ML20133G665

Marked-up Draft Sser 3,including Sections 4 & 7 Re Reactor & Instrumentation & Controls,Respectively

ML20133G665
Person / Time
Site:	River Bend
Issue date:	08/06/1985
From:	Office of Nuclear Reactor Regulation
To:
References
NUDOCS 8508090025
Download: ML20133G665 (175)

Text

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ABSTRACT 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.

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4 REACTOR 4.6 Functional Design of Reactivity Control Systems In FSAR Amendment 20, the applicant provided revised pages in order for the FSAR to conform to the proposed plant Technical Specifications. One of the 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 similar,.poration rates. Therefore, the staff concludes that the revised figur provvided by the July 8th submittal is accept-able. The applicant has also com mitted 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 (G0C) 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).

River Bend SSER 3 4-1

5 REACTOR COOLANT SYSTEM 5.2 Integrity of Reactor Coolant Pressure Boundary 5.2.4 Reactor Coolant Pressure Boundary Inservice Inspection and' Testing

-This section was prepared with the technical assistance of Department of Energy (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 This evaluation supplements conclusions in Section 5.2.4.3 of the SER (NUREG-0989), which addressed the definition of examination requirements and the evaluation of compliance with 10 CFR 50.55a(g). The design of the ASME Code Class 1 and 2 components of the reactor coolant pressure boundary incor-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 detailed requirements for the preservice inspection (PSI) and inservice inspec-tion (ISI) programs for light-water-cooled nuclear power facility components.

On the basis of the construction permit date of March 25, 1977, this section of 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) may meet 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 limita-tions 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 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, the PSI Program through Revision 3 submitted on May 15, 1985, and other letters dated June 10 and June 24, 1985.

The 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 Iton 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 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- ,

l 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

were consistent with the applicable Code and the commercial practices at the time when examinations were performed.

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, 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 technical justification. The staff evaluated the ASME Code-required examina-tions 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 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 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 will be evaluated after the applicable ASME Code edition and addenda can be determined based on 10 CFR 50.55alb), 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 across components, such as heat exchangers, to other water systems, such as the reactor plant component cooling water system, and (2) leakage across passive components, such as across closed isolaAion valves. The applicant has provided means to detect the first type of intertsystem leakage, as was previously dis- -

$ussedintheSER. In FSAR Amendment 21, the applicant has identified a means "

to detect the second type of intersystem leakage, which is also referred to as 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 (GDC) 2,

" Design Basis for Protection Against Natural Phenomena."

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 leakage detection system meets the acceptance criteria of SRP Section 5.2.5.

River Bend SSER 3 5-2

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.f e SAFETY EVALUATION TMI ACTION PLAN II.K.3.28 VERIFY QUALIFICATION .

OF ACCUMULATORS ON ADS VALVES RIVER BEND STATION UNIT 1 ,

DOCKET WO. 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 instrumentation meet the requirements specified in the plant's FSAR and are capable c? 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 nuclear safety related Seismic Category I system.

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1 The realignment from the main steam system air compressors to the'P.VLCS is performed by the plant operators from the main control room.

The PVLCS is manually actuated approximately 20 minutes after a LOCA. Prior l to the manual actuation, the system is in an automatic mode and maintains the i 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 pennit the required actuations during this period, assuming a leakage of 1 SCFH.

ISAR Section 9.3.6.3.1 indicates that the PVLCS accumulators are maintained with er.ough air to meet all short-term requirements of the PVLCS, the MS-PLCS, and l' 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-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 />.

The allowable leakage rate of 1 SCFH for the ADS air accumulator sub-system is l 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.

, 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. ,

4. EVALUATION l

'4.1 The primary source of air for the ADS accumulators is from the non-nuclear safety related main steam system air compressors. Backup to this l system is the nuclear safety related PVLCS. The applicant states that the l PVLCS is placed in service approximately 20 minutes after it has been )

ascertained that a LOCA has occurred. This realignment is accomplished in the i main control room. The 20-minute period is approximately equal to the time 1 required for the PVLCS air compressors to be loaded onto the standby power j

supplies. The applicant has provided a statement verifying that the ADS l 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 l for two actuations at 70 percent of drywell design pressure. This capability 1 3

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 ADS air supply. Therefore, accounting for (a) the

': capacity of the accumulators, (b) that the ECCS is a NSSS (GE) designed i system, and (c) that previous rubmittals 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 takin credit for non-safety related equipment and instrumentation. g no

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.

