._,__..._m.
its emergency operating procedures (EOPs) and background documents in accord-ance with its E0P program.
In addition, the applicant committed in its April 17, 1985, letter to change or clarify the deviations on pages 18, 34, and 50.
The staff has confirmed the acceptability of these revised deviations.
The staff identified three errors associated with the deviations reviewed.
First, although the justification on page 1 of Attachment 1 stated that generic emergency procedures guidelines (EPG) Cautions 1-8 were addressed in training and not contained in the procedures, two cautions which the operators would be expected to have difficulty remembering (6 and 8) are, in fact, included in the procedures.
The applicant acknowledged this error and the staff found the ex-clusion of cautions 1-5 and 7 acceptable.
Second, there is an inconsistency in the value used for the " maximum subcritical banked withdrawal position." The applicant stated that it had identified this inconsistency and had corrected it.
The staff found this acceptable.
Third, an apparent typographical error was identified in the justification for E0P-0002, step 3.4.4 (page 33 of Attach- _
ment 1) referencing 2 psig instead of 12 psig.
An applicant representative stated that this error will be corrected.
The staff found this acceptable.
Finally, the River Bend E0Ps provide direction to the plant operators to vent the primary containment when containmen.t pressure exceeds the " primary contain-ment pressure limit" as defined by a curve of primary containment water level vs. suppression chamber pressure.
The River Bend proposed limit is based on an ultimate capacity of 55 psia which is in excess of the design pressure by a factor of about 4.
The NRC staff's Safety Evaluation Report on Revision 2 of the generic Emergency Procedure Guidelines (issued February 1983) has approved the use of twice design pressure as an interim limit, provided containment in-tegrity can be demonstrated. The staff is aware of a proposed revision to the generic EPGs which will result in a redefinition of the venting criteria.
In this regard, it is the staff's intent to continue the review of the proposed venting criterion (both generically and for each plant) which emphasis on the following areas:
(1) purge valve operability at the proposed venting pressure (2) consideration of depressurization rate during venting to limit suppression pool flashing (3) safety / relief valve actuation at high containment pressures (4) structural analyses and tests (5) limitation of nffsite radioactive releases by selective use of vent paths The staff must complete its review of this item before the plant can operate above 5% of rated power.
The staff concludes that Confirmatory Item 60 has been adequately addressed and, therefore, the applicant's program for developing E0Ps is acceptable for fuel load and operation up to 5% of rated power.
During the staff's review of the applicant's E0P program, it was determined that the applicant is considering changing its method of presenting E0Ps cur-rently described in the PGP from narrative to flowchart.
It is the staff's i
River Bend SSER 3 13-2 i
1 position that a change in E0P presentation method from narrative to flowchart is quite a significant change and currently there are no acceptance criteria in SRP Section 13.5.2, "Aperating and Maintenance Procedures" which address the development'of flowcaart procedures.
Furthermore, the applicant has not submitted a plan for developing flowchart E0Ps.
The staff should review the applicant's method for developing, verifying / validating and implementing flow-chart E0Ps before their implementation.
4 River end SSER 3 13-3 3
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14 INITIAL TEST PROGRAM The Initial Plant Test Program of the River Bend Station Unit 1 was reviewed and approved through FSAR Amendment 10 and documented in the SER.
- Recently, the staff has completed its review of FSAR amendments through Amendment 18.
Changes and modifications had been made to a previously approved test program which required additional information from the applicant before the staff could complete its review.
The applicant responded with the necessary information in a letter dated May 15, 1985.
The staff has reviewed the revised Initial Plant Test Program and finds it acceptable.
In the May 15, 1985, letter, the applicant took exception to the provision for 2-hour testing at 110% of rated load in Position C.2.a(3) of RG 1.108, " Periodic '
Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuc-lear Power Plants." The acceptability for this exception and the applicant's proposed test program for the Transamerica Delaval diesel generators at River Bend is addressed separately in Section 8 of this supplement.
River Bend SSER 3 14-1
15 TRANSIENT AND ACCIDENT ANALYSIS
~
15.4 Reactivity and Power Distribution Anomalies 15.4.2 Rod Withdrawal Error at Power In the SER, the staff stated that the statistical analysis of the rod withdrawal event at power may not be applied to cases with a control cell core loading or those loaded to accommodate a high energy /high-discharge exposure cycle unless a compliance check is performed to demonstrate its applicability.
Since the River Bend first-cycle loading is a control cell core, the applicant has provided assurance that such a compliance check has been done (see letter from applicant dated June 19, 1985).
Therefore, the staff concludes that the withdrawal limits resulting from the generic analysis are acceptable for River Bend.
15.4.7 Operation of a Fuel Assembly in an Improper Position--Fuel Misloading Event In the SER, the staff reviewed the applicant's analysis of a three-bundle configuration. The applicant has modified the initial core with a control cell 1
core containing five different enrichments.
For the revised core, the limiting fuel bundle loading error is that of inter-changing a 2.78% enrichment bundle with a 0.94% enrichment bundle in the center of the core and away from a low power-range-monitor (LPRM) string.
When the i
mirror-image location (assumed to be instrumented) is placed on thermal limits, the misloaded bundle will exceed operating limits.
l J
l River Bend SSER 3 15-1
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i RIVER BEND SSER 3 SEC 18.
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18 HUMAN FACTORS ENGINEERING In the discussion that follows, the staff closed out the open licensing issues of the detailed control room design review (DCROR) required by Supplement I to The Lawrence Livermore National Laboratory (LLNL) Technical Evalu-
29, 1985 (see Appendix J of Supplement 2 to ation Report (TER) dated January SER)3 and the LLNL Supplemental Technical Evaluation Report (STER) dated June 28, 1985 (see Appendix N of this supplement), provide the evaluation of the River Bend Station Unit 1 DCRDR up to and including the applicant's Supplemen-14, 1985.
The staff reviewed the SSR tal Summary Report (SSR) No. 1 dated Maywhich resolved the concerns expressed in Append No. 2 dated June 12, 1985, of the enclosed LLNL STER, and discussed the resolutions with the LLNL staff.
The NRC staff concurs in the technical evaluations and conclusions contained in the STER, which is appended to this supplement.
The DCRDR open issues which are identified in the conclusions section of SSER 2 are closed out based on the following acceptable responses provided by the applicant:
confirmed the continued participation of human factors specialists in the (1) remaining DCROR activities 3
submitted additional task analysis documentation results discussed in (2)
SSER 2 under " Function and Task Analyses" confirmed that the remaining control room survey items have been completed 4
(3) and the submittal of acceptable resolutions and implementation schedules for human engineering discrepancies (HEDs) have been identified provided acceptable responses to the specific concerns regarding resolu-(4) tion of the HEDs identified in Appendices A and B to the Technical Eval-uation Report (January 29,1985) appended to SSER 2 as Appendix J confirmed that all control room modifications resulting from the OCROR (5) have been verified to assure they have provided the expected corrections and do not introduce new HEDs Although the applicant committed to implementing corrective actions for a number of HEDs before licensing, the staff does not plan to confirm that all of How-these actions have been completed before issuing the low power license.
ever, the staff will confirm that all actions proposed to correct HEDs before licensing and before exceeding 5% of rated power have been completed before a full-power license is issued. All but 11 of approximately 325 HEDs will be The 11 HEOs will be corrected corrected before exceeding 5% of rated power.The staff has determined that the confirma-during the first refueling outage.
tion of actions required to correct certain HEDs before licensing could be deferred until before issuance of a full-power license without affecting safe The identification of all HEDs requiring corrective operation of the plant. action and the applicant's accepted proposed schedules for im 18-1 River Bend SSER 3
actions are contained in the River Send DCRDR Summary Report dated October 31, 1984, in supplements dated May 14 and June 12, 1985, and in the applicant's letter of July 30, 1985.
On the basis of the staff's review of the River Bend Procram Plan, DCROR
~
Summary Report, and supplements, and an onsite, in progress audit, the staff has concluded that except for completing the implementation of corrective acticns for certain HEDs, the applicant has satisfactorily completed its DCROR for River Bend Station Unit 1 in accordance with the requirements of Supple-ment 1 to NUREG-0737.
The staff will verify implementation of actions to correct certain HEDs before exceeding 5% of rated power and before startup after the first refueling outage, in accordance with commitments made in the Summary Report, in supplements dated October 31, 1984; May 14, 1985; and June 12, 1985; and in the applicant's letter of July 30, 1985.
1 River Bend SSER 3 18-2
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APPENDIX L PRESERVICE INSPECTION RELIEF REQUEST EVALUATION l
I.
INTRODUCTION I
This section was prepared with the technical assistance of Department of Energy l
(00E) contractors from the Idaho National Engineering Laboratory.
For nuclear power facilities whose construction permit was issued on or after July 1, 1974, 10 CFR 50.55a(g)(3) specifies that components shall meet the
~
preservice inspection (PSI) requirements set forth in editions and addenda of Section XI of the ASME Boiler and Pressure Vessel Code applied to the con-struction of the particular component.
The provisions of 10 CFR 50.55a(g)(3) also state that components (including supports) may meet the requirements set forth in subsequent editions and addenda of this Code which are incorporated by reference in 10 CFR 50.55a(b) subject to the limitations and modifications listed therein.
In the P.iver Bend Station PSI Program, Revision 3, submitted on May 15, 1985 and in letters dated June 10 and June 24, 1985, the applicant requested relief from ASME Section XI Code requirements which the applicant has determined to be not practical and provided a technical justification..Therefore, the staff evaluation consisted of comparing the applicant's submittals to the requirements of the applicable Code edition and addenda and determining if relief from the Code requirements was justified.
II. TECHNICAL REVIEW CONSIDERATIONS A.
The construction permit for River Bend Station was issued on March 25, 1977 and components (including supports), which are classified as ASME Code Class 1 and 2, have been designed and provided with access to enable the performance of required preservice examinations set forth in the 1977 Edition of the ASME Boiler and Pressure Vessel Code,Section XI, including the Addenda through Summer 1978.
B.
Verification of as-built structural integrity of the primary pressure boundary is not dependent on the Section XI preservice examination.
The applicable construction codes to which the primary pressure boundary was fabricated contain examination and testing requirements which by themselves provide the necessary assurance that the pressure boundary components are capable of performing safely under all operating conditions reviewed in the FSAR and described in the plant design specification.
As a part of these examinations, all of the primary pressure boundary full penetration welds were volumetrically examined (radiographed) and th,e system was subjected to hydrostatic pressure tests.
C.
The intent of a preservice examination is to establish a reference or baseline prior to the initial operation of the facility.
The results of
~
River Bend SSER 3 1
Appendix L i
subsequent inservice examination can then be compared with the original condition to determine whether changes have occurred.
If the inservice inspection results show no change from the original condition, no action is required.
In the case where baseline data are not available, all flaws must be treated as new flaws and evaluated accordingly.
Section XI of the ASME Ccde contains acceptance standards which may be used as the basis for evaluating the acceptability of such flaws.
D.
Other benefits of the preservice examination include providing redundant or alternative volumetric examination of the primary pressure boundary using a test method different from that employed duaing the component fab-rication.
Successful performance of preservice exanination also demon-strates that the welds so examined are capable of subsequent inservice examination using a similar test method.
In the case of River Bend Station, a large portion of the preservice exam.
ination required by the ASME Code was performed.
Failure to perform a 100%
preservice examination of the welds identified below will not significantly affect the assurance of the initial structural integrity.
E.
In some instances where the required preservice examinations were not per-formed to the full extent specified by the applicable ASME Code, the staff may require that these examinations or supplemental examinations be con-ducted as a part of the inservice inspection program.
Requiring supple-mental examinations to be performed at this time would result in hardships or unusual difficulties without a compensating increase in the level of quality or safety.
The performance of supplemental examinations, such as surface examinations in areas where volumetric examination is difficult, will be more meaningful after a period of operation.
Acceptable preopera-tional integrity has already been established by similar ASME Code Sec-tion III fabrication examinations.
- i In c % where parts of the required examination areas cannot be effec-tively examined because of a combination of component design or current examination technique limitations, the development of new or improved ex-amination techniques will continue to be evaluated.
As improvements in these areas are achieved, the staff will require that these new techniques be made a part of the inservice examination requirements for the components or welds whlch received a limited preservice examination. Several of the preservice inspection relief requests involve limitations to the examina-tion of the required volume of a specific weld.
The inservice inspection (ISI) program is based on the examination of a representative sample of welds to detect generic degradation.
In the event that the welds identi-fied in the PSI relief requests are required to be examined again, the possibility of augmented inservice inspection will be evaluated during review of the Applicant's initial 10 year ISI program.
An augmented pro-gram may include increasing the extent and/or frequency of examination of accessible welds.
III.
EVALUATION OF RELIEF REQUESTS The applicant requested relief from specific preservice inspection requirements in Revision 3 of the River Bend Station PSI Program submitted May 15, 1985, and submitted revisions to these relief requests in letters dated June 10 and June 24, River Bend SSER 3 2
Appendix L
1985.
Based on the information submitted by the applicant and the staff's re-view of the design, geometry, and materials of construction of the components, certain preservice requirements of the ASME Boiler and Pressure Vessel Code,Section XI have been determined to be impractical to perform.
The applicant has demonstrated that either (i) the proposed alternatives would provide an acceptable level of quality and safety or (ii) compliance with the specified requirements of this section would result in hardships or unusual difficulties without a compensating increase in the level of quality and safety.
Therefore, pursuant to 10 CFR 50.55a(a)(3), conclusions that these preservice requirements are impractical are justified as follows.
Unless otherwise stated, references 1
to the Code refer to the ASME Code,Section XI, 1977 Edition, including addenda through Summer 1978.
A.
Relief Request R0001, Examination Category 8-J, Pressure-Retainina Pipina Welds (21 Welds)
~
Code Requirement: ASME Code Class 1, pressure-retaining piping welds are re-quired to receive a 100% surface and volumetric examination for PSI in accor-dance with IWB-2500-1, Examination Category B-J, Item B9.10.
Code Relief Request:
Relief is requested from performing the Code-required volumetric examination on the pressure-retaining welds listed below:
System & Weld Number Type of Weld i
ICS-006-057-1 0578FWOO4 Pipe to flange MSS-024-600-1 600A25WOSE Sweep-o-let to flange 600A25WO50 Sweep-o-let to flange MSS-024-700-1 700A25WO8M Sweep-o-let to flange 700A25WO8L Sweep-o-let to flange 700AISWO8K Sweep-o-let to flange 700A25WOBJ Sweep-o-let to flange 700A25WO8H Sweep-o-let to flange MSS-024-800-1 800A25WO7K Sweep-o-let to flange 800A25WO7J Sweep-o-let to flange 800A25WO7M Sweep-o-let to flange 800A25WO7L Sweep-o-let to flange 800A25WO7N Sweep-o-let to flange 800A2SWO7P Sweep-o-let to flange MSS-024-900-1 900A25WO6F Sweep-o-let to flange 900A25WO6G Sweep-o-let to flange 900A2SWO6H Sweep-o-let to flange 1813*D020 1-ICS-014A-SW001 Tee to flange 1-ICS-014A-SWOO2 Tee to flange 1-ICS-014A-SWOO3 Tee to flange 1-ICS-014A-SWOO4 Tee to flange River Bend SSER 3 3
Appendix L
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Reason for Request
Because of the configuration (pipe to flange, sweep-o-let to flange, or tee to flange), there is not sufficient area to perform a mean-ingful ultrasonic examination.
Sketches showing the typical configuration of each weld were provided in the PSI Program.
1 Staff Evaluation:
The staff has reviewed the geometric configuration of the subject welds and determined that the required preservice volumetric inspection, using ultrasonic techniques, is not practical because of the design of the com-i i
This relief request is acceptable for PSI based on the following con-ponent.
siderations:
(1) Other welds in the same piping runs received full Code examinations.
The overall integrity of the pressure boundary thus was verified by sampling.
(2) These welds have been subject to a system hydrostatic test and found accept-able in accordance with ASME Code Section III, Class 1, requirements.
(3) These welds have been volumetrically examined by radiography, and found acceptable in accordance with ASME Code Section III, Class 1, requirements.
(4) These welds have also been surface examined by magnetic particle, and found acceptable in accordance with ASME Code Section XI, Class 1, requirements.
The above examinations and tests are an acceptable alternative for PSI and pro-vide reasonable assurance of the preservice structural integrity of the subject welds.
The staff has determined that compliance with the specified requirements would result in hardship or unusual difficulties without a compensating increase in the level of quality and safety because the components would have to be re-moved and redesigned to provide an inspectable weld surface for ultrasonic inspection.
8.
Relief Request R0002, Examination Category 8-J, Pressure-Retaining Piping Welos (6 welds)
Code Requirement: ASME Code Class 1, pressure retaining piping welds are re-quired to receive a 100% surface and volumetric examination for PSI in accor-dance with IWB-2500-1, Examination Category 8-J, Item 89.10.
Code Relief Request:
Relief is requested from performing 100% of the Code-required volumetric examination on the pressure-retaining welds listed below:
Standby Liquid Control Welds Approximate % Examined 1-SLS-0428-FW016 70 1-SLS-0428-FWOO9 60 l
._1-SLS-037C-FWOO4 65 Reactor Core Isolation Coolina System Welds Approximate % Examined
[.1-ICS-0018-SWO10[
75 Main Steam Pipino sweep-0-Let Welds Approximate % Examined 1
l il-MSS-600A2-SWO50 75 I -MSS-900A2-SWO6E i
l 75 River Send SSER 3 4
Appendix L l
j
Reason for Request
Because of the location and configuration of adjacent component supports or welded pads located on weld metal repair, the required volumetric examination cannot be performed on 100% of the required weld volume.
Sketches showing typical restrictions from adjacent structures were provided in the PSI Program.
The staff has reviewed the design configuration of the adjacent structures and determined that the preservice inspection, to the extent required by the Code, is impractical.
Staff Evaluation:
This relief request is acceptable for PSI based on the fol-lowing considerations:
(1) Other similar welds in the same piping runs received full Code examinations.
Thus, the overall integrity of the pressure boundary was verified by sampling.
(2) These welds were volumetrically examined by radiography and found acceptable in accordance with ASME Code Section III, Class 1, requirements.
(3) These welds were subject to a system hydrostatic test and found acceptable in accordance with ASME Code Section III requirements.
(4) The above welds have received the Code required surface examination and the accessible portions of the above welds have received a preservice vol-umetric examination in accordance with ASME Code Section XI.
Therefore, the staff concludes that the limited Section XI volumetric examina-tion, the required Section XI surface examination, and the Section III fabrica-tion examinations performed during construction are an acceptable alternative for PSI and provide reasonable assurance of the preservice structural integrity of the subject welds.
C.
Relief Request R003, Examination Category C-G, Pressure-Retaining Welds in Pumps Code Requirement:
ASME Code Class 2, pressure-retaining welds in pumps are re-quired to receive a surface examination for PSI in accordance with ASME Code Section XI, IWC-2500-1, Examination Category C-G, Item C6.10.
Code Relief Request:
Relief is requested from performing a preservice surface examination on those portions of welds located within the concrete pump support encasement on the following pumps.
Pump Pump No.
Low Pressure Core Spray IE21 PC001 High Pressure Core Spray IE22 PC001 RHS "B" IE12 PC002-A
Reason for Request
These welds are located in the pump housing and are encased in concrete.
Examination of required welds would require complete disassembly of the pumps.
Examination of the accessible pump casing welds were performed.
If a pump is disassembled for normal maintenance, examination of the welds will be considered at that time.
Sketches showing the installed configuration of the pumps were provided in the PSI Program.
River Bend SSER 3 5
Appendix L
i i
i f
Staff Evaluation:
The staff has determined that disassembly of the pumps would be necessary to perform the required examination in the installed configuration.
This relief request is acceptable based on the following considerations:
(1) These welds have been volumetrically examined by radiography, and found ac-t ceptable in accordance with the ASME Code Section III, Class 2, requirements.
(2) These pumps were subject to a system hydrostatic test and found acceptable in accordance with ASME Code Section III, Class 2, requirements.
(3) The failure of these welds, thus leading to failure of the pump, would
[
i have no adverse affect on plant safety because redundant emergency core 1
cooling systems are provided.
[
The staff concludes that requiring a surface examination of the welds encased i
in concrete would result in hardships or unusual difficulties without a signif-icant increase in the level of quality and safety because the radiography per- -
l formed during fabrication and the hydrostatic test are equivalent or superior to the required preservice inspection.
In the event that these pumps are dis-l assembled for inservice repair or maintenance, so that the subject welds are accessible, the staff will require that the preservice inspection be performed at that time.
l D.
Relief Request R004, Examination Category 8-0, Peripheral Control Rod t
i Drive Housing Welds, and Examination Cateaory 8-G-2, Boltina Located on CR0 Housinos and Incore Housinas Code Requirement:
(1) Peripheral control rod drive housing welds are required to be surface examined (liquid penetrant) for PSI in accordance with ASME Code Section XI' IYB-2500-1, Examination Category 8-0.
i i
(2) Pressure-retaining bolting for the flange-to-flange joints, located on the
)
control rod drive (CRO) and incore housings, are required to receive a visual. examination (VT-1) for PSI in accordance with ASME Code Section XI, IW8-2500-1, Examination Category 8-G-2.
Code Relief Request:
Relief is requested from performing the liquid penetrant examinations on the peripheral CR0 housing welds and the visual (VT-1) examina-
[
tions on the subject bolting.
Reason for Request: The weld area and bolting is not accessible for examina-1 tion unless the CR0 support structure is removed.
A total 360* surface examina-tion cannot be accomplished because of interference from adjacent CRD housings.
Examination of the weld from the inside of the CR0 housing would require that the CR0 mechanisms be removed, which could result in damage'to the drive.
Staff Evaluation: This relief request is acceptable for preservice inspection j
for the following considerations:
(1) The peripheral CRD. housing welds have been volumetrically and surface ex-amined by radiographic and liquid penetrant methods and have been hydro-static tested in accordance with the requirements of ASME Code Section III.
l River Bend $$ER 3 6
Appendix L 4
l
i (2) All incore and CR0 housing bolting has been examined in accordance with the requirements of ASME Code Section III.
(3) The welds and bolting were subject to hydrostatic testing and found accept-able in accordance with the requirements of ASME Code Section III.
~
The staff concludes that' requiring the removal of the installed CR0 support structure to perform the required surface and visual examinations would result in hardships and unusual difficulties without a compensating increase in the 1evel of quality and safety because the radiography performed during fabrica-l tion and the hydrostatic test are equivalent or superior to the required per-service inspection.
In the event that the CR0 housings are disassembled for inservice repair or maintenance, so that the subject welds and bolting'are ac-cessible, the staff will require that the perservice inspection be performed at that time.
E.
Relief Request R005, Examination Category B-K-1, Integral Welded
~
Attachments for Class 1 Piping, Pumps, and Valves, and Examination Category C-C, Integral Welded Attachments for Class 2 Piping, Pumps, and valves (Relief Request R005 has been withdrawn by the applicant.)
F.
Relief Request R006, Examination Category B-J, Pressure-Retaining Dissimilar Metal Piping Welds Code Requirement: ASME Code Class 1, pressure retaining dissimilar metal welds i
are required to receive a 100% surface and volumetric examination for PSI in accordance with ASME Code Section XI, IWB-2500-1, Examination Category B-J, i
Note (1)(c), Item B9.11.
i Code Relief Request:
Relief is requested from performing 100% of the Code-i required volumetric examination on the following welds:
Line Number Weld Number 1-RCS-020-900-A 900A-FWB25 1-RCS-020-800-A 800A-FWA24
~
1-RHS-018-900-A 900A-FW822
Reason for Request
Because of the configuration of these welds (fitting to pipe), a meaningful ultrasonic examination can only be performed from one side of the weld.
Sketches showing the typical configuration of each weld were provided in the PSI Program.
Staff Evaluation:
The staff has reviewed the design configuration of the sub-ject welds and determined that the preservice inspection to the extent required by the Code is impractical.
This relief request is acceptable for preservice inspection based on the following considerations:
(1) These welds have been volumetrically examined by radiography and found acceptable in accordance with ASME Code Section III, Class 1, requirements.
River Bend SSER 3 7
Appendix L
=--
(2) These welds were subject to a system hydrostatic pressure test and found acceptable in accordance with ASME Code Section III, Class 1, requirements.
(3) These welds have been surface examined by liquid penetrant and found accept-able in accordance with ASME Code Section XI, Class 1, requirements.
The staff has therefore concluded the limited Section XI volumetric examination, the required Section XI surface examination, and the fabrication examinations performed during construction are acceptable alternatives for PSI and provide reasonable assurance of the preservice structural integrity of the subject welds.
G.
Relief Request R007, Examination Category 8-J, Pressure-Retaining Piping Longitudinal Welds Code Requirement:
ASME Code Class 1, longitudinal welds on 4-inch and greater.
NPS piping are required to receive a 100% surface and volumetric examination 6
for PSI in accordance with ASME Code Section XI, IWB-2500-1, Examination Cate-gory 8-J, Item 89.12 and Paragraph IWB-2200(a).
Code Relief Request:
Relief is requested from performing 100% of the Code-required examination on the following welds:
System & Line Weld Number 1-MSS-024-600-1 600A25W05BL1 600A25WO58L2 1-MSS-024-900-1 900A25WO6BL1 900A25WO68L2 1-MSS-024-700-1 700A25WO88L1 700A2SWO88L2 1-MSS-024-800-1 800A25WO78L1 800A25WO78L2 1-RCS-010-80G-1 800C-FWA16L 1-RCS-010-800-1 800C-FWA13L i
1-RCS-010-80E-1 800C-FWA14L 1-RCS-010-900-1 900C-FWB13L 1-RCS-020-900-1 900A-SWOO4BCL 1-RCS-020-900-1 900A-SWOO4 BBL 2 1-RCS-020-80A-1 8008-FWA06L j
1-RCS-020-800-1 800A-SWOO2ABL 1-RCS-020-900-1 900A-SWOO288L 1-RCS-010-80F-1 800C-FWA15L 1-RCS-010-90E-1 900C-FWB14L i
1-RCS-010-90C-1 900C-FWB12L 1-RCS-010-90F-1 900C-FWB15L c
1-RCS-010-90G-1 900C-FWB16L i
1-RCS-010-80C-1 800C-FWA12L l
1-RCS-020-80A-1 8008-SWOO7ABL 1-RCS-020-800-1 800A-FWA04L l
River Bend SSER 3 8
Appendix L
===.
Reason for Request===
The required area of examination cannot be examined because of the location of integral attachments, branch connections, and Code identifi-catior. plates.
The location of the specific obstruction for each weld was iden-tified.
The accessible portion of these longitudinal welds will be examined in accordance with Section XI requirements.
Staff Evaluation:
This relief request is acceptable for preservice inspection based on the following considerations:
(1) The accessible portions of the above-listed welds received a preservice volumetric and surface examination in accordance with the ASME Code Section XI.
(2) Adjacent weld lengths in the same piping runs received full Code examina-tion.
The overall integrity of the pressure boundary thus was verified by sampling.
(3) These welds have been volumetrically examined by radiography and found acceptable in accordance with ASME Code Section III requirements.
(4) The subject piping welds received a system hydrostatic test and were found acceptable in accordance with ASME Code Section III requirements.
The staff has determined that the Code preservice examination was essentially completed on the majority of welds.
The staff concludes that the limited Sec-
~
tion XI volumetric examinations, the required surface examinations, and the fabrication examinations performed during construction are acceptable alterna-tives for PSI and provide reasonable assurance of the preservice structural integrity of the subject welds.
H.
Relief Request R0008, Examination Category 8-J, Pressure-Retaining Welds in Piping Code Requirement: ASME Code Class 1, pressure retaining piping welds are re-quired to receive a 100% surface and volumetric examination for PSI in accor-dance with IWB-2500-1, Examination Category B-J, Item B9.10.
Code Relief Request:
Relief is requested from performing 100% of the Code-required volumetric examination on the fitting side of the following pipe to fitting or component welds:
System & Line Weld Weld Configurations i
1-RCS-010-80C-1 800C-FWA12 Pipe to sweep-o-let 80D-1 800C-FWA13 Pipe to sweep-o-let 80F-1 800C-FWA15 Pipe to sweep-o-let 80G-1 800C-FWA16 Pipe to sweep-o-let 1-RCS-020-80A-1 800C-FWA11 Pipe to tee 80A-1 8008-FWA10 Pipe to valve 90A-1 900CX-SWO14CA Reducer to tee 90A-1 900C-FWB11 Pipe to tee River Bend SSER 3 9
Appendix L
System & Line Weld Weld Configurations 1-RCS-010-90F-1 900C-FWB15 Pipe to sweep-o-let 90G-1 900C-FWB16 Pipe to sweep-o-let 900-1 900C-FWB13 Pipe to sweep-o-let 90C-1 900C-FWB12 Pipe to sweep-o-let 1-RCS-020-900-1 900A-SWOO4BA Pipe to tee 900-1 900A-SWOO4BC Pipe to tee 900-1 900A-FWB03 Pipe to pump 800-1 800A-FWA05 Pipe to pump 800-1 800A-FWA03 Pipe to valve 900-1 900A-SW005BA Pipe to elbow 900-1 909A-FWB04 Pipe to valve 800-1 800A-SW005AA Pipe to elbow 800-1 800A-FWA04 Pipe to valve 1-RCS-010-90G-1 900C-FWB21 Pipe to nozzle 90F-1 900C-FWB20 Pipe to nozzle 90E-1 900C-FWB19 Pipe-to nozzle 900-1 900C-FWB18 Pipe to nozzle 90C-1 900C-FWB17 Pipe to nozzle 80C-1 800C-FWA17 Pipe to nozzle 800-1 800C-FWA18 Pipe to nozzle 80E-1 800C-FWA19 Pipe to nozzle 80F-1 800C-FWA20 Pipe to nozzle 80G-1 800C-FWA21 Pipe to nozzle Reason for Request: Because of the configuration of these welds, the ultrasonic examination can only be performed from one side of the weld using a 1-1/2 V technique.
Sketches showing the typical configuration of each weld were pro-vided in the PSI Program.
Staff Evaluation: The staff has reviewed the geometric configuration of the subject welds and determined that the required preservice volumetric inspection, using ultrasonic techniques, is not practical from the fitting side because of the design of the component.