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-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 applicant requested relief from the testing requirement for the following reasons:

(1) Even though River Bend has a freestanding steel containment, the annulus, 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  ;

containment and internal structures. The resulting response spectra at i 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 may have different effects on the response of the containment structure, compo-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 Kuosheng structure. The response spectra used in the River Bend design based on the General Electric (GE) SRV forcin'g functions provide significant responses 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 examination 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, the final program review with respect to the systems and components subject to PSI examination was evaluated using this submittal. The most significant revisions which have been noted are:

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

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 applicant has demonstrated that either (1) the proposed alternatives would provide an accept-able level of quality and safety or (2) compliance with the requirements would results in hardships or unusual difficulties without a compensating increase in the level of quality and safety. The detailed evaluation supporting this con-clusion is provided in Appendix L to this report. On the basis of granting of relief from these preservice examination requirements and review of the appli-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. This program will be evaluated after the applicable ASME Code edition and addenda can be determined based on 10 CFR 50.55a(b) when inservice inspection commences., but before the first refueling outage f

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1 River Bend SSER 3 6-3

7 INSTRUMENTATION AND CONTROLS 7.2 Reactor 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 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 MOR 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 occurs to circuits on the opposite side of the device). The appli-cant has stated that the MDR 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 MOR 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 MDR 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 testedjsuccessfully -

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 l

J 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 coil 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 dc was applied across 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 i:

l occurs and that there is no insulation resistance breakdown (including carbon traces) upon application of the 1000 V ac.

i 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 i fault will not propagate to the input (coil) side of the device. The staff i considers 115 V ac/15 amps to be the minimum credible fault voltage / current

, acceptable for qualification of components as acceptable isolation devices.

1 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 i (model MDR-4130-1) as installed at River Bend are acceptable isolation devices i for use between redundant safety-related circuits, and between safety-related

[ and non-safety-related circuits.

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! 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-l 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 i tests and 5000-V ac card isolation tests were performed on the optical isolator i assemblies. These tests are discussed below.

j i l The maximum credible voltage / current test was performed for the following input /

i output card pairs:

1 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  :

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High Speed Input /High Speed Output Analog Input / Analog Output i Logic Input /12-V Logic Output l

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4 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 oscilloscope) to detect any perturbations that might occur. The acceptance criteria for all tests was that no fault source voltage 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 /operaoility 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 MDR relays and optical isolator assemblies (models 13309947 and 147D8804) 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 k L -in 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, E and area serviced eiu t G

, p s H:n Cooler Area serviced Cooler Area serviced 1HVC*ACU1A Control room 1HVR*UC5 HPCS pump room Control room IHVR*UC6 RCIC & RHR Division 1 1HVC*ACU1B+

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1HVC*ACU2A Switchgear/ battery / equipment room cable areas 1HVR*UC7 MCC areas i 1HVC*ACU2B, Swichgear/ battery / 1HVR*UC8 Main steam pipe tunnel, l cable areas north {

1HVC*ACU3A, Chiller equipment room 1HVR*UC9 RHR Division 2 equipment

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1HVC*ACU3g. Chiller equipment room area ,

1HVR*UC1A . Containment 1HVR*UC10 MCC areas L 1HVR*UC1B++ Containment 1HVR*UC11A East SGTS area / west l IHVR*UC2 RWCU pump room equipment area i 1HVR*UC3 RPCCW and CRD areas 1HVR*UC11B East SGTS area / west l IHVR*UC4 Auxiliary building equipment area '

general area l

+These air conditioning units start automatically following a LOCA signal l

[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 is running.

++These unit coolers start automatically on a LOCA signal if power is available ,

at the respective emergency buses. _.

}

River Bend SSER 3 7-4

l

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I l

Unit coolers 1HVR*UC2 through 1HVR*UC10 and 1HVR*UC11A&B do not receive auto- l 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-taining engineered safety features (ESF) equipment, the staff raised concerns that the unit coolers did not automatically start in response to system level initiation signals (manual or automatic) for the respective 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-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 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 J

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 verified to be op daily log. in accordance with surveillance required by the control building's daily The operation. areas served by these unit coolers are commonly accessed during plant 4

high differential pressure and high discharge temperature for 1HVC*ACU2A&B.

ture limits for those areas served by all unit coolers listed abov i exception of the containment unit coolers 1HVR*UC1A&B.

The containment unit coolers are provided with discharge temperature indication and low flow alarms-in the main control room.

4

7. 6 Interlock Systems Important to Safety i

' 6.2__Jpecific Findings vg 1 0. 2.1

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7.6.2.5 19h - R essure /Lew-hessure 9 S U"! b %U

Isolation Between Information Systemthe Neutron Monitoring System and Rod Control and The rod pattern control system (RPCS) is a subsystem of the rod action control system (RACS) portian of the rod control and information system (RCIS). The RPCS is a redundant system (Divisions 1 and 2) designed to limit the conse-quences of a rod drop accident by restricting control rod movement (i.e., ini-tiating rod blocks) to within preestablished patterns. The RPCS is powered from the 120-V ac emergency safeguards buses.

located in RACS cabinet 1H13*P651 in the control room.RPCS Division 1 circuitry is

This cabinet also re-ceives inputs from Divisions 1 and 4 of the neutron monitoring system (NMS),

and inputs from non-safety related sources (e.g., the operators' rod control module and the refuel platform). RPCS Division 2 circuitry is located in RACS i cabinet 1H13*P652,sources.

non-safety-related which receives inputs from NMS Divisions 2 and 3 and from NMS Divisions 1 and 3 are powered from reactor

! protection bus B. system (RPS) bus A, and NMS Divisions 2 and 4 are powered from RPS The staff's initial review raised concerns that the isolation provided between the NMS and the RCIS, and between non-safety-related circuits and safety-related circuits within the RACS cabinets may not be sufficient to pre-vent electrical faults from affecting redundant divisional circuits.