This relief request is acceptable for preservice inspection based on the following considerations:
(1) These welds have been volumetrically examined by radiography, and found acceptable in accordance with ASME Code Section III, Class 1, requirements.
(2) These welds have also received a liquid penetrant surface examination and were found acceptable in accordance with ASME Code Section XI, Class 1 requirements.
(3) These welds were subject to a system hydrostatic test and found acceptable in accordance with ASME Code Section III requirements.
(4) The staff will continue to evaluate the development of new or improved i
procedures and will require that these improved procedures be made part of the inservice examination requirements.
River Bend SSER 3 10 Appendix L
The staff has determined that the limited Section XI examinations from the pipe side of the weld, the required surface examinations, and the fabrication exami-nations performed during construction are acceptable atternatives for PSI as they provide reasonable assurance of the preservice structural integrity of the subject welds.
I.
Relief Request R0009, Examination Categories B-L-2 and B-M-2, Pump Casings and Valve Bodies Code Requirement:
Class 1 pump casing internals and valve body internal surfaces are required to receive a visual examination (VT-1) for PSI in accordance with ASME Code Section XI, IWB-2500-1, B-L-2 Item 812.20 and B-M-2 Item B12.40.
Code Relief Request:
Relief is requested from performing the required examina-tion for PSI.
Reason for Request
Visual examination of the internals of the pumps and valves' at this time would require disassembly, which would impose an undue hardship on the plant and may increase the probability of pump failure.
Staff Evaluation:
This relief request is acceptable for PSI based on the following:
The subject pump casings and valve bodies were volumetrically examined by radiography and hydrostatically tested in accordance with ASME Code Section III requirements.
Disassembly of pumps and valves at this time, for the sole pur-pose of performing preservice visual examination, would result in hardships or unusual difficulties without a compensating increase in the level of quality and safety. The staff has concluded that these construction code examinations and tests exceed the requirements for visual examination and therefore, are an acceptable alternative to the Section XI preservice visual examination.
J.
Relief Request R0010, Examination Category B-J, Pressure-Retaining Piping Weld (1 weld)
(Relief Request R0010 has been withdrawn by the applicant.)
K.
Relief Request R0011, Examination Category C-B, Pressure-Retaining Nozzle Welds in Vessels Code Requirement:
Table IWC-2500-1, Examination Category C-8, Item C2.20, requires surface and volumetric examination of the regions described in Fig-ure IWC-2500-4 for nozzles in vessels over 1/2-inch nominal thickness.
Fig-ure IWC-2500-4 requires volumetric examination of the inner radii on nozzles over 12-inch nominal pipe size.
Code Relief Request:
Relief is requested from performing the Code-required vol-umetric examination on the nozzle inner radii for the following residual heat removal (RHR) heat exchanger nozzles:
Component Description Nozzle Number 1-RHS-1-E12*EB 001-A N3 1-RHS-1-E12*EB 001-A N4 River Bend SSER 3 11 Appendix L
===.
Reason for Request===
The nozzles contain inherent geometric constraints which limit the ability to perform meaningful ultrasonic examination of the nozzles' inner radii.
To perform an alternate surface examination, the tube bundle 4
would have to be removed from the heat exchanger.
However, a surface examina-tion will be performed if the heat exchanger is disassembled.
Sketches of the nozzle configuration are provided in the PSI Program.
Staff Evaluation:
The staff review of the design configuration of the nozzle inner radius has concluded that the Code-required volumetric examination is impractical and would require redesign of the nozzle.
This relief request is acceptable for PSI based on the following considerations:
(1) The subject weld area received radiographic examination and a hydrostatic test during fabrication in accordance with ASME Code Section III require-ments.
(2) An ultrasonic examination has been performed on the nozzle-to vessel welds per ASME Code Section XI requirements.
(3) The staff will continue to evaluate the development of new or improved procedures and will require that the procedures be made part of the ISI examination requirements.
(4) If the heat exchanger is disassembled, the applicant has committed to perform an alternative surface examination.
The staff concludes that compliance with the Code requirements would result in hardships or unusual difficulties without a compensating increase in the level of quality and safety and the Section III hydrostatic test provides a reasonable assurance cf an acceptable level of structural integrity of the nozzle inner radii region.
IV.
CONCLUSIONS Based on the foregoing, pursuant to 10 CFR 50.55a(a)(3), the staff has deter-mined that certain Section XI required preservice examinations are impractical.
The applicant has demonstrated that either (i) the proposed alternatives would provide an acceptable level of quality and safety or (ii) compliance with the requirements would result in hardships or unusual difficulties without a compen-sating increase in the level of quality and safety.
The staff technical evaluation has not identified any practical method by which the existing River Bend Station can meet all the specific preservice inspection requirements of Section XI of the ASME Code.
Requiring compliance with all the exact Section XI-required examinations would delay the startup of the plant in order to redesign a significant number of plant systems, obtain sufficient re-placement components, install the new components, and repeat the preservice examination of these components.
Examples of components that would require redesign to meet the specific preservice examination provisions are the core spray pumps and a significant number of the piping and component support systems.
Even after the redesign efforts, complete compliance with the preservice exami-nation requirements probably could not be achieved.
However, the as-built struc-tural integrity of the existing primary pressure boundary has already been estab-lished by the construction code fabrication examinations.
l l
River Bend SSER 3 12 Appendix L i
f Based on the staff's review and evaluation, it is concluded that the public i
interest is not served by imposing certain provisions of Section XI of the i
ASME Code that have been determined to be impractical.
Pursuant to 10 CFR 50.55a(a)(3), relief is allowed from these requirements which are imprac-l tical to implement.
l i
I l
l l
River Send SSER 3 13 Appendix L
4 TABLE OF CONTENTS P, age ABSTRACT................................................................
iii 1
INTRODUCTION AND GENERAL DISCUSSION................................
1-1 4
1.1 Introduction.................................................
1-1 1.5 Outstanding Issues...........................................
1-1.6 Confirmatory Issues..............'...........................
1-l 1.7 Licence Conditions...........................................
1-i e
2 SITE CHARACTERISTICS...............................................
2-1 2.1 Geology and Demography.......................................
2-1 y, II
,l.L6,:
, ~,.
/i-,.
-h'n5 Stebi4f i.y o f 5 i vp us..................................
2-1 3
DESIGN CRITERIA FOR STRUCTURES, SYSTEMS, AND COMPONENTS............
3-1 3.6 Protection Against Dynamic Effects Associated With the Postulated Rupture of Piping.................................
3-1
~
u.y,de::r Pr
.Han abst.Pe>hJcdect Ryu 4 3,I sl f
3,(, a f, lad c
w,ea ri 3.6.2 Dete nationof,uptureL ation and Dynamic Effects 4
Associated With the Postulated Rupture of Piping.....
3-F 3.10 Seismic and Dynamic Qualification of Seismic Category I Mechanical and Electrical Equipment..........................
3-
.3 3.10.1 Seismic and Dynamic Qualification....................
3-3 3.10.2 Pump and Valve Operability...........................
3-b River Bend SSER 3
-tii-V
I CONTENTS (CORTIs0E'0)
Pj!gg 4
REACTOR............................................................- 4 4.6 Functional Design of Reactivity Control Systems..............
4-1 5
R EACTO R COO LANT SYSTEM.............................................
5-1 5.2 Integrity of Reactor Coolant Pressure Boundary...............
5-1 5.2.4 Reactor Coolant Pressure Boundary Inservice Inspection and Testing...............................
5-1 5.2.5 Reactor Coolant Pressure Boundary Leakage Detection............................................
5 EL i
6 ENGINEERED SAFETY FEATURES.........................................
6-1 1
6.2 Containment Systems..........................................
6-1 i
l 6.2.1 Containment Functional Design........................
6-i 6.6 Inservice Inspection of Class 2 and 3 Components.............
6-SL 6.6.3 Evaluation of Compliance With 10 CFR 50.55a(g).......
6- )L 7
INSTRUMENTATION AND CONTROLS.......................................
7-1 i
7.2 Reactor Protection System....................................
7-1 7.2.2 Specific Findings...................................
7-1
- 7. 3 Engineered Safety Features Systems...........................
7-f/
7.3.2 Specific Findings....................................
7-4 I
I l
River Send SSER 3 vi
CONTENTS (CpNTINUED)
.P,agg.
7.6 Interlock Systems Important to Safety........................
7-4 7.6.2 Specific Findings....................................
7-6 7.7 Control Systems..............................................
7
- /
7.7.2 Specific Findings....................................
7-7 l'h 8
ELECTRIC POWER SYSTEMS.............................................
8-1 Y
8.3 Onsite-b r;; = 3 Power Systems...............................
8-AC Power System [....................................
8-l 8.3.1 8.3.2 DC Power Systems....................................
8-8.4 Other Electrical Systems and Requirements for Safety.........
8-8.4.1 Adequacy of Station Electric Distribution System Voltage.......................................
8-8.4.2 Containment Electrical Penetrations..................
8-8.4.5 Physical Identification and Independence of Redundant Safety-Related Electrical Systems..........
8-j 8.4.6 Non-Safety Loads on Emergency Sources................
8-j 9
AUXILIARY SYSTEMS..................................................
9-1 I
9.2 Water Systems................................................
9-1 9.2.5 Ultimate Heat Sink...................................
9-1 9.2.7 Standby Service Water System.........................
9-2 9.3 Process Auxiliaries.........................................
9.3 River Bend SSER 3 VII
l CONTENTS (CpHTINUED) i Pa28 9.3.3 Equipment and Floor Drainage System..................
9-3 9.3.5 Standby Liquid Control System........................
9-9 9.4 Air Conditioning, Heating, Cooling, and Ventilation Systems......................................................
9-JI 9.4.1 Control Building Ventilation System (Control Room Area Ventilation System)........................
9-3' 9.4.6 Miscellaneous Building Heating, Ventilation, j
and Air Conditioning (HVAC) Systems..................
9-JI 13 CONOUCT OF OPERATIONS..............................................
13-1 13.5 Station Administrative Procedures............................
13-1 13.5.2 Operating, Maintenance, and Other Procedures.........
13-1 14 INITIAL TE3T PROGRAM...............................................
14-1 15 TRANSIENT ANC ACCIDENT ANALYSIS.................................... 15-1 l
15.4 Reactivity and Power Distribution Anomalies..................
15-1 15.4.2 Rted Withdrawal Error at Power........................
15-1 15.4.7 Cperation of a Fuel Assembly in an Improper Position--Fuel Misloading Event......................
15-1 18 HUMAN F/.CTORS ENGINEERING..........................................
18-1 River Bend SSER 3 viii
CONTENTS (C0iTINUED)
P e-APPENDICES APPENDIX A CONTINUATION OF CHRONOLOGY OF NRC STAFF RADIOLOGICAL REVIEW OF RIVER BEND STATION APPENDIX B BIBLIOGRAPHY APPENDIX D ACRONYMS AND INITIALISMS i
APPENDIX E PRINCIPAL STAFF CONTRIBUTORS i
APPENDIX L PRESERVICE INSPECTION RELIEF REQUEST EVALUATION APPENDIX M TECHNICAL EVALUATION REPORT: REVIEW AND EVALUATION OF TRANSAMERICA DELAVAL, INC., DIESEL ENGINE RELIABILITY AND OPERABILITY--RIVER BEND STATION UNIT 1 APPENDIX N SUPPLEMENTAL TECHNICAL EVALUATION REPORT OF THE
SUMMARY
REPORT SUPPLEMENT NO. 1 TO THE DETAILED CONTROL ROOM DESIGN REVIEW FOR GULF STATES UTILITIES COMPANY RIVER BEND STATION FIGURE Pc4
- 2. 4 Plant boundary and exclusion area for River Bend Station (revised from SE!!)
2-2 TABLES 1.3 Listing of outstanding issues 1-1.4 Listing of confirmatory issues.....................................
1-1.5 Listing of license conditions......................................
l-River Bend SSER 3 vtt U
e e.
CONTENTS (CONTINUED)
Page -
3.1 SQRT findings on seismic and dynamic qualification (revised from SSER 2)..............................................
3-10 3.1A Generic issues.....................................................
3-16 3.2 PVORT findings on operability qualification of pumps and valves (revised from SSER 2)..............................................
3-17 i
7.1 Safety related air conditioning units, unit coolers, and area
~
serviced...........................................................
7-4 f,t.Iteir.1 r Feco.,icid/ [., r its edusion i612e'ver &c..cf NHem s beibg clieset Tu y vri tts,n ple n,,
A*
1 t
i River Bend SSER 3
- H+ x
i i
l I
l 2 SITE CHARACTERISTICS 2.1 Geography and Demography 2.1.1 Site Location and Description The nearest rail route, the Illinois Central Gulf Railroad, is at a minimum distance of 2400 feet from the center of the River Bend Unit 1 reactor.
Explo-sive materials are not shipped along this route.
The applicant has purchased from the Illinois Central Gulf Railroad 1.2 miles of railroad south of the connection to the River Bend Station's plant access railroad.
From this junc-tion northward, past the applicant's property boundary, the Illinois Central Gulf Railroad is abandoning the track which traverses the site in a northwest-.
southeast direction.
l River Bend SSER 3 2-1
3 DESIGP CRITERIA FOR STRUCTURES, SYSTEMS, AND COMPONENTS 3.6 Protection Against Dynamic Effects Associated With the Postulated Rupture of Piping plc.it Dedso fk j
pRupture of Pip.ing (Outside Cen.twerd'-Sted Wtb tk Postulated Protection Against Cymic Effcc-t: he 3.6.1 In its SER, the staff stated that the applicant's analysis indicated that the main steam isolation valve (MSIV) closure would be expected to terminate the blowdown from a main steamline break within 5.5 seconds.
Furthermore, the applicant was to provide detailed information from this analysis for staff re-view.
The applicant has changed the time until MSIV closure to 10.5 seconds.
In a submittal dated May 14, 1985, the applicant justified the 10.5-second time as follows.
A high flow instrument sensing time of 0.1 second and an in-strument delay time of 0.3 second were assumed.
The PSIVs are designed to close between 3.0 and 5.0 seconds.
This leaves an overall conservatism of 5.1 seconds in the applicant's analysis.
This is acceptable.
The staff also stated in the SER that the applicant had not provided sufficient information for the staff to perform an independent calculation to verify the applicant's analysis of the environmental conditions in a compartment after a high-energy-line break (HELB).
By letter dated June
, 1985, the applicant has subsequently provided the additional information.
The Ataff reviewed the infor-mation and performed an independent analysis of the'sub(compartment environmen-
/
tal conditions following a HELB.
Staff analysis indicates that the applicant has appropriately determined the subcompartment conditions by predicting more conservative conditions than those predicted by the staff's independent analysis.
This is acceptable.
In its SER, the staff stated that the applicant had not completed its analysis of the rupture of high-energy piping systems and their analysis of compartment flooding resulting from moderate-energy-line cracks.
The applicant has now completed its analyses and has provided the results in FSAR Amendment 21.
The applicant further has provided the results of an analysis of the effects of the jet impingement from longitudinal cracks in the main steam or feedwater piping in the break exclusion area of the main steam tunnel. The potential jet impinge-ment targets in this area were identified and were assumed to fail to function because of the jet forces. The applicant's analysis indicates that the failed components would not prevent a safe shutdown. A structural evaluation was per-formed which verified that the structure will retain its integrity considering the effects of the jet impingement, pressure, and flooding.
In a submittal dated May 14, 1985, the applicant stated that the main feedwater piping in the steam tunnel had been analyzed and is supported in accordance with seismic Cate-gory I criteria. Therefore, the failure of the non-seismic Category I main feed-water piping in the steam tunnel will not adversely affect the safety-related main steamlines or other safety-related components. The staff reviewed these analyses and concludes that the applicant has appropriately used the guidance in Standard Review Plan (SRP) Section 3.6.1 and Branch Technical Position (BTP)
River Bend SSER 3 3-1
ASB 3-1 in evaluating the effects of high-and mocerate energy pipe failures and the guidance of Regulatory Guide (RG) 1.29 (Rav. 3), Position C.2, as related to protecting safety-related components from failure of non-safety-related components.
The applicant has adequately designed and protected areas and systems required for safe shutdown.
On the basis of the above evaluation, the staff concludes that the design of the facility meets the requirements of General Design Criterion (GDC) 4, with regard to protection against environmental conditions anc missiles and the guidelines of RG 1.29, Position C.2, concerning protection of safety-related components from the failure of non-safety-related components, and is, there-fore, acceptable.
The design of the facility meets the acceptance criteria of SRP Section 3.6.1, 3.6.2 Determination of Rupture Location and Dynamic Effects Associated With the Postulcted Rupture of Piping In Section 3.6.2 of the River Bend SER (NUREG-0989 dated May 1984), the staff identified a confirmatory issue regarding the dynamic analysis of the feedwater isolation check valves for the effects of a postulated pipe break in the feed-water piping outside containment.
In letters dated December 17, 1984 July 8, 1985, and July 25, 1985, the applicant provided its results for the analyses of the feedwater check valves.
The results of the applicant's evaluation were subsequently provided in Appendix 3C.2.2 of FSAR Amendment 17.
In the event of a pipe break in the feedwater piping outside containment, con-tainment. isolation is provided by two Atwood & Morrill check valves.
Breaks are not postulated in the region between the two check valves because that region is classified as a break exclusion area.
The applicant performed dy-namic analyses to demonstrate that the feedwater isolation check valves can perform their intended function following a postulated pipe break of the feed-water piping outside containment.
A flow transient analysis was performed using the comouter program WATHAM to determine the forcing functions associated with the raverse flow condition during a postulated pipe break.
The hydrodynamic torque exerted on the valve disk by the reverse flow was applied to determine the valve closing time and the impact speed of the disk onto its seat.
A stress analysis was performed to determine the ability of the feedwater isola-tion check valves to withstand the dynamic impact of the valve disk on the seat.
An inelastic analysis was performed in accordance with the ASME Code Section III Appendix F (1977) for Class 1 components using the ANSYS computer program.
The acceptance criterion was based on the ability of the valves to preclude gross leakage from disk rupture, fracture of the seat / disk interface, or misalignment of the disk. The analysis verified that the structural integrity of the feed-water check valves is maintained.
On the basis of the results of the applicant's analysis confirming the ability of the feedwater isolation check valves to perform their intended function fol-lowing a feedwater line break outside containment, the staff concludes that the applicant has provided a reasonable basis to conclude that the safety concerns raised in the SER confirmatory issue have been acceptably resolved.
Thus, the staff considers the confirmatory issue to be resolved.
River Bend SSER 3 3-2
3.10 Seismic and Dynamic Qualification of Seismic Category I Mechanical and Electrical Equipment 3.10.1 Seismic and Dynamic Qualification INPUT TO BE PROVIDED BY THE SEISMIC QUALIFICATION REVIEW TEAM (SQRT)
/
3.10.1.1 Introduction As part of the review of the applicant's Final Safety Analysis Report (FSAR)
Sections 3.7.3A, 3.7.38, 3.9.2A, 3.9.2B, 3.10A, and 3.108, an evaluation is made of the applicant's program for seismic and dynamic qualification of safety-related electrical and mechanical equipment.
The evaluation consists of:
(1) a determination of the acceptability of the procedures used, standards followed, and the completeness of the program in general and (2) an audit of selected equipment to develop a basis for the judgment of the completeness and adcquacy of the seismic and dynamic qualification program.
Guidance for the evaluation is provided by the Standard Review Plan (SRP) Sec-tion 3.10, and its ancillary documents, Regulatory Guides (RGs) 1.100, 1.61, 1.89, and 1.92; NUREG-0484; and Institute of Electrical and Electronics Engi-neers (IEEE) Standards 344-1975 and 323-1974.
These documents define accept-able trethodologies for the seismic qualification of equipment.
Conformance with these criteria is required to satisfy the applicable portions of the General Design Criteria (GDC) 1, 2, 4, 14, and 30 of Appendix A to 10 CFR 50, as well as Appendix B to 10 CFR 50 and Appendix A to 10 CFR 100.
Evaluation of the program is performed by a Seismic Qualification Review Team (SQRT) which consists of staff engineers and consultants from the Brookhaven National Labo-ratory (BNL, Long Island).
3.10.1.2 Discussion The SQRT reviewed the equipment seismic and dynamic qualification information contained in FSAR Sections 3.7.3A, 3.7.38, 3.9.2A, 3.9.28, 3.10A, and 3.10B and visited the plant site from October 29 through November 2, 1934.
The purpose of the review and visit was to determine the extent to which the qualification of equipment, as installed at River Bend meets the criteria described above.
A representative sample of safety-related electrical and mechanical equipment, as well as instrumentation, included in both nuclear steam supply system (NSSS) and balance of plant (BOP) areas, was selected for the audit.
Table 3.1 (re-vised from SSER 2) identifies the equipment audited.
The plant-site visit con-sisted of field observation of the actual, final equipment configuration and its installation. This was followed by a review of the corresponding qualifi-cation documents. The field installation of the equipment was inspected in order to verify and validate equipment modeling employed in the qualification program.
During the audit, the applicant presented details of the qualifica-tion and in-service inspection program.
3.10.1.3 Summary Audit Findings On the basis of the observation of the field installation, review of the quali-fication documents, responses provided by the applicant to SQRT's questions l
River Bend SSER 3 3-3 i
1 l
during the audit, and correspondence and meetings with the applicant following the audit, the applicant's seismic and dynamic qualification program has been found to be defined and largely implemented.
The equipment-specific findings and resolutions as a result of the SQRT audit are identified in Table 3.1.
The generic issues are identified in Section 3.10.1.4.
The resolution, status, and -
remarks for each generic issue is provided in Table 3.1A.
The license condi-tions are identified in Section 3.10.1.5.
On the basis of the review of the applicant's FSAR and the resolution of issues identified during the SQRT audit, the staff concludes that the seismic and dynamic qualification of safety-related equipment at the River Bend Station, Unit 1, does meet the applicable portions of GDC 1, 2, 4, 14, and 30:
Appendix B to 10 CFR 50; and Appendix A to 10 CFR 100.
3.10.1.4 Confirmatory Items As a result of the plant-site visit, the following generic issues were identi- ~
fied. The staff considers these issues to be of a confirmatory nature.
For each of the following issues, the corresponding status, resolution, and remarks are provided in Table 3.2.
(1) Each equipment qualification document package contained summary statewients and overall conclusions.
The conclusion for each package was that the equipment was fully qualified.
However, in many instances, it was otserved that evidence necessary to reach the state of complete qualification aas unavailable. More recent documentation packages were incomplete and appeared to be put together without adequate checking after the selection of equipment was transmitted to the applicant.
Therefore, the applicant was to develop a more systematic program to perform the acceptance review of all safety-related equipment.
(2) Where the qualification document package identifies a need for equipment modification, the applicant was to develop a systematic program to include in the qualification package either a statement indicating implementation of the modification or justification for not implementing the modification.
(3) In many cases, it was observed that the equipment qualification report identified parts with a limited life.
Such equipment could be located in either a mild or a harsh environment.
The applicant was to develop a sys-tematic procedure for identifying limited-life parts and to ensure their replacement at appropriate intervals during the acceptance review of equipment.
(4) Some equipment had been incorrectly or improperly installed.
The applicant was to develop a procedure to check proper mounting of all safety-related equipment consistent with the qualification mounting configuration.
(5) It was observed that the enclosure panel for many pieces of equipment was partially removed or screws had been l' eft loose reportedly in order to facilitate preoperational testing. The applicant was to develop a proce-dure to ensure that such equipment is returned to the qualified status.
(6) Upon completion of as-built piping analysis for all pipe-mounted safety-related equipment, the applicant must confirm that the g values used for River Bend SSER 3 3-4
qualification of this equipment were not lower than the g values obtained from the as-built piping analysis.
(7). The qualification of those pieces of equipment which were originally quali-fied to meet IEEE Std. 344-1971, should be identified and upgraded to meet -
the requirements of IEEE Std. 344-1975 as applicable.
(8) Upon completion of the ongoing qualification process, the applicant must confirm that all items of safety-related equipment have been qualified.
3.10.1.5 License Conditions The River Bend fuel-load, low power, and full powe" licenses are subject to the following conditions:
(1) The full power license is condittor.ed upon the applicant modifying all hydraulic control units during the third refueling outage.
The modifica- '
tion consists of installing the additional brace used during the qualifi-cation test of the equipment.
The applicant's letter dated May 15, 1985, indicated that the nitrogen cylinder hangar on the hydraulic control units (1C11*ACTD001) are qualified to a limited life based on safety / relief valve (SRV) fatigue test data.
(2) The low power license is conditioned upon the applicant performing an inde-pendent internal audit of seismic qualification documentation and reporting results to the staff before exceeding 5% of rated power.
Issues identified by the audit must be resolved to the staff's satisfaction before exceeding 5% of rated power.
vL (3) The low power license is condj oned upon the completion of the seismic qualification of panel board IENB*PNLO4A before exceeding 5% of rated power operation.
Low power operation before completion of qualification is justified on the basis of similarity of the unqualified panel board to other panel boards which have been qualified for River Bend requirements.
(4) The low power license is conditioned upon the completion of the seismic qualification of the HPCS diesel generator before exceeding 5% of rated power.
Low power operation before completion of seismic qualification of the high pressure core spray (HPCS) diesel generator is justified because the automatic depressurization system (ADS) is redundant to the HPCS sys-tem.
The ADS is fully qualified.
(5) The low power license is conditioned upon the completion of seismic quali-fication of Borg Warner globe valves purchased under GSU Specification No. 247.97 before exceeding 5% of rated power.
Low power operation before completion of seismic qualification is justified because of the similarity between the valve actuators of the unqualified valves and the actuators of valves which have been qualified for River Bend requirements.
The quali-fication of the valve body has been demonstrated by static analysis and static deflection tests.
f (6) The low power and full power licenses are conditioned upon the ompletion of the seismic qualification of the in-vessel rack (MPL No. F16-E006) before use during the first refueling outage. The in-vessel rack shall be stored in the plant warehouse before completion of seismic qualification.
River Bend SSER 3 3-5 i
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d 3.10.~2 Pump and Valve Operability
{
3.10.2.1 Introduction i
To ensure that an applicant has developed and implemented a program regarding -
I the operability qualification of safety-related pumps and valves, the staff performs a two-step audit.
The first step is to review FSAR Section 3.9.3.2 for the description of the applicant's pump and valve operability assurance program.
The information provided in the FSAR, however, is general in nature and not sufficient by itself to provide confidence in the adequacy of the applicant's overall program for pump and valve operability qualification.
To provide this confidence, the Pump and Valve Review Team (PVORT), consisting of staff from Brookhaven National Laboratory (BNL) and the NRC, conducted an on-site audit of a small representative sample of safety-related pumps and valves 4
and supporting documentation.
][
The criteria by which the audit is performed are described in Section 3.10 entitled " Seismic and Dynamic Qualification of Mechanical and Electrical Equipment" of the Standard Review Plan.
SRP Section 3.10 provides detailed i
t guidelines on how to satisfy the requirements of applicable portions of i
General Design Criteria (GDC) 1, 2, 4, 14, and 30 of Appendix A to 10 CFR 50 as well as Appendix B to 10 CFR 50.
l 3.10.2.2 Discussion In performing the first step of the audit, the staff reviewed FSAR Sec-tion 3.9.3.2.. The onsite audit, or second step, was performed by the PVORT during the week of October 29, 1984.
The purpose of this two-step review I
process is to determine the extent that Gulf States Utilities Company (GSU),
i the applicant) meets the criteria of SRP Section 3.10.
A sample of three nuclear steam supply system (NSSS) and seven balance-of plant (BOP) compo-r 4
nents was selected to be audited.
The onsite audit includes a plant inspection of the as-built configuration i
and installation of the equipment; a review of the normal, accident, and post-accident conditions under which the equipment and systems must operate; the' fluid dynamic-loads; and a review of the qualification documentation (status l
reports, test reports, analysis specifications, surveillance programs, and' long-term operability program (s), etc.).
A postaudit meeting with the staff and the applicant (GSU) and Stone & Webster (S&W) and General Electric (GE) was held at the NRC offices in Bethesda, Maryland, on May 10, 1985, for the purpose of discussing the confirmatory issues resulting from the NRC site audit and transmitted to GSU in the NRC's i
Table 3.2-(revised from SSER 2) identifies the equipment audited. the audit-
{
findings, and the resolution of equipment-specific items resulting from the-audit.
In addition to the equipment-specific items, the NRC audit also re-vealed-several items related to the broad program for pump and valve opera-7 i_
bility assurance. These items are perceived by the staff ~to be systematic in E
i-nature and they cut across specific equipment items. ?These items are discussed below in Section 3.10.2.3.
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River Bend SSER 3 3-6
3.10.2.3 Generic Items The generic items determined during the site audit are listed below.
Their resolution and status are discussed.
(1) In many instances, it was observed that evidence of complete qualification.
was unavailable.
More recent documentation packages were incomplete and appeared to be put together without checking.
The PVORT long forms con-tained numerous inconsistencies including inconsistent serial numbers, capability, and qualification information of the actual equipment.
The applicant is to develop a more systematic program to perform the accept-ance review of safety-related pumps and valves.
The applicant has demonstrated during the meetings at Bethesda on May 10 and June 10, 1985, that the qualification documentation and review program has been improved.
Additionally, details of the GE and S&W review and approval procedures were presented to the staff during the May 10, 1985, audit in Bethesda.
This issue is closed.
(2) During the acceptance review of equipment, a procedure should be developed
'o identify limited life parts and ensure their replacement at appropriate in'ervals.
In the applicant's letter of March 29, 1985, reference is made to a Novem-ber 8, 1985, letter directing S&W to perform a review of all qualification documents submitted by equipment vendors for both BOP and NSSS and to ex-tract the preventive maintenance requirements necessary to maintain quali-fication.
GSU also directed S&W to develop a procedure to address the ongoing review of qualification documents for maintenance and surveillance requirements.
This issue is closed.
(3) Procedures should be established to return tested equipment to its quali-fled status.
The applicant, in the March 29, 1985, letter and the May 10, 1985, meeting in Bethesda, provided additional information and documentation demonstrat-ing the adequacy of the existing procedures.
This issue is closed.
(4) Components were found to be incorrectly or improperly installed.
Proce-dures should be established verifying equipment installation requirements and qualification.
The applicant's response in the March 29, 1985, letter and the subsequent audit at Bethesda on May 10, 1985, have satisfied the staff that the dis-crepancies noted during the site audit are isolated cases and do not re-quire programmatic. changes to preclude recurrence.