The staff has subsequently reviewed all inputs to the RACS cabinets, both safety related and not safety related.

i using optical isolation devices. All inputs to the RACS cabinets are buffered photo transistor type mounted on These devices are the light-emitting diode /

are from the c.ame division (e.g., printed circuit (PC) cards. Where RACS inputs NMS, mode switch, turbine first-stage pressure, rod position multiplexers, buffering is provided. scram discharge instrument volume level), only the '

Where the inputs are from a redundant division (NMS) or from a non-safety-related source, electrical isolation using qualified quartz 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.

i 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. The staff has concluded that the B isolation provided between the NMS and the RCIS is sufficient because (1) in River Bend SSER 3 7-6 m

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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.

7.7 Control Systems l 7.7.2 Specific Findings 7.7.2.1 High-Energy Line Breaks and Consequential Control Systems Failures I i

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 the 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 parameters on loss of power. For those systems that can affect reactor critical parameters, the applicant compiled 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, alarms, 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 considered 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 the 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 l ji es and were excluded from the analysis. High-energy "

lines that are less than Winch 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, I and auxiliary buildings in order to subdivide the plant into HELB zones. Each l zone is a separate area of the plant which is bounded by walls, ceiling, floors, etc., so that the environmental effects of a HELB in a given zone are confined 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 lines identified were then assumed to break at all locations (zones) where the non-safety-related/

control components are located. 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 fail). All component failure modes were considered to determine the worst-case failures 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 l affected zones were considered to fail in their worst states. The sacrificial l approach covers all potential component failure mechanisms (i.e., pipewhip, l jet impingement, humidity, temperature, pressure, and radiation) since this approach assumes that the break will adversely impact all components in the respective zone (s).

l The applicant has analyzed the worst-case combined effects of each HELB and all consequential non-safety-related/ control systems failures. Where the l worst-case failure mode for a component was not readily discernible, all failure

modes and their consequences were analyzed. The consequences of these events 1 -

were then compared with the accident and transient analyses presented in l

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 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 I

considered in the FSAR Chapter 15 analyses. However, subsequent analysis per-formed by the applicant has demonstrated that the effects of this accident event, l including consideration of a single active failure in a mitigating safety system, i

are bounded by the Chapter 15 analyses. The applicant has determined that the combined consequences of all other HELBs 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

t'

! On the basis of a detailed review of the applicant's analysis of HELBs 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 that the methodology applicant used and the results of the analysis performed by the are acceptable.

Table 1.4 of the River Bend SER.This resolves Confirmatory Item 41 as listed in i

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River Bend SSER 3 7-9

8 ELECTRIC POWER SYSTEMS 8.3 Onsite Emergency Power Systems 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 diesel generator qualification test results when they are available. The Division I and II diesel generators are manufactured by Transamerica Delaval, Inc. (TDI).

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 TDI 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 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) 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 machine to 110% of its continuous rating. 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 l

I delivering 3130 kW continuously and load testing should be limited to this 8-1 RIVER BEND SSER 3 SEC 8 08/01/85

E O

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 requirements for accidents and transients as described below. 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 not a TDI unit, it will be tested in accordance with all the requirements of RG 1.108.

With regard to the deenergization of the LPCS or RHR A pump, the applicant has since revised the entire loading profile on the diesel generator units which

~

the staff had originally reviewed. The most recent diesel generator loading for Divisions I and II was submitted by the applicant in FSAR Amendment 21.

The applicant has reduced the loading on Divisions I and II from an original maximum of 3724 kW down to the current maximum of 2886 kW to demonstrate adequate load margin on its TDI diesel generators. The applicant has accom-plished this through a combination of transferring loads (Standby Service Water Pump 2C to Division III), delaying the start of loads, manually deenergizing loads, eliminating loads, and assuming reduced power input to loads. This 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 of 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 the LOCA load profile to shed automatically sequenced loads and load other required 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 Division 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 TDI generic review. The evaluation of these units is covered below in the section titled, " Qualification of TDI Emergency Standby Diesel Generators."

8-2 RIVER BEND SSER 3 SEC 8 08/01/85

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 standby service water pump motor which will be sequenced to operate at 30 seconds after the diesel generator circuit breaker closes. The maximum load on the 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.