This issue is closed.
(5) -All pumps and valves important to safety have had their required preopera-tional tests completed before fuel load.
The applicant's letter of July 25, 1985, indicates that all preoperational tests are complete.
This issue is closed.
River Bend SSER 3 3-7
(6) All pumps and valves important to safety are qualified before fuel load.
The applicant's letter of July 22, 1985, indicates that of all the safety-related pumps and valves, only the Borg Warner globe valve actuator will be seismically qualified after the fuel load.
All other pumps and valves -
are scheduled to be qualified before fuel loading.
The seismic qualifi-cation of the Borg Warner globe valve is addressed in Section 3.10.1 of this supplement.
In the letter of July 26, 1985, the applicant confirmed that all pumps and valves important to safety have been qualified.
This issue is closed.
(7) The applicant shall confirm that new loads resulting from loss-of-coolant accident (LOCA) or analysis of as-built conditions applicable to pumps and valves important to safety do not exceed those loads originally used to qualify the equipment.
In the July 26, 1985, letter, the applicant stated that as-built piping analysis to reconcile the differences between the actual loads and the loads originally used to qualify the pumps and valves is complete.
This issue is closed.
3.10.2.4 Evaluation Summary On the basis of the review of the pump and valve qualification program, obser-vation of the field installation, and the responses provided by the applicant to the PVORT's questions, it is evident that the applicant's pump and valve operability assurance program is properly defined and substantially implemented.
The equipment-specific findings resulting from the PVORT site audit have been resolved and are discussed in the Table 3.2.
In a letter dated July 22, 1985, the applicant has stated that there are only four items of equipment that will not be qualified before fuel loading.
With respect to pump and valve opera-bility qualification, only one of the four items to be qualified after fuel load falls within the pump and valve area of review. That is the Borg Warner globe valve for which the seismic qualification of the vahe actuator remains to be completed.
The Borg Warner globe valves are covered by a license condition (see Sec-tion 3.10.1 of this supplement). Thus, there are no outstanding open issues with respect to pump and valve operability qualification.
The operability qualification program for safety related pumps and valves at the River Bend Station, Unit 1, meets the applicable portions of GDC 1, 2, 4, 14, and 30 of Appendix A to 10 CFR 50, Appendix B to 10 CFR 50, and Appendix A to 10 CFR 100.
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3 10 2. 5
.t
-Term Operability Deep Draft Pumps. IE Bultetin 79-15
\\ g5 In response to IE Bulletin 79-15, the applicant identified the deep draft pumps
'6 e
in letters dated September 11, 1979 and October 22, 1979.
The resolution of 1
the concern identified in the subject bulletin is addressed by the applicant-in g
d*
FSAR Section 9.2.7.4.
The applicant has used the guidelines endorsed by the f,' p ' FSAR, staff and has completed the performance / endurance testing as indicated in the d
The tests included verification of performance at normal flow for 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />.
QA 5
River Bend SSER 3 3-8
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The staff concludes, on the basis of the discussion above, that the concerns identified in IE Bulletin 79-15 are satisfactorily resolved and this issue is closed.
1.
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River Bend SSER 3-3-9
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Table 3.1 SQRT findings on setselc and dynamic qualification (revised from SSER 2)
SQRT Applicant Equipment name ID No.
ID No.
and description Safety function Findings Resolution Status Remarks N555-1 1C11*ACTD001 Hydraulic control Translates scraa signal The additional brace Qualified to a limited Closed See CSU letter unit: Assembly con-into hydraulic energy used during qualift-Ilfe based on SRV R8G-20996 dated sists of Na cylinder, to insert the control cation test of the fatigue test data prior 5/15/85. This water accumulator rod drive and a110w its equipment was missing to failure of the hanger is a license and various valves.
return flow to discharge from the installed and subsequent addition condition on full-through the enhaust unit.
of the second brace.
power operation.
valve.
N555-2 H13-P680 Plant control console: Supports instruments The dynamic stellar-Additional documents /
Closed See G50 letter A U-shaped monitoring which are used to ity between the clarifications were R8G-20996 dated benchboard.
monitor and control the tested specimen and provided to show slal-5/15/85.
safe operation and the River Bend con-larity, test mounting, shutdown of the plant.
sole was not estab-and capability g values.
11shed.
The test sounting was not documented in the test report.
For components qualifl-cation, the capability g values were not de-fined and demonstrated to envelop the required response spectra over the entire frequency range.
N555-3 C61-P001 Remote shutdown Provides redundant The installation con-The vertical board and Closed See G5U 1etter sortical board means for safe shut-dition of being next the adjacent cabinet R8G-20996 dated down of the plant.
to another cabinet are being bolted 5/15/85.
and the well was not together.
addressed in the quellfIcation.
ge" M555-4 E1Z-C002A C RHR pump and motor Assembly is required to Qualification, verified Closed pump water in the sup-during audit.
pression pool during pool 8
cooling modes and LPCI vessel injection modes.
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Table 3.1 (Continued)
SQRT Appilcant Equipment name ID No.
ID No.
and description Safety function Findings Resolution Status Remarks M555-5 H13-P601 Reactor core cooling Contains instruments Dynamic stellarity Additional documents /
Closed See G5U letter bench board: Mont-that are used for manual between the tested clarification were R8G-20996 dated toring panel.
control for accident specimen and the provided to show stel-5/15/85.
altigation of the emer-River Bend unit was larity, test sountir.g.
gency core cooling not estabitshed.
capability g values, systes.
device qualification Test sounting was below 5 H2, Controller not completely docu-and recorder informa-mented in the test tion, and installation report.
correction.
For component qualifi-cation, the capability g values were not de-fined and demonstrated to envelop the required response spectra over the entire frequency range.
Qualification of some devices below 5 Hz was alssing.
Controller and recorder units were sliding during tests. It could not be verified free documentation presented whether River Bend panel contains these devices.
$lte inspection revealed the following:
One unistrut was loose.
GE ERIS terminals were very flexible.
s N555-6 H13-P670 Neutron / process Provides information The cabint was in-Additional documents Closed See G5U 1etter radiation monitoring about power levels and stalled with %"-
were provided to show 30G-20996 dated system.
power distribution in diameter bolts al-
- -diameter bolts ade-5/15/85.
the reactor, and is though the specimen quate for River Send.
tied to a trip system was tested with 5/8*-
(reactor protection diameter bolts.
systee).
I
______= _____ _ _ _ _. _ __
Table 3.1 (Continued)
SQRT Applicant Equipment name ID No.
10 No.
and description Safety function Findings Resolution Status Remarks 10555-7 H22-PO41, 42 Main steam flow Supports Class IE Transeitters were Additional documents Closed See GSU letter local panel devices.
not environmentally were provided to demon-R9G-20996 dated aged before selselc strate quellfication 5/15/85.
testing.
of aged transeitters and use or proper Transmitter oatput calibration.
variation was de-tected during testin0 apparently because incomplete instruc-tion was provided by GE to testing engineers regarding calibration.
GSU/GE is to confire that River Bend in-l
]
stallation engineers have received the com-plete instruction and the transeitters are properly calibrated.
N555-8 B21-F0288 Main steam isolation Isolates the steamline Adequacy of the Additional documents Closed See G5U letter valve upon demand valve body was not were provided to indi-ADG-20996 dated demonstrated.
cate that the valve 5/15/05.
body was analyzed sepa-GSU is to confirm rately and to confire compliance with GE's fleid modifications.
recommendation regard-ing the following required for quali-fication:
Bracket modifica-tion for llelt switch.
Elimination of junc-tion boa.
The source of River 8
i Bend-specific RR$ was not presented during the audit.
I
Table 3.1 (Continued)
SQai Appilcant Equipment name 10 No.
ID No.
and description Safety function Findings Resolution Status Remarks Qualificatlodverified Closed BOP-1 1CCP*MOV138 10" motor-operated is required to isolate valve the containment and to during audit.
intercept the water flow of the reactor plant component cooling water system (RFCCW) to the non-regenerative heat exchanger.
nhe=s J
90P-2 1RCP*TCA03 Termination cabinets Are required at penetra-Qua11 fled W **
- Closed tions to contain the dw..)
Lt.
wiring used in instru-mentation monitoring and control of equipment used in various safety-related functions.
30P-3 IEH5*MCC Motor control center:
Required to provide Qualification of Additional dx ments Closed See G5U letter A two-bay rectangular Class IE power devices apparently were provided to quell-ROG-209%
cabinet containing distribution.
covered by Gould fy devices; document dated 5/15/85.
starters, circuit reports R-STS-10, 31 test mounting; confire and analysts was not testing of both ener-breaters, switches, available for review.
gized and deenergt2ed teral,nal, blocks, etc.
conditions; and circuit Testing of mounting breaker quellfication was not documented.
was included in the documentation package.
It is not clear free test report whether the MCC was tested for 5 OBE and 1 SSE for both the energl2ed and deenerglied conditions.
Supplemental' eval-uation report for HE 4-3 circuit breakers was not part of the qualification docu-8 mentation package.
S
l 1
Table 3.1 (Continued)
SORT Applicant Equipment name j
10 No.
10 No.
and description Safety function Findings Resolution Status Remarks 30P-4 1E12*PC003 Centrifugal fill Maintains the RHR sys-The site inspection Installation deficien-Closed See G5U letter i
pump: A pimp / motor tem piping filled sad revealed the following cies were corrected.
ROG-20996 dated assembly.
ready for main RHR pamp deficiencies:
5/15/85.
startup.
The shie stack was loose.
One nut in the seal housing was loose and another was missing.
The motor nameplate -
was missing.
W 30P-5 1HVC*ACU1B Control building air Maintains the control Qualification, verified Closed conditioning unit building at design tee-during audit.
perature and humidity.
wHP 90P-6 1HVR*A0010A Air-operated damper:
Operates only during Qualjfied W.
Closed l
It is duct mounted LOCA when it bypasses mp alma +.g an.h i
and supported from the air to the standby the ceiling gas treatment building.
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30P-7 IL5V*C3A Leakage air systes Provides pressurized Quallflee W
Closed compressor: A single air to containment iso-rotary compressor lation valves to prevent with electric motor release of fission prod-drive ucts after LOCA.
30P-8 150t'XRC14 Transformer Furnishes power to Dynamic siellarity Additional documents closed See G5U letter various Class 1E instru-brtween the tested were provided to jus-lleG-20996 ments as part of the specimen and the River tify stellarity. test dated 5/15/85.
j uninterrupted power Send transformer was sounting, anomalles, l
s e ly system.
not established.
and site installation.
l Test mounting was not completely documented in the test report.
e Test anomalies were mentioned, but neither described nor justi-fled in the test report.
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Table 3.1A Generic issues Generic
- Issue No.
Resolution Status Remarks 1, 2 During a meeting between staff and applicant in Confirmatory See GSU letter RBG-21093, Bethesda on June 10, 1985, the applicant demon-5/24/85. This is the strated improvement of its qualification docu-license condition for mentation and review program.
The applicant is exceeding 5% of rated committed to perform an independent internal power.
audit and report the results to the NRC before exceeding 5% of rated power.
3 The applicant has developed a procedure to perform Confirmatory See GSU letter RBS-19377, a review of all qualification documents and 11/8/84.
Effectiveness extract the preventive maintenance requirements is to be verified in a necessary for the qualification.
audit.
4, 5 During a meeting between staff and applicant in Closed Bethesda on May 10, 1985, the applicant presented FQC inspection reports and startup manual to demonstrate improvement / effectiveness of the existing procedure to identify field installation deficiencies.
6 The applicant has confirmed the completion of the Closed See GSU letter RBG-21575, as-built piping analysis, and concluded that g 7/19/85.
values obtained from the analysis are not higher than the g values used to qualify the equipment.
7 During the May 10, 1985, meeting in Bethesda, Closed the applicant showed that all BOP equipment pro-1 curement specifications were upgraded to the IEEE 344-1975 requirements.
8 The applicant is committed to confirm completion Closed See GSU letter RBG-20594, of qualification of all safety-related equipment 3/29/85.
- See Section 3.10.1.4 of this supplement for statement of issues.
I
l S
' Table 3.2 PVORT findings on operability qualification of pumps and valves (revised from SSER 2)
Plant ID No.
Description Safety function Findings / resolution Status E22-F015 20" motor-Opens in re-GSU resolved earlier concerns by providing docu-Closed i
l operated gate sponse to either mentation demonstrating qualification by sial-valve (NSSS) a suppression larity analysis extending test results from a pool high-level similar 24" valve.
signal or a low-condensate tank level, contain-ment isolation.
ISWP-P2A Standby ser-Provides cool-GSU provided additional documentation and analy-Closed vice water ing water for sis results at the May 10, 1985, Bethesda audit pump (BOP) safety-related responding to staff concerns regarding vibration l
equipment if acceptance criteria and coupling runout values normal service measured during installation alignment. Correc-water is lost tions were also provided clarifying errors noted during the site audit. "Long Ters Operability of Deep Draft Pumps" (IE Bulletin 79-15) concerns for this pump are under staff review as noted in the February 6,1985, letter to GSU from the NRC.
B33-F060A 20" flow con-Maintain pres-Satisfactory.
Closed trol valve sure boundary l
(NSSS) integrity.
IE12-MOVF021 14" motor-Containment Staff concerns regarding stem leakoff require-Closed l
operated globe isolation.
ments, welding discrepancies, and document issue j
valve (BOP) dates have been satisfactorily addressed in the applicant's letter of March 29, 1985, and during the Bethesda May 10, 1985, audit.
1HVC-MOV1B 24" motor-Isolate main Serial no. discrepancy and staff concerns regard-Closed i
operated control room ing serialization procedures have been satisfac-butterfly during LOCA.
torily addressed in GSU's March 29, 1985 letter.
valve (BOP) i I
4
Table 3.2 (Continued)
Plant ID No.
Description Safety function Findings / resolution Status ICCP-MOV138 10" motor-Outboard con-Staff concerns regarding serialization discre-Closed operated tsinment iso-pancy, stroke time, stem leakoff, space heaters, gate valve lation valve.
and checkout procedure revisions have been satis-(80P) factorily addressed by GSU in the March 29, 1985, letter and the May 10, 1985, Bethesda audit.
B21-A0VF32A 20" check Containment iso-Satisfactory.
Closed valve (BOP) lation and reactor cool-ant pressure boundary.
E33-50V14 2" solenoid-Provides initial Staff concerns regarding an installation error Closed operated globe pressurization noted during site audit, opening air pressure, valve (BOP) of main steam spring closure forces, and air quality have been positive leak satisfactorily addressed in GSU's March 29, 1985, control system.
letter and the May 10, 1985, Bethesda audit.
f E12-C002C RHR pump Supplies water Staff concerns regarding the use of manufac-Closed (NSSS) to the core in turer's acceptance criteria, reject and accept-the event of an ance tags, serialization discrepancy, conformance accident.
to IEEE standards, and age-sensitive components
).
have been satisfactorily addressed in GSU's l
Suppression March 29, 1985, letter and the May 10, 1985, e
pool cooling.
Bethesda audit.
E12PC003 RHR sub-Maintains RHR Staff concerns regarding effects of using sup-Closed system fill system piping pression pool water and the capability of the pump (BOP) filled and ready pump / motor at reduced voltages have been satis-for RHR pump factorily addressed in GSU's March 19, 1985, startup.
letter and the May 10, 1985, Bethesda audit.
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Seismic and Dynamic Qualification of Seismic Catecory I Mechanical and 3.10 Electrical Equipment 3.10.1 Seismic and Dynamic Qualification Input to be provided by the Seismic Qualification Review Team (SQRT).
3.10.2 Operability Qualification of Pumps and Valves 3.10.2.1 Introduction To assure that an applicant has developed and implemented a program regarding the operability qualification of safety-related pumps and valves, the Equipment Qualification Branch (EQB) performs a two-step audit. The first step is a re-view of Section 3.9.3.2 of the FSAR for the description of the applicant's pump The information provided in the FSAR, and valve operability assurance program.
l however, is general in nature and not sufficient by itself to provide confidence in the adequacy of the licensee's overall program for pump and valve operability qualification. To provide this confidence, the Pump and Valve Review Team (PVORT),
1 consisting of staff from Brookhaven National Laboratory (BNL) and the NRC, con-ducted an onsite audit of a small representative sample of safety-related pumps and valves and supporting documentation.
The criteria by which the audit is performed are described in Section 3.10 entitled " Seismic and Dynamic Qualification of Mechanical and Electrical Equip-ment" of the Standard Review P.lan. The SRP Section 3.10 provides detailed guide-lines on how to satisfy the requirements of applicable portions of General 1
i Design Criteria (GDC) 1, 2, 4, 14, and 30 of Appendix A to 10 CFR 50 as well as Appendix B to 10 CFR 50.
6 1
RIVER BEND SER SEC 3.10 INPUT 1
07/29/85
3.10.2.2 Discussion In performing the first step of the audit, the EQB staff reviewed Section 3.9.3.2 of the River Bend Station Unit 1 FSAR. The onsite audit, or second step, was performed by the PVORT during the week of October 29, 1984. The purpose of this two-step review process is to determine the extent that Gulf States Utilities Company (GSU) meets the criteria of Section 3.10 of the SRP. A sample of three NSSS and seven BOP components was selected to be audited.
The onsite audit includes a plant inspection of the as-built configuration and installation of the equipment, a review of the normal, accident, and post-accident conditions under which the equipment and systems must operate, the fluid dynamic loads, and a review of the qualification documentation (status reports, test reports, analysis specifications, surveillance programs, and long-term operability program (s), etc.).
A post-audit meeting with the staff and the utility (GSU) and Stone & Webster i
and General Electric was held at the Nuclear Regulatory Commission offices in Bethesda, MD for the purpose of discussing the confirmatory issues resulting from the NRC site audit and transmitted to GSU in the NRC's February 6,1985
- letter, Table 3.10.2.1 identifies the equipment audited, the audit findings, and the j
resolution of equipment specific items resulting from the audit.
In addition to the equipment-specific items, the NRC audit also revealed several items related These items are to the broad program for pump and valve operability assurance.
perceived by the staff to be systematic in nature and they cut across specific equipment items. These items are discussed below in Section 3.10.2.3.
3.10.2.3 Generic Items The generic items determined during the site audit are listed below with their 4
resolution and status.
RIVER BEND SER SEC 3.10 INPUT 07/29/85 2
rm
=,
I 1.
In many instances, it was observed that evidence of complete qualifica-tion was unavailable. More recent documentation, packages were incom-plate and appeared to be put together without checking. The PVORT long forms contained numerous inconsistencies ranging from' serial numbers, i
capability, and qualification information of the actual equipment. The appitcant is to develop a more systematic program to perform' the accep-tance review of safety-related pumps and valves.
fi 8
Theapplicanthasdemonstratedduring2;p:t-:MtImeeting[
l Resolution:
64 Bethesda that an improvement in the qualification documentation and review program has been achieved. Additionally, details of the GE and SWEC review and approval procedures were presented to the staff during the May 10, 1985 audit in Bethesda.
Status: Closed.
2.
During the acceptance review of equipment, a procedure should be de-veloped to identify limited life parts and ensure their replacement at appropriate intervals.
Resolution:
Intheappignt'sletterofMarch 29, 1985, reference is made to a November 8. TJ4) letter (R85-19,377) directing SWEC to per-l2A) form a review of all qualification documents submitted by equipment vendors for both BOP and NSSS and extract the preventive maintenance requirements necessary to maintain qualification. GSU also directed 3
SWEC to develop a procedure to address the ongoing review of qualifica-i tion documents for maintenance and surveillance requirements.
1 Status: Closed.
3.
Procedures should be established to return tested equipment to its qualified status.
l i
07/29/85 3
RIVER SEND SER SEC 3.10 INPUT i
l
-- ~ -,-
V.
Resolution: The applicant in the March 29, 1985 letter and the May 10, 1985 audit at Bethesda provided additional information and documenta-tion demonstrating the adequacy of the existing procedures.
Status: Closed.
4.
Components were found to be incorrectly or improperly installed.
Pro-cedures should be established verifying equipment installation require-ments and qualification.
~
Resolution: The applicant's response in the March 29, 1985 letter and la the subsequent audit bt,Bethesda on May 10, 1985 have satis-fled the staff that the discrepancies noted during the site audit are isolated cases and do not require programmatic changes to preclude recurrence.
Status: Closed.
5.
All pumps and valves important to safety have had their required pre-operational tests completed prior to fuel loads.
b Status: Applicant's letter of July 26, 1985 indicates that all pre-operational tests are completed. This issue is closed.
6.
All pumps and valves important to safety are qualified prior to fuel load.
P-Status: Applicant's letter of July 22, 1985 indicates that of all the safety-related pumps and valves, only the Borg Warner globe valve actuator will be seismically qualified after the fuel load. All l
other pumps and valves era scheduled to be qualified prior to fuel loading. The seismic qualification of the Borg Warner globe valve is addressed in Section 3.10.1 of this report. In theirletter of 1
July 26,1985, the applicant confirmed that all pumps and valves important to safety have been qualified. This issue is closed.
07/29/85 4
RIVER BEND SER SEC 3.10 INPUT
7.
The applicant shall confirm that new loads resulting from LOCA or analysis of as-built conditions applicable to pumps and valves important to safety do not exceed those loads originally used to qualify the equipment.
1 Status:
In the July 26, 1985 letter, the applicant stated.that as built piping analysis to reconcile the differences between the actual loads and the loads originally used to qualify the pumps and valves is complete. This issue is closed.
i 3.10.2.4 Evaluation Summary On the basis of the review of the pump and valve qualification program, obser-vation of the field installation and the responses provided by the applicant to the PVORT's questions, it is evident that the applicant's pump and valve opera-bility assurance program is properly defined and substantially implemented.
The equipment-specific findings resulting from the PVORT site audit have been l
resolved and are discussed in the Table 3.10.2.1.
In a letter from Booker to i
Denton, dated July 22, 1985, the applicant has stated that there are only four ofequipse that will not be qualified prior to fuel loading. Only one of i
the four items to be qualified after fuel load is related to pump and valve operability qualification. That ites, the Borg Warner globe valve, requires
]
completion of seismic qualification of the valve actuator.
i The Borg Warner globe valves are covered by a license condition under Section 3.10.1 of this report. Thus, there are no outstanding open issues with respect to pump
~
l and valve operability qualification, j
l The operability qualification program for safety-related pumps and valves at the River Bend Station, Unit 1, meets the applicable portions of GDC 1, 2, 4, 14, and 30 of Appendix A to 10 CFR Part 50 Appendix 8 to 10 CFR Part 50, and j
Appendix A to 10 CFR Part 100.
i i
RIVER BENO SER SEC 3.10 INPUT
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07/29/85 5
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3.IC 3 S Long Term Operability Deep Draft Pumps - IE Bulletin 79-15 In response to the IE Bu'11etin 79-15, the applicant identified the deep draft pumps in letters dated September 11, 1979 and October 22, 1979. The resolution of the concern identified in the subject bulletin is addressed by the applicant in the FSAR Section 9.2.7.4.
The applicant has used the guidelines endorsed by the staff and has completed the performance / endurance testing as indicated in the TSAR. The tests included verification of performance at normal flow for 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />.
The staff concludes, on the basis of the discussion above, that the concerns identified in IE Bulletin 79-15 are satisfactorily resolved and this issue is closed.
4 1
07/29/85 6
RIVER BEND SER SEC 3.10 INPUT
- - ~ -.
Table 3.10.2.1 Audit Findings.
Page 1 of 4 Plant 10 No.
Description Safety Function Findings / Resolution Status em 3
~
- w.. J b
E22-F015 20-inch motor Open in re-Applicant resolved Closed operated gate sponse to earlier concerns by valve (MSSS).
either a sup-providing documenta-pression pool tion demonstrating high-level sig-qualification by sini-nel or a low larity analysis ex-condensate tank tending test results level - con-from a stellar 24-inch tainment isola valve.
tion..
ISWP-P2A Standby ser-Provide
- cool Applicant providad ad-Closed vice water ing water for ditional documentation pump (BOP).
safety-related and analysis results equipment if at the May 10, 1. 8.
normal service Bethesda e-s tarr water is lost.
sponding to staff con-i cerns regarding vibra-tion acceptance cri-teria and coupling run out values measured during installation alignment. Correc-tions were also pro-vided clarifying er-rors noted during the site audit.
Long Tem Operability of Deep Draft Pumps (IE Bulle-tin 79-15) concerns for this pump % d p t staff review as noted in the February 6, 1985 letter to GSU from the NRC.
e O
Table 3.10.2.1 Audit Findings.
Page 2 of 4
( Remarks
})C2e Plant ID No.
Description Safety Function Findings / Resolution Status B33-F060A 20-inch flow Maintain
- pres-Satisfactory.
Closed control sure boundary valve integrity.
(NSSS).
1E12-MOVF021 14-inch motor Containment Staff concerns regard-operated isolation.
ing stem leakoff re-globe valve quirements, welding (BOP).
discrepancies, and g
document issue dates Closed have been satisfac-torily addressed in the applicant's letter of March 29, 1985 and during the Bethesda May 10, 1985 audit.
1HVC-MOV18 24-inch MD Isolate main Serial no. discrepancy butterfly control room and staff concerns re-valve (BOP).
during LOCA.
garding serialization procedures have been Closed satisfactorily ad-dressed in the app 11-cant's March 29, 1985 letter.
ICCP-MOV138 10-inch Outboard con-Staff concerns regard-Closed motor oper-tainment iso-ing serializatica dis-ated gate lation valve.
crepancy, stroke time, valve (BOP).
stem leakoff, space heaters, and Checkout Procedure revisions have been satisfactor-11y addressed by the applicant in the March 29, 1985 letter and
l l
l Table 3.10.2.1 Audit Findings.
Page 3 of 4 Plant ID No.
Description Safety Function Findings / Resolution Status Remarks the May 10, 1985 id at Bethesda.
e TEI' B21-A0VF32A 20-inch Containment Satisfactory.
Closed check valve isolation and (BOP).
reactor cool ent pressure boundary.
E33-50V14 2-inch Provide int-Staff concerns regard-Closed solenoid tial pressuri-ing an installation operated zation of main error noted during*
globe valve steam positive site audit, opening (BOP).
leak control air pressure, spring system.
closure forces, and air quality have been satisfactorily ad-dressed in the app 11-cants March 29, 1985 letter and the May 10, 1985 Bethesda audit.
E12-C002C R!R pump
' Supply water to Staff concerns regard closed (NSSS).
the core in the ing the use of manu-event of an ac-facturer's acceptance cident. Sup-criteria, reject and pression pool acceptance tags, seri-cooling.
alization discrepancy, conformance to IEEE, and age sensitive com-ponents have been sat-1sfactorily addressed in the applicant's March 29,1985 letter and the May 10, 1985 Bethesda audit.
~
8 Table 3.10.2.1 Audit Findings.
Page 4 of 4 Plant ID No.
Description Safety Function findings / Resolution Status Remarks t
E12PC003 RHR - sub Maintain RHR Staff concerns regerd Closed.
system fill system piping ing effects of using pump (BOP).
filled and suppression pool water ready for RHR and the capability of pump startup.
the pump / motor at re-duced voltages have been satisfactorily addressed in the ap-plicant's March 29, 1985 letter and the May 10, 1985 Bethesda audit.
I I
L 3.10 Seismic and Dynamic Qualification of Safety-Related Electrical and Mechanical Equipment 3.10.1 Seismic and Dynamic and Qualification 4
3.10.1.1 Introduction l
As part of the review of the applicant's Final Safety Analysis Report (FSAR) l i
Sections 3.7.3 A, 3.7.3 B, 3.9.2 A, 3.9.2 B, 3.10 A and 3.10 B, an evaluation l
is made of the applicant's program for seismic and dynamic qualification of j
safety-related electrical and mechanical equipment. The evaluation consists of:
(1) a determination of the acceptability of the procedures used, standards followed, and the completeness of the' program in general, and (2) an audit of j
selected equipment to develop a basis for the judgement of the completeness and adequacy of the seismic and dynamic qualification program.
i Guidance for the evaluation is provided by the Standard Review Plan (SRP) j Section 3.10, and its ancillary documents, Regulatory Guides (R.G.) 1.100, l
1.61, 1.89, and 1.92, NUREG-0484, and Institute of Electrical and Electronics Engineers (IEEE) Standards 344-1975 and 323-1974. These documents define acceptable methodologies for the seismic qualification of equipment. Con-i formance with these criteria is required to satisfy the applicable portions ofo#'the General Design Criteria 1, 2, 4, 14, and 30 of Appendix A to 10 CFR Part 50, as well as Appendix B to 10 CFR Part 50 and Appendix A to 10 CFR Part 100. Evaluation of the program is nerformed by a Seismic Qualification Review Team (SQRT) which consists of^sk W
~
engineers f ;; th. Zy ip;;..; Q.iiiication cas.iH***8 fr'^
0.;.;h CW;;/:Q:) and,the Brookhaven National Laboratory (BNL, Long Island).
i.
3.10.1.2 Discussion i'
l The SQRT has reviewed the equipment seismic and dynamic qualification informa-l tion contained in the FSAR Sections 3.7.3 A, 3.7.3 B, 3.9.2 A, 3.9.2 B, 3.10 A 1
and 3.10 B and made a plant site visit from October 29 through November 2,1984.
The purpose was to determine the extent to which the qualification of equipment, as installed at River Bend meets the criteria described above. A representative i
l l
07/26/85 3.10.1-1 RIVER BEND SER SEC 3.10.1
\\
sample of safety-related electrical and mechanical equipment, as well as instru-mentation, included in both Nuclear Steam Supply System (NSSS) and Balance of Plant (BOP)[ h, was selected for the audit.
Table 3.10.1.1 identifies the equipment audited. The plant-site visit consisted of field observation of the actual, final equipment configuration and its installation. This was followed by a review of the corresponding qualification documents. The field installa-tion of the equipment was inspected in order to verify and validate equipment modeling employed in the qualification program.
During the audit the applicant presented details of the qualification and in-service inspection program.
3.10.1.3 iummary of Audit Findings On the basis of the observation of the field installation, review of the quali-l fication documents, responses provided by the applicant to SQRT's questions during the audit, and correspondence and meetings with the applicant following the audit, the applicant's seismic and dynamic qualification program has been found to be defined and largely implemented.