InSection8.3.1oftheSE3gitwasstatedthatallClass1EmotorsatRiver 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%.

The staff was concerned that if the 80% figure applied to all Class IE motors, the motors would not be capable of starting during degraded voltage conditions.

This is based on the applicant's March 5, 1984, letter which provided a voltage profile that showed less than 80% starting voltage available to start major Class 1E motors under degraded voltage conditions. In FSAR Amendment 21, the applicant clarified that only the motors driving air compressors ILSV*C3A and ILSV*C3B require 80% voltage to start, and calculations have determined that the minimum starting voltage available at the motor terminals is 89.63%. The remaining Class 1E motors still require only 70% voltage to start. This resolves the staff's concern on this issue and is acceptable. Therefore,

~

Outstanding Issue 22 is closed.

fV3An.! fQ C k 8-3 RIVER BEND SSER 3 SEC 8 08/01/85

I

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SUPPLEMENTAL SAFE Y ALUATION REPORT l

RIVERBEND TION UNIT 1 DOC NO 50-348 M M6 /

43m Rusha%, To 1. wyqDd2 C**~%

--+2 - %roaucdons 4 ,;; -

l Gu1Mtetes1tilitiesiompany @SU) is seeking p ru%W6r 77t.ug /t.a, operating-coneswd den hann lic.eneede- tS ohje- Rond m+4ac Uait-1Mer wl 'ch kee

'sp G oT ie Nnto-the-NRC-staf M as i een the reliability of standby emergency rDI diesel generators (EDGs) manufactured by Transamerica Delava f n.ct<ca w Q & Mj^5%

4at River Bend and other sites.

Concerns regarding the reliability of large7 ore, b medium-speed diesel generators manufactured by TDI for application tk." at domestic nuclear plants werefirstpromptedbyacrankshaftfailureat/Shoreham/inAugust1983.

gin However, a broad pattern of deficiencies in cri,ii " ical lRA *e components 3/rA p he m +1 subsequently became evident gat Shorehamj and at other nuclear and non-These deficiencies nuclear facilities employing TDI diesel generators.

cture fanddonow/ .

QA/QC by TDI. f u 4 b & s gh stem from inadequacies in design, manu y

_ y River Bend St+t4en-Unit-l' is served by two TDI ~-m,,odel DSR-48 diesel engines, c

These EDGs are designated ,;&gancy pacal ganeratoN(EDGsIIA

- a and 18.

inline eight-cylinder, four-cycle, turbocha)ged, aftercooled engines.

J with an overload Each has a nameplate continuous1o7 ad rating of 3500 rating of 3900 /W, and operates at 450 rpm with a brake mean effective pressure (BMEP)of225psig.

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, Q,

\.t _ _ . _.. - A ra ,o '

p Q has been actively involved in the TDI Diesel Generator Owners Group, k ot+Ed 12.

an organization fonned by 3 Stand Mother utilities to resolve reliability issues stemming from the early problems with TDI engines.

E "

ike off With the assistance of the Owners Group,4 Sit 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 t .cin. be/0W -

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- 2.0 s.aweu m =e= ^ , . ,

g,1 ~ TDI Owners Group ^'2 . q . . . . . .

On March 2,1984, the TDI Diesel Generator Owners Group submitted a plan to the NRC which, through a combination of design reviews, quality revalidations, engine testsjand component inspections, is intended to provide an in-depth assessment of the adequacy of the respective utilities' TDI engines to perform their safety-related function.

The Owners Group rogram involves the following two major elements:

N 5 h Phase I: 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 I Owners Group Program.

(h M Phase II: A design review / quality revalidation (DR/QR) of a large setofimportantenginecomponentstofsurethattheirdesignand manufacture neluding specifications, quality controljand quality assurance and operational surveillance and maintenance, are adequate.

~~

The Owners Group Program includes provisions for special or expanded engine tests / inspections, as appropriate, to verify the adequacy of the engines and components to perform their intended functions.

The 16 known problem areas (Phase I issues) identified by the Owners Group include'the engine base and bearing caps, cylinder block, crank-4 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 I issues. These generic reports 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 functional requirements, and provide reconsnendations concerning needed component upgrades, inspections, and testing.

4-The Owners Group has also issued the DR/QR (Phase II) report, Revision 1, dated March 7, 1985, for the River Bend EDGs. This report documents the results of the design review and quality revalidation which was performed on all components critical to the operability and reliability of the engines, including the 16 components identified by the Owners 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.

(/el)

-_ h e Engine Inspections and Tests e e 4 .- .