The equipment-specific findings and resolutions as a result of the SQRT audit are identified in Table 3.10.1.1.
The generic issues are identified in section 3.10.1.4.
The resolution, status I
and remarks for each generic issue is provided in Table 3.10.1.2.
The license conditions are identified in Section 3.10.1.5.
Based upon review of the appli-cant's FSAR and the resolution of issues identified during the SQRT audit, the staff concludes that the seismic and dynamic qualification of safety-related equipment at the River Bend Station, Unit 1, does meet the applicable portions of GDC 1, 2, 4, 14 and 30 of Appendix A to 10 CFR Part 50, Appendix B to 10 CFR Part 50, and Appendix A to 10 CFR Part 100.
3.10.1.4 Confirmatory Issues As a result of the plant site visit the following generic issues were identi-fled. The staff considers these issues to be of a confirmatory nature.
For each of the following issues the corresponding status, resolution, and remarks are provided in Table 3.10.1.2.
4 1.
Each equipment qualification document package contained summary statements and overall conclusions. The conclusion for each package was that the equipment was fully qualified.
However, in many instances it was observed 07/26/85 3.10.1-2 RIVER BEND SER SEC 3.10.1
--v.
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that evidence necessary to reach the state of complete qualification was unavailable. More recent documentation packages were incomplete and appeared to be put together without adequate checking after the selection of equipment was transmitted to the applicant. Therefore, the appifcant was to develop a more systematic program to perform the acceptance review of all safety-related equipment.
2.
Where the qualification document package identifies a need for equipment modification, the applicant was to develop a systematic program to include in the qualification package either a statement indicating implementation of the modification or justification for not implementing the modification.
3.
In many cases, it was observed that the equipment qualification report identified parts with a limited-life.
Such equipment could be located in either a mild or a harsh environment. The applicant was to develop a systematic procedure for identifying limited-life parts and to ensure their replacement at appropriate intervals during the acceptance review of equipment.
Qas There weee, equipment 9 eees found to be incorrectly or improperly installed.
4 4.
The applicant was to develop a procedure to check proper mounting of all safety-related equipment consistent with the qualification mounting con-figuration.
pieces of 5.
It was observed that for many equipment the enclosure panel was partially
)
3 removed or screws were loose reportedly in order to facilitate preopera-l tional testing. The applicant was to develop a procedure to insure that j
such equipment is returned to the qualified status.
6.
Upon completion of as-built piping analysis for all pipe-mounted safety-related equipment, the applicant must confirm that the g-values used for qualification of these equipment were not lower than the g-values obtained from the as-built piping analysis.
07/26/85 3.10.1-3 RIVER BEND SER SEC 3.10.1
.c-.
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7.
The qualification of those pieces of equipment which were originally quali-fied to meet IEEE Std 3,44-1971, should be identified and upgraded to meet the requirements of IEEE Std 344-1975 as applicable.
8.
Upon completion of the on going qualification process, the-applicant must confirm that all safety-related equipment have been qualified.
3.10.1.5 License Conditions Me fo// oui,heert e :kernse conod'Avn tai // de incogowa AlA1A' S 05<
ope +a h9 The " h;r Stad r"a1 Lc:d, L:n r;ucr :nd Fu!1 P:wcr Licen m r-e @ ject te th-e,%
f;11re'n; cend4 tf ent :c--CL-
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a,ppl;co.4 sbo.k prico 'lc SYufo l*"' I )
h c
1.
The ro 1 F:r:r L':ence 1 cenditioned up;n ;.;...yplicent ;,;d!!yf ag =11 4
hydraulic control units.during th: tF'rd refu:!'ng ;utege.
The modifica-tion consists of installing the additional brace used during the qualifi-cation test of the equipment. The applicant's letter RBG-20996 dated May 15, 1985 indicated that the Nitrogen Cylinder Hangar on the Hydraulic
~
Control Units (ICII*ACTD001) are qualified to a limited life based on SRV fatigue test data.
$ all, prier-k e$cteding &st ptrese)" rn. fed power"> Pet-bas h
~
2.
The L= P:u:r Lie:n:; is cend tivu.d veen the applicant p;ciec.,ing an independent internal audit of seismic qualification documentation and su.snA* %e r-yw.tingresults to the staff,pri;r t: n;eeding 0% pw.r.
Issues iden-tified by the audit must be resolved to the staff's satisfaction prior to exceeding 5% power.
4:nt da., prior lo wc eediq i" P**I '**'0 **$ '** P '?' **
f F
I 3.
The t: 7:r:- Lf::n.; is ;;nditi;,;d u;:r the * *en:' the ' seismic g
qualification of panel board IENB*PNLO4A, prier tw www.d;ng 5% pu;r Low power operation prior to completion of qualification is g
justified based on similarity of the unqualified panel board to other panel boards which have been qualified for River Bend requirements.
I appheQ &\\, prior b egceed;ng ele. p& RAW paaeh>p C*MP '
4.
The t e Perer l'eeace 15 cend't';n;d p;n th; ;-vi.i.;wn
? the seismic g
qualification of the HPCS Diesel Generator,priec te
.w ding 5% p;-;r, Low power operation prior to completion of seismic qualification of the 07/26/85 3.10.1-4 RIVER BEND SER SEC 3.10.1 i
HPCS Diesel Generator is justified because the Automatic Depressurization System (ADS) is redundant to the HPCS system.
The ADS is fully qualified, mt;J M, prtor k epeedi9 S '*4P '*t'*( P"> C'~P ete. &
P L
5.
The,Lc."; c r ' ' e-a r e f : ::ndittened uper th: :::p!:tfer;Neismicquali-
{
fication of Borg Warner globe valves purchased under GSU specification No. 247.97,prf:- t: creeedk;; 0% p;-ar.
Low power operation prior to com-pletion of seismic qualification is justified because of similarity between the valve actJators of the unqualified valves and the actuators of valves which have been qualified for River Bend requirements. The qualification of the valve body has been demonstrated by static analysis and static de-
~
flection tests.
o ppliM cs.Rallg CoNP 8b I
6.
The L; "; ;. and Pu?' a:1.c Licen;;; a e cenditi:n:d pen th: :;;.p h t kr-3 c
.ad the seismic qualification of the In-Vessel Rack (MPL No. F16-E006) prior to use.d.ri. ;; the f'r:t ref :'ia; eute;;:. The b-Vessel "::' the! W D: tsind in Uiu plant was uiivu5e pa-iwe tu wwmpieT.lon 07 seimmis -
ge !**f::.t h..=" -
O ee 6
1 07/26/85 3.10.1-5 RIVER BEND SER SEC 3.10.1
8 Table 3.10.1.1 0
0:
D SQRT Appittant Equipment Name
" ID No.
10 lea.
and Description Safety Function Findings Resolution Status Remarks 18555-1 1C11*ACT0001 leydraulic Control Translates scram signal The additional brace Quallfted to a ilmited Closed See G5'J 1etter Unit. Assembly con-Into hydraulle energy used during quaitfi-Itfe based on SRV RBG-20995 dated sists of M cylinder, to insert the control cation test of the fattgue test data prior 5-15-85.
This a
water accumulator rod drive and allow its equipment was alssing to failure of the hanger is a License and various valves.
return flow to discharge from the Installed and subsequent addition Condition on Full through the eahaust
- unit, of the second brace.
Power Operstlan.
valve.
18555-2 Il13-P680 Plant Centrol Consale. The console supports
- 1. The dynamic sle-Additional documents /
Closed See G5U 1etter A U-shaped monitoring instruments which are 11erity between tne clarifications were RBG-20996 dated benchboard.
used to montter and tested specimen and provided to show stal-5-15-85.
control the safe opera-the River Send con-1erity, test mounting, i
w tion and shutdown of sole was not estab-and capability g-values.
the plant.
Ilshed.
-[
- 2. The test mounting e
was not docimented In the test report.
- 3. For components quellfication, the capability g-values were not defined and demonstrated to en-velop the RAS over the entire frequen-g cy range.
E 18555-3 C61-P901 Remote Shutdown it provides redundant The Installation con-The vertical board.and Closed See G5U letter g
Vertical Board means for safe shut-dition of being neat the adjacent cabinet R8G-209% dated g
down of the plant.
to another cabinet are being bolted 5-15-85.
and the wall was not ttgether.
addressed in the g
qualification.
E O
t e
Table 3.10.1.1 (Continued)
S e%s h SORT App 1tcent Egulpment lemme IB Ito.
10 Iss.
and Description Safety Function Findings Resolution Status Remarks 11555-4 E12-C002A.C RNR Pump and fester The assashly is required Qdibcafion to pump water in the sup*
Ve ri6*e ol g5c daria$ clue le b pression pool during pool cooling modes and LPCI wessel injectlen modes.
le555-5 Is13-P601 Reacter Core Coeling It contains fastruments
- 1. Dynamic stellarity Additional documents /
Closed See G5U letter Bench Seerd. A mont-that are used for manual between the tested clarification were R8G-209% dated toring panel.
control for accident specimen and the provided to show sist-5-15-85.
mitigation of the emer-River Send was not larity, test sounting, gency core cooling estabitshed.
capablitty g-values, system.
- 2. Test asunting was device qualtftcation not completely docu-below 5 Hz, controller o
mented in the test and recorder informa-
.O report.
tion, and installation 7
- 3. For component correction.
quellfication, the capability g-walues were not defined and demonstrated to envelop the RR$ over the entire frequency range.
- 4. Quellfication of some devices below 5 Hz was alssing.
E 5.
Controller and
- llC, recorder units were sliding during tests.
R lt could not be verl-fled from documentation presented whether River Bend panel contains these destces.
n"
.Q
8 4
Table 3.10.1.1 (Continued)
S Pe b SORT Appilcant Equipment hee It me.
Is Iso.
and Descrfptten Safety Functlen Findings Resolution Status Remarks 18555-5
- 6. 51te Inspectien (Cent'd) revealed the following:
a) One untstrut was loose.
b) GE ERIS terminals were very flexible.
11555-6 Is13-P6M Issutron/ Process Provides informetten The cabinet was in-Additional doc uents Closed See G50 letter Reetetten stenttering about power levels and stalled with 1/2" provided to show % in.
reg-20996 dated Systre.
power distributten in diameter bolts al-dia. bolts adequate 5-15-85.
the reactor, and is though the specimen for River Send.
tied to a trip system was tested with 5/8*
(Seector Protectlen diameter bolts.
-w System).
7 IE555-7 let2-PO41.42 Benin Stese Flaw It soports Class 1E
- 1. Transmitters were Additional documents Closed See Csu 1etter Local Panel devices not environmentally provided to demonstrate R9G-20996 dated aged prior to setsete quaitfication of aged 5-15-85.
testing.
transeltters and use
- 2. Transeltter output or proper calibration.
variation was de-tected during testing apparently due to incomplete instruc-tion provided by CE to testing engineers regarding calibration.
G5U/CE is to confire R
that River Bend in-5 stallation engineers have received the com-u9 plete instruction and the transeltters are properly calibrated.
w 3
I i
8 i
l t
l l
e Table 3.10.1.1 (Continued)
S2 5 SORT Aspitcant Espelpment name
- Is me.
10 see.
and coscriptten Safety Functlen Findtags Resolution status Reserks N555-8 321-Feres stein Steen Iseletten It Isolates the steam
- 1. Adequacy of the Additional deciments Closed See CSU letter Valve Ifne upon doet.ad.
valve body we. not provided to indicate R8G-20996 dated demonstrated, that the valve body 5-15-85.
- 2. G5U ts to confire was analyzed separately compitance with GE's and t.s confire field recosamendetton regard-medIfIcat1ons.
Ing the fellowing required for quelt-ficati m:
a) Bracket modifica-tion for Llelt Switch, b) Elimination of junc-tion bem.
o
- 3. The source of River P
bend spectfic RR$ was 7
not presented during the eudit.
SOP-1 1CCP'tWV138 IS" IInter Operated The welve to required M.ficnk
%; ;i;a,
Velve to Isalate tIie contata-ygg.gpied (bM ment and to intercept g - auag,g the water flow of the l
reacter plant component cooling water system (RPCCW) to the non-7..
regenerettwo heet enchanger.
C" 30P-2 14CP*TCA03 Teretnetten The cabinets are required W
at penetrattens to contain Vf is the wiring used in Instrv-
" ggsl.Y 06 9
mentation monitoring and I
control of equipment used w
E in wartous safety related functions.
w
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i l
Table 3.10.1.1 (Continued) i Sh h 50AT Appilcant Egulpment Name Is me.
ID No.
and Descriptfon Safety Functlen Findings Resolution Status Remarks 30P-3 1 Ell 5*MCC seeter Control Center.
MCC is required to pro-
- 1. Qualtfication of Additional documents Closed See CSU letter A two-bay rectangular vide Class IE power devices apparently provided to quaitfy a8G-20996 cabspot containing distribution, covered by Gould devices; document test dated 5-15-85.
starters, circuit reports R-Sis-10.31 mounting; confirm test-breakers, switches, and analysis was not Ing of both energized terminal, blocks, etc.
available for review.
and de-energised condt-i
- 2. Testing mounting tiens; and inclusion of was not documented.
circuit breaker qualtf t-
- 3. It is not clear cation in the documenta-from test report tion package.
I whether the MCC was I
tested for 5 OSE and 1 55E for both the l
energfred and de-l energised conditions.
- 4. Supplemental eval-uation report for HE 4-3 circuit breakers was not part of the quellfication docu-l mentation package.
30P-4 1E12*PC003 Centrifugal fill It estatains the RHR The site inspection Installation deflCten-Closed See CSU 1etter 3
pump. A pump / meter systes pfptng filled and revealed the following ctes were corrected.
R8G-209% dated 2
- assently, ready for main RHR pump deficienCles:
5-15-85.
E startup.
- 1. The shte stack was loose.
9
- 2. One put in the seal housing was loose and M
another was utssing.
- 3. The actor name plate M
was alssing.
ri 4.s O
l Table 3.10.1.1 (Continued) o y
04 h SQRT Appilcant Esgulpment Items IS Ilo.
10 iso.
and Descrfption Safety Functfen Findings Resolution Status Remarks 30p-5 1HWC*ACUlt Centrol building air It maintains the control
@ eld;cedfe~
Quauffed conditioning unit, b.stiding at destyi tes-W,;fic (
Qgg perature and humidtty.
y,;
M;b 90p-6 IlWR*A00104 Air operated damper.
It operates only duct a Quettttvis It is duct asunted LOCA when it bypasses and supported free the air to the Staney g
the ceiling.
Cas Treeteent Sullding gep-7 IL5V*C34 Leeltage Air system It provides pressortred M
compresser. A single air to contaiseent iso-retary ce gresser latten valves to prevent g g4 u
with electric motor release of flesten pro-erive alucts after LOCA.
.m.
7 00P-8 150l*RAC14 Transformer It furntshes power to
- 1. Dynaste stellarity Additional documents Closed See CSU letter O
verteus Class 1E Instrv-between the tested provided to justify reg-209%
ments es port of the specimen and the River stellarity, test dated 5-15-85.
Uninterripted power Bend transformer was mounting, enomaltes, Supply System.
not established.
and site installation.
8
- 2. Test mounting was not completely docu-mented in the test report.
- 3. Test enamelles were mentioned. but neIther descrfbed nor justi-fled in the test R
report.