The engine disassembly and inspection performed in support of the DR/QR effort took place in 1984, p .cr te preoperational testing. The inspec-tions included all Phase I components plus inspection of the engine gears and wrist pin bushings. Other components were included in the inspection, based on operating experience at other plants and reconsnendations of the Owners Group as needed to support Phase II. A sunrnary of the inspections perfonned and the results was enclosed with a letter dated May 17, 1985,

1. -

and was recently updated by letter dated June 21, 1985.

h / )

Ec110 : Sg engine, reassembly, crankshaft deflection measurements, torsio-graph testing, and engine break-in tests were conducted in accordance with NRC staff criteria as identified in Section 4.6, " Interim Basis for Licensing," of the staff's generic evaluation of the Owners Group Program

kW Plan which was enclosed by letter dated August 13 to J. &crge, Owners Group,hh Eisenhut, NRC y &J A description of the preoperational test program of theJBS' engines was

'es 4 W submitted with the letter dated May 17, 1985. Except as noted below, SWd JStf states that the test program was performed in compliance with r m Rephtcry Gu4de.1.108. The preoperational test program did not include E

~ PW d4s *tth 'd a 2-hour overload test pursuant to Section C.2.a(3) of RG 1.108. 65tl justified the sception to the criterion (see letter dated May 15,1985),_a on grounds that a 24-hour test at the manufacturer's continuous rating of FSA6 3500 [W exceeds by.10% the maximum load (3130fW as given in, Figur 8.3-2a and 2b'W) at which the engines would actually be run during emergency ervice. ma a d, therefore, that the 24-hour test at 3500fWmettheintentofthefegulatoryfuide.

At the conclusion of the preoperational test program, an engine inspection not involving major engine disassembly was conducted. This inspection

~

included visual inspection of critical components by removal of access covers and analysis of the engine oil. The inspections and results were documented by letter dated June 21, 1985.

) (l.3) 2.3 Component Replacement and Modifications

- - - u. , , , , ,

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.

n The jacket water pumps were replaced with pumps with a nodular iron impeller without a keyway.

Fuel injection. tubing not meeting acceptance criteria developed by the Owners Group wen replaced.

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(14) 2.4 Qualified Load The ade f attention between 4fzd&quacy of theJB!r crankshaft ' was&~Aa major focus JSrandtheNRCstaff. The crankshafts are similar in design to the replacement crankshafts at Shoreham, which were ,

pproved by the staff for aqualifiedloadof3300fWonthe sis of I cycle test at loads equal W

to or exceedin 00[W. 9tte-to differences t nerators and flywheels between andShoreham,operationoftheJB5'enginesat3130[ produces nominal torsional stresses in the crank ~ hafts s which are comparab at Shoreham at'3300-[W. However, the factor of safety for the BBS' crank-shaft at 3130 W co ld be up to 14% lower exists at Shoreham at 3300 fW due_to a higher tensile strength which 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 lieu of,perfo ing a confirmatory wk I cycle test at that load level on u = engine. Although3130[W is less than the manufacturer's continuous nameplate rating of 3500 /W, it exceeds the maximum emergency service load which would 1 ced on these engines durin an actual design-basis accident (seeg T able 8.3-2 C dLL FSAR). -GSU stated in its letter dated May 17, 1985, that appropriate operating procedures have been prepared to ensure that the 385 engines Kwk Y are not loaded above the " qualified" load. .

l l

Failure Analysis Associates, Inc. (FaAA), a consultant to the Owners Group, has estimated a factor of safety of 1,39 for the crankshaft at 3130 8

.Lu W M W /g gQ andanominalspeedof450%7(6,%letterdatedMay 16,1985). GSt(also submitted a report from its consultant, FEV (Research Society for Energy, 0/ Technology and Internal Combustion Engines) by letter dated June 12, 1985.

FEV calculated a safety factor of 1.205 for the crankshafts at 3130 [

which, according to FEV, is within the range normally

[ and 450 considered adequate by German engine manufacturers. Differences between the FaAA and FIV es_timates were attributed by FEV to the use of different S-N (stress vs. cycles) curves. FEVused(S-Ncurvebasedonbenchtests of actual crankshafts, whereas FaAA, according to FEV, employed a[S-N curve based on 1.eboratory data.

In response to concerns by the NRC staff concerning the proximity of thenominalspeedof450htothe5thorderharmonicresonantspeed 7

ib ) Mrovided additional infonnation from FaAA by letter GSU of 455 ,

dated June 12, 1985, indicating the response to the 5th-order harmonic

~

is small and is excited only by variations in the combustion pressure from cylinder to cylinder. To prevent sustained op "eration under con-4*ffh ditions of engine imbalance and overspeed, y will adopt the following ax Q'eut lu (G W letter dated June 12,1985):

P

_g.

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 5 of the average for all

, cylinders.

Generator-frequency will be monitored and maintained within 60 '

Hz 1 0.2 Hz. gg, g g y Evaluation 'A

&f Enc! :er: [tothis is a Technical Evaluation Report (TER) entitled ff[ " Review and Evaluation of Transamerica Delaval, Inc.j Diesel Engine Reliability and Operability--[ River Bend Station Unit 1." This TER was prepared by Pacific Northwest Laboratory (PNL) which is under contract (ff to the NRC to perform technical evaluations of the TDI Owners Group generic program, in addition to plant , specific evaluations relating to I the reliability of TDI diesel s retained the services of several expert diesel consultants as part of its review staff.