3
- 4. Site inspection re-w weeled the following:
9 a) There was no con-w tact between the base E
plate and concrete in w
most places 5
emu m
I Table 3.10.1.1 (Continued)
Sh S SORT Applicant Egi.lpment liame
- It see.
13 see.
and Description Safety Functlen Findings mesolutten Status pesort s b) 5tde penets were Sep-g IeeSe (Cent'd) c) Sese piste was,iet addressed in the quelt-ficetten documents presented.
Sep-9 IEJS*L9 CIA Lead Centers Titey are required to Only a summary of The ortginal test Closed See CSU 1etter furnish power distribu-test report was report was made evell-89G-209%
tion to efWAC systems in evellable. The able efter the audit.
dated 5-15-85.
the Centrol and Slesel original Wyle Test Generater Sulldtag and Report is needed else to Class IE lentor for review and w
Centrol Centers.
documentatten.
- -~
g Sep-le 15Mp*p23 Stamey Service water It provides cooling we-
- 1. Torstenal fre-Additlenet documents Closed See CSU letter
.~
=
pump. An electrical-ter for safety reisted guency of assently prowlded to justify 99G-209%
Iy delsen vertical equipment usion normal needs to be computed terstenal frequency dated 5-15-85 turbine p g.
service water is lost.
and compared to and pump operability.
seter's operettenet speed.
- 2. Operability of pump under setselc lead needs to be assured.
E f.,
=
5
=
m O
t Table 3.10.1.2 O
h Generic Issues N.
u Generic
- Issue Mo.
Resolution Status Remarks 1, 2 During a meeting between staff and applicant Confirmatory See G5U letter in Bethesda on June 10, 1985, the applicant R8G-21093, 5-24-85.
demonstrated improvement of their qualifica-This is License tion documentation and review program. The Condition for applicant is committed to perform an inde-exceeding 5% power.
pendent internal audit and report the results to the NRC prior to exceeding 5% power.
3 The applicant has developed a procedure to Confirmatory See GSU letter perform a review of all qualification R85-19377, 11-8-84.
documents and extract the preventive main-Effectiveness to w
tenance requirements necessary for the be verified in a
.g quellfication.
future audit.
L 4, 5 During a meeting between starf and applicant Closed in Bethesda on May 10, 1985, the applicant w
presented FQC inspection reports and start-up manual to demonstrate improvement / effectiveness of the existing procedure to identify field installation deficiencies.
=
6 The applicant has confirmed the completion Closed See G5U letter
(
- F, of the as-built piping analysis, and con-RBG-21575, 7-19-85.
cluded that g-values obtained from the
=
R analysis are not higher than the g-values g
used to qualify the equipment.
h 7
During the May 10 meeting in Bethesda, the Closed i
appifcant showed that all DOP equipment o,
R procurement specifications were upgraded to the IEEE 344-1975 requiresents.
w LP
- See section 3.10.1.4 of this SER for statement of issues.
s.
I
l I
l a
Table 3.10.1.2 (Continued)
.4
~==
h Generic" Issue No.
Resolutten Status Remarks a
The applicant is committed to confirm Confirinatory See G5U letter completten of qualification of all A9G-20594 3-29-85.
safety-related equipment.
l l
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- i
=
5 M
=
ive n
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+
3 10. 3
- 0 r:.EA A.h) ad Relief Yalve Tesfing (rmr tw 1r.0.1)
Me s Faff ws+2. 4R.< assisL.. afcondalLh Ga.
Es + G M.., 7.
Jas cy ehd ifs revtew af InGa/rw suhmifial l
.by IAe a A
safeQ &pp L} f A cane feskn g &
relief valves Ae B'ver Bonal I. m.
i sk.FF finds
% inkahn submilled demon s+ea./e.1
{
M e a biI,+y a f A. rsuu% coolan f-sysfu rehd l
amd safeG va.Nes lo fune&o's undes eppec /wf' yerahny candi/r'sn.s Rn 4e. rip-bacis a fra.a sle os 1.s
\\
and acciolenfc as cle Aned un6 TMZ W Hm
.2r; b. L.
Th e. c4e k.i Is af Mis review au tkA Ad i*
i App & -
e i
( & 4 Qu,lif.'ea.1Now &E m la j o u ( 7~ M Z 5 W E ' N ' *
- 3, /O. 2 i YU s_
SAFETY EVALUATION I ACTION PLAN !!.K.3.28 VERIFY QUALIFICATION OF ACCUMULATORS ON ADS VALVE 5 RIVER BEhD STATION UNIT 1 DOCKET NO. 50-458 J./o. 2. 7. l BACKGROUND g
frdf Safety Analysis Reports aim that air r nitrogen ecumulators for the automatic depressurization system (ADS) valves are provided with General Electric (y to cycle the valves open five times at design pressures.GE) has sufficient capacit (ECCS) are designed to withstand a hostile environment and still perform their function for 100 days following an accident. Licensees and applicants must demonstrate that the ADS valves, accumulators, and associated equipment and instrumentation meet the requirements specified in the plant's FSAR and are capable of performing their functions during and following exposure to hostile environments, taking no credit for non-safety-related equipment or instrunen-tation. Additionally, air (or nitrogen) leakage through valves must be ac-counted for in order to assure that enough inventory of compressed air is available to cycle the ADS valves.
If this cannot be demonstrated, it must be shown that the accumulator design is still acceptable.
"3. @. A. 7.1 4
DISCUSSION The comitment to satisfy the requirement of TMI Action Item !!.K.3.28 for the River Bend Station, Unit 1 is discussed in the following submittals.
A.
Gulf States Utilities Company letter from J.E. Booker to H.R. Denton, NRC, dated April 9,1984, response to a request for additional informa-tion.
8.
Gulf States Utilities Company letter from J.E. Booker to H.R. Denton, NRC, dated May 13, 1985.
3,lo.3. 7. 3 DEMONSTRATION OF OPERABILITY The design of the River Bend Station is such that the ADS will be available for 100 days following an accident. Each ADS valve is equipped with a 60 gallon accumulator designed for two (2) actuations at 70 percent of drywell design pressure which is equivalent to 4 to 5 actuations at atmospheric pressure. During normal plant operation, air is supplied from the non-nuclear safety (NNS) main steam system air compressors. Post-LOCA air requirements are supplied from the Penetration Valve Leakage Control System (PVLCS), a nuclear safety related Seismic Category I system.
s
b a
i j
t The realignment from the main steam system air ccmpressors to the PVLCS is c
perfomed by the plant operators from the main control room.
The PVLCS is manually actuated approximately 20 minutes after a LOCA. Prior i
to the manual actuation, the system is in an automatic mode and maintains the accumulators at a preset pressure. Following a loss of off-site power, the PVLCS initiation is delayed to avoid overloading due to starting currents.
l The ADS accumulators are designed and maintained with sufficient inventory to pemit the required actuations during this period, assuming a leakage of 1 f
l SCFH.
l i
FSAR Section 9.3.6.3.1 indicates that the PVLCS accumulators are maintained with
]
enough air to meet all short-term requirements of the PVLCS, the MS-PLCS, and the main steam safety / relief valve system.
j T; cif;;l M d ' 5 t'en 8urveillance reauirementL associated with the sWld b Iacerp..hd in tac R 35 - 8 +8f e
- ve accumulator system and backup systemh; ";;; that the PVLCS accum I
sure is greater than 101 psig,n i;::t : :: ;;, G.......
j The allowable leakage rate of 1 SCFH for the ADS air accumulator sub-system is i
compatible with the Emergency Core Cooling System (ECCS) performance evaluations and assumptions, and the calculations for sizing the ADS air i
supply system. Additionally no credit was taken for non-safety related equipment or instrumentation'when establishing the allowable leakage criteria, f
The air accumulator sub-system is designed to withstand Seismic Category I i
loads and post-accident environments.
i The ADS air accumulator sub-system is defined as all the components between (andincluding)thecheckvalvelocatedontheinletsideoftheaccumulator i
and the associated main steam safety relief valve.
i i
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~
i W.
EVALUATION M he primary source of air for the ADS accumulators is from the non-nuclear safety related main steam system air compressors. Backup to this system is the nuclear safety related PVLCS. The applicant states that the PVLCS is placed in service approximately 20 minutes after it has been i
ascertained that a LOCA has occurred. This realignment is accomplished in the main control room. The 20-minute period is approximately equal to the time required for the PVLCS air compressors to be loaded onto the standby power l
supplies. The applicant has pa;f f:d : :t:t: : t xM*"'-- that the ADS accumulators have sufficient inventory to assure operability of the ADS valves during this 20-minute interval.
gg l
The accumulator on each ADS valve has a 60-ga11on capacity which is designed for two actuations at 70 percent of drywell design pressure. This capability l
is equivalent to 4 to 5 actuations at atmospheric pressure, i
I
-_,__....m-__
.-m_.-._,
4 3-The staff concludes that the applicant has demonstrated the long and short tem capability of the automatic depressurization system and is therefore acceptable, b,E Mhe applicant states that the allowable leakage rate of 1 SCFH is ba' l
compatible with the ECCS performance evaluations and assumptions, and t Mb 4 calculations for sizing the ADS air supply. Therefore,.-----..,... M a) the capacity of the accumulators (b) that the ECCS is a NSSS (GE) designed s.vstem, and (c) that previous submittals have discussed in detail the basic for the allowable leakage criteria, the staff concludes that the allowable j
leakage criteria of 1 SCFH address the concerns in this area and is acceptable.
8The applicant has provided information acceptable to the staff '-Mt've clescr*A3nj
.es the development of surveillance, maintenance, and leak testing programs for the ADS accumulator system and associated alams and instrumentation, 8The applicant has provided information confirming that:
I the backup air supply system, pVLCS, is seismically and environmentally qualified, and I
the accumulators and associated equipment are capable of performing their functions during and following an accident, while taking no i
credit for non-safety related equipment and instrumentation.
3J0..a. 7. f l
6 CONCLUSION Based on the information provided by the applicant sumarized in Section 5 5.10.a.13 and the evaluation perfomed highlighted in Sectio $ the staff concludes that the4 s" he; Utilitie;.: ;=y has verifi qualification of the 0
raccumulatordhn ADS valves for River Bend Stati IUnit 1, thereby satisfying
~
i the raquirements of TMI Action Item !!.K.3.28.
(
3.60.3.7.'I i
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Safety Evaluation Report j
Office of Nuclear Reactor Regulation Equipment Qualification Branch Docket No. 50-458 I
3.11 Environmental Qualification of Electrical Equipment Important to Safety and Safety-Related Mechanical Equipment 3.11.1 Introduction Equipment that is used to perform a necessary safety function must be demon-strated to be capable of maintaining functional operability under all service conditions postulated to occur during its installed Iffe for the time it is required to operate.
This requirement--which is embodied in General Design Criteria (GDC) 1 and 4 of Appendix A and Sections !!!, XI, and XVII of Appen-dix B to 10 CFR 50--is applicable to equipment located inside as well as out-side containment.
More detailed requirements and guidance relating to the methods and procedures for demonstrating this capability for electrical equip-l ment have been set forth in 10 CFR 50.49, " Environmental Qualification of Elec-tric Equipment Important to Safety for Nuclear Power Plants"; NUREG-0588, "In-terim Staff Position on Environmental Qualification of Safety-Related Electrical Equipment, "which supplements the Institute of Electrical and Electronics Engi-l neers (IEEE) Standard 323; and various NRC Regulatory Guides (RGs) and industry standards.
l 3.11.2 Background l
NUREG-0588 was issued in December 1979 to promote a more orderly and systematic implementation of equipment qualification programs by industry and to provide l
guidance to the NRC staff for its use in ongoing licensing reviews.
l l
The positions contained in that report provide guidance on (1) how to establish environmental service conditions, (2) how to select methods that are considered 07/24/85 31 RIVER SEND $$ER SEC 3.11 INPUT
appropriate for qualifying equipment in different areas of the plant, and (3) other areas such as margin, aging, and documentation.
In February 1980, the NRC asked certain near-term OL applicants to review and evaluate the en-vironmental qualification documentation for each item of safety-related elec-trical equipment and to identify the degree to which their qualification pro-grams were in compliance with the staff positions discussed in NUREG-0588.
IE Bulletin 79-018. " Environmental Qualification of Class IE Equipment," issued by the NRC Office of Inspection and Enforcement (IE) on January 14, 1980, and its supplements dated February 29, September 30, and October 24, 1980, estab-lished environmental qualification requirements for operating reactors. This bulletin and its supplements were provided to operating license (OL) applicants for consideration in their reviews.
A final rule on environmental qualification of electrical equipment important to safety for nuclear power plants became effective on February 22, 1983.
This rule, Section 50.49 of 10 CFR 50, specifies the requirements to be met for de-monstrating the environmental qualification of electrical equipment important to safety located in a harsh environment.
In conformance with 10 CFR 50.49, electrical equipment for River Bend Station (RBS), Unit 1 may be qualified according to the criteria specified in Category 1 of NUREG-0588.
The qualification requirements for mechanical equipment are principally con-tained in Appendices A and 8 of 10 CFR 50.
The qualification methods defined in NUREG-0588 can also be applied to mechanical equipment.
To document the degree to which the environmental qualification program complies with the NRC environmental qualification requirements and criteria, the app 11-cant provided equipment qualification information by letters dated March 1, October 19 and December 14, 1984, February 15, March 12 and 15, April 26 Hay 13. June 19, and July 19, 1985, to supplement the information in the FSAR Section 3.11.
The staff has reviewed the adequacy of the R85 environmental qualification pro-gram for electrical equipment important to safety as defined in 10 CFR 50.49 and the program for safety-related mechanical equipment.
The scope of this 07/26/85 3-2 RIVER SEND $$ER SEC 3.11 INPUT
report includes an evaluation of (1) the completeness of the list of systems and equipment to be qualified, (2) the criteria they must meet, (3) the I
environments in which they must function, and (4) the qualification documenta-tion for the equipment.
It is limited to electrical equipment important to safety within the scope of 10 CFR 50.49 and safety-related mechanical equipment.
3.11.3 Staff Evaluation The staff evaluation included an onsite examination of equipment, an audit of qualification documentation, and a review of the applicant's submittats for completeness and acceptability of systems and components, qualification methods, and accident environments. The criteria described in Section 3.11 of the NRC Standard Review Plan (NUREG 0800), Revision 2, in NUREG-0588 Category 1, and f
the requirements in 10 CFR 50.49 form the bases for the staff evaluation, i
The staff performed an audit of the applicant's qualification documentation and insta11ed electrical equipment on January 26, 27, and 28, 1985. The audit con-sisted of a review of 12 files containing information regarding equipment quali-fication. The staff's findings from the audit are discussed in Section 3.11.4.2 of this report.
3.11.3.1 Completeness of Equipment !aportant to Safety 10 CFR 50.49 identifies three categories of electrical equipment that must be qualifted in accordance with the provisions of the rule.
(1) safety-related electrical equipment (equipment relied on to remain func-tional during and following design-basis events).
(2) nonsafety-related electrical equipment whose failure under the postulated environmental conditions could prevent satisfactory accomplishment of the safety functions by the safety-related equipment.
(3) certain post-accident monitoring equipment (R.G. 1.97, Category 1 and 2 post-accident monitoring equipment).
l 07/26/85 33 RIVER BENO 55tR SEC 3.11 INPUT i
- -