The staff concurs with the findings of the PNL TER, and incorporates  !

SEK Q&

the TER as part of this S:'ety ...lecti:n 4 rt by reference, l

at

This W and the eAlend 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 com letion of the NRC staff review Euda of the total DR/QR program atJMMIis anticipated by the first refueling outage. However, the staff and its PNL. consultants find that these reviews M

have progressed,sufficiently pe# that all significant issues warranting i ention as a basis for issuance of an operating license for JSSI have been resolved.

'( 2 1) h4 Engine Tests and Inspections PNL's review of the engin,e test'and inspection program at RBS is provided F1*

in Section 4 of th anclacad MR. 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 6.4 finds that component upgrades at were responsive to the Owners Group recommendations.

e The NRC staff concurs with these findings and notes the following:

• N Detailed disassembly and inspection of the 389 engines as part of

')

A W the DR/QR effort were perfomed prier 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 which called for such inspections to take place s s ;c ttr preoperational testing. The staff. considers the h to be acceptable,on e

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 part of the design review process of the DR/QR program. A major P?

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.

Preoperational testing was performed for engine loads ranging to the full manufacturer's continuous rating of 3500 [W. Because this exceedsthequalifiedloadrating(3130fW)ofthe .

a crankshafts ,

the staff was concerned about the potential for inducing cracks in

the crankshafts during the preoperational testing. At the staff's request, d 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 of fatigue crack initiation (see Section 5.3.5 of e E).'

$W 1 The exception taken by JStf against perfonning the twe-hour overload fos W @ ~ $(r .

test in act.ced:nce with Secticr.-C.2.a(3) of " g i tcry Guie 1.108 is acceptab1Itothestaff. The 3500- 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 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.

i N

&A Component Problem Identification and Resolution t M g Y."

Section 5 of sed TE" qv3,g.g PNL's review offW1 actions to upgrade and/or qualify the 16 engine components known to have had significant problems (Phase I components). The PNL evaluation also considered the pertinent Owners Group Phase I 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 reconnendations regarding needed component upgrades, inspections, and testing.

k1bs.

Based-tmYthis Yevaluation, the NRC staff and PNL have concluded that each

%M ofthePhaseIcomponentsinthe)BTenginesisadequatetoperformits intended function at a " qualified" load rating of 3130 fW. This finding is subject to implementution of an table en emain(enanceand g ,1].

surveillanceprogramasidentifiedhSecyon .:"+'

bss ***

p M With respect to crankshafts, PNL has concluded in Section 5.3.5.3 of h WM enc' : d eepart that the FaAA and FEV analyses substantiate the adequacy ofthecrankshaftsforoperationto3130f.AsnotedbyPNL, extensive testing e reham engines and the absence of any evidence of cracks intheRyfSD1Acrankshaftfollowingpreoperationaltestingprovide

. MM additionalevidenceoftheadequacyoftheJWcrankshafts. On this basis, the staff concludes that a confinnatory test for 1 cycles is not needed to support 3130 W as the qualified load of the y engines.

w

(? i h 4:t Resolution of Open Issues Identified by PNL N' t a c;p4, In Section 5.0 of th: : :.000. "L PNL reconinended implementation M

~

of the following actions pertaining to Phase I components ;Mer te h;;,; .;: Of- an operating license:

.5W

cal,I eractien ef The idler gear on SD 1A A I

(o

m. .

(/J / reload torque on all connecting rod bolts should be verified to be in accordance with TDI reconsnendations,

(C) vieim1 4 ;p;; tion ;heg1rl be nMe-d =

---~ e turbocharger bearinas p k w. -g. sg pf and nozzle ring of SD 18 and Set a 17 quid penetrant testgbe A

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.

- cd) ,

@ Replacement jacket wate(pumps with modifications recomended by the Owners Group should be installed.

e)'

Owners Group-recomended inspections of replacement jacket waterO v

pump to be installed on SD 1A should be compig c

If cotter pin holes do not line up at the specified torque, the nut washer or nut should be. reduced in thickness until the pin holes do match.

I- )

@ Fuel-oil injection tubing which did not meet Owners Group acceptance criteria should be replaced with acceptable tubing.

Subsequent to preparation off:::1;;cd t..:

M UW N" rep;, t, SSU submitted an updated inspection r rt by letter dated June 21, 1985. ";; d r :

667At M 4 A ik W review of submittal, the staff concludes that each of the 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 M/

JStf e ected to replace th=== haari p.

15 - **

WN i In Section 5.7.5 of the en;'s: d ML = port, PNL reconnended 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. Hcwever, PNL concluded that these inspections

.C.aAld.A could be delayed until the first major engine overhaul or jwhen the pistons

[ become available for inspection prkr th:=te. This item corresponds to an Owners Group reconnendation, yet it appears to the staff to have been omitted yw -

from a computerized listing of the status relative to each Owners Group ree,ommendation which was provided to the staff by letter dated May 3, ud &

1985, with en updated letter d:t:1 June 26,1985. Although not an innediate issue with res et to issuance of an operating license, the *

k. MW N

'cd staff will require that dress this issueY' p&r&. r, te k =:nce fg o

.s.ta W s final evaluation of the'DR/QR ro ram at afMk The staff will  ?

M also require at that time, that y ave completed a QA check to verify the completeness and accuracy of tracking system, implementing, and r

procedural documents relating to the implementation of all Owners G.gou MW 1$2 W reconnendations in Appendix I of the DR/QR report. ,SStf S in bry rAn. AWMN exception to an Owners Group reconnendation, tMs sh uld be r; ported tv-N f th appropriate justificationg MN '

b,O tlIr 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 and operability of TDI

MM engines. W has agreed to implement the M/S program identified in f{u1j %2 %

Appendix II of the RBS DR/QR Report, Revision 1 (see SStf ietter dated May17,1985). Appendix II of the DR/QR Report presents a schedule of M/ e recommended by the Owners Groups for implementation at SB5".

. $hW N Y

- ":::d es its evaluation of Appendix II, PNL has made a number of M,

recomendations which are identified in Section 6 of t..:g:::1;;ed 7tE i ye. L. These-recournendations address the maintenance items, operational surveillance, and standby surveillance. PNL notes that its RitmBwcf recomendations are intended to augment the M/S plan forJ9ff rather than to supplant it.

By letter dated July 29,1985,JSt! committed to incorporate the P,NL recomendations into its M/S program by August 30, 1985, with the excep ' pt .

Q:ksed tion of some of the PNL recommendations shown in Table 6.3 of t..: er PNLraert. 45Ufas p#roposed a dised table shown ast. Table 1 of this 3

. The proposed changes include deletions of PNL recomendations to perform a visual check every hours of starting air pressure, lube oil temperature, jacket water temperature, lube oil sump level)and fuel oil

&QM day-tank level. JSt! would continue to log each of these parameters every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> as recomended by PNLy MW

'dith the eEgth: that only, inlet (rather than inlet and outlet) temperatures would be logged for lube oil temperature. Furthermore, e ch of the subject parameters has an associated 9 db g, 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 recomended by PNL. It is the staff's overall

d.e b judgment thatKs proposal will not result in a significant reduction Mh in the effectiveness of the 395' standby surveillance program, and is therefore, acceptable, hY g At the NRC staff's request,galso consnitted to incorporat4*g- the following items into its M/S program by August 30, 1985:

&qv;J (a) j,k) /perational and surveillance practices identified in.GSU5 let dated Jung,12, 1985, concerning the monitoring of engine speed, exhaust gas temperatures, and generator frequency g (D 9p,Ja k

@) fdditional PNL M/S reconsnendations discussed in Section 5 of the-

-er.ch:;;d '"il r;prt and listed below:

0b

• idler gear assembly [0wners Group reconsnendation to clean h) idler gear and hub ating surfaces should be incorporated

& if fW' into the JSS' maintenance and surveillance program if3 not e m. This item was not included in the Appendix already II sungnary of the DR/QR report, although it was identified in Appendix I.

( 149 , h h idler gear assemblyk GStf should verify that proper torque specifications are incorporated into the maintenance /

surveillance program. There appears to be a discrepancy g -go oS between Appendix I (80 20 ft - Jg b) and Appendix II p .90 (70 20 f t - ) of the DR/QR report. #

V L

~

~

^

([Il ,

push rodsM For future purchases of push rods, Mshould h *'

perform destructive verification of weld quality by sectioning random samples from each manufacturing lot.

Finally, the has also agreed to perfonn a QA check of implementing and procedural documents pertaining to the maintenance and surveillance program to ensure the complateness and accuracy of these documents g relative to the.reconmandations of the Owners Groups and PNL. JMi will complete this check by August 30, 1985.

g 4(a M f g

,Jed ei,- the above, the staff concludes that the GS3 M/S program for engines 1A and IB at RBS is acceptable. Furthermore, the staff finds that no

[ exception to GDC k7willbeneededtosupportissuanceofalicensefor i fuel load pM .a te completion of the afo,reme tioned actions by August 30, W AW 1985. This is.i te the f:d th:t GSU has completed a comprehensive i program of engine inspections, testing, and component upgrades which ensure that the engines are in a good and operable condition. The i

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 l l

and reliable condition over the life of the plant.  !

l It is reasonable to. expect that certain changes to the M/S program may become appropriate in the future based on operating experience. The staff will require that any changes to the M/S program be subject

9 to the provisions of 10 CFR 50.59. In addition, NRC staff /PNL 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:

.. b)

O Crankshafts shall be inspe;'ed as follows:

SD 1B: 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 Y"currentasappropriate.

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 mentioned.

4 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 e t and eddy current as appropriate. This inspection is 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)

tr in 'f report entitled Design Review of TDI R-4 Series Emergency Diese' 3

Generator Cylinder f Blocks"(FaAA 9-11.1)) dated December 1984.

WY t innid retra-tInspect cylinder liner loading area 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)

~

.>- Ed M The Ishall roll the engines over with the air-stare system y 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 oNr 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 W expiration of the e@8~ hour or 24-hour periods noted pe4eM.o above, that engine need not be rolled over while it is out of service. Once the engine is returned to service, the lice s p'd 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. .

(LsT J6 Additional Reporting Requirements Except as noted below, the staff is not imposin ad,di al reporting requirementspertainingtotheTDIdiesel[at yond what is already 10 CF(L 10 CP K. 10 CF%

required in the regulations (e.g.,-Ferts 21,50.72,and50.73),andby 7 3

the plant Technical Specifications. The exceptions involve any cracks which may be found in the crankshaft or in the engine block between stud holes of adjacent cylinders. Either of these unexpected situations could involve a potentially serious concern regarding the future oper- $

ability of theangioe. In these cases, the staff will require by condition of the license that any proposed resolution be approved by the h

(

u .

NRC staff pe &fer to returning the engine to an " operable" status. g i g, T "o

(? , b ) $E

. i>r6 Load Restriction Requirements E ,! E m a The plant Technical Specifications will limit surveillance testing of c e "o 7 p plaaf Tec4m'cas %gh j 5 5

$ f, 'g engines IA and IB pursuant to,Section 4.8.1.1.2 to within a lead range 3 g ,c of3030/Wto3130[Wconsistentwiththequalifiedloadratingofthe ($ ", ,$

E engines, o  ; y I { '%E 9 v, s c e Engine operating procedures, operator training, alarms, etc., to $[

e %

minimize the potential for overloading the engines beyond 3130 5 i % [i 2

W U 3'l B g ,g areaddressedinthenextsectionofthisJECThestaffwil( require j g that the following actions be perfonned in the eventgthat the engines 9 should be operated in excess of an indicated 3130 WW:

a .

e "a h 5 d Y Jt7 Momentary transients (not exceeding 5 seconds)(ze te changing need not be considered as an overload.

For indicated engine loads in the range of 3130)di to 3200 )d for m 1 aperiodlessthantwerhours%,noadditionalactionshallbe required.

For indicated engine loads in the range of 3130 to 3200)d for a 1

lb period equal to or exceeding twe hours fM,acrankshaftinspection

,, pursuantto[ tem elow)shall be perfonned at the next refueling outage.

(C} _ , , , _

For indicated engine loads in the range of 3200 )dl to 3500)$ for a p 4 period less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> , a crankshaft inspection pursuant to itemff helow)shallbeperformedfortheaffectedengineatthenext refueling outage.

For indicated engine loads in the range of 3200[ to 3500 /dfor L mt , and for engine loads periods equal to or exceeding one hour os exceeding 3500 for any period of time ,(2) the engine shall be

- I h removed from service as soon as safely possible, (2) the engine 0,

shall be declared inoperable, and (f) the crankshaft shall be inspected. The crankshaft inspection shall include crankpin journal numbers 5, 6, and 7 (the most heavily loaded)) and the two main journals in between using fluorescent liquid penetrant and eddy N

currentgas appropriate.

Y 6if there are multiple overload events within a given load range) criterion appliesg l

1 I

W Ms In Section 2.0 of the e-lacad TE", PNL has recommended that fast starts be limited to the number consistent with NRC requirements in. order to I l

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 M* 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-engire prelube period and/or other warmup procedures recommended by the manufacturer.

De .

'4,7 Operating Procedures gM In a3 NRC staff letter dated July 23, 1985 GB0 was m = ned 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:

i b I h No single operator error should cause the loading of more than ore 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.

M If) d The training program should adequately address the technical concerns associated with the qualified load limit on the TDI EDGs.

f;l)

@ If a situation were to occur that would, for some unspecified failure, cause the EDG to exceed the qualified load, the procedures and training should provide the necessary guidance to reduce the load below the l L

qualified load within one. hour.

h Distinctive and unique instrumentation and alanns should be -

installed to warn operators when the engines are loaded above '

the qualified load.

ph . . . ,

JStIhas agreed by letter dated July 29, 1985j to review its procedures and to make any necessary cha es prigr to-plant W -

M criticality p0rsuant to e above criteria. G,JR urther noted that i M j[#^ instrumentation and a with a distinctive sound have already been

, (Qu,1{d &. Y (lp.^ .?

installed to warn operators if the engine loads % exceed fwv.A 3130

~.

= kw. "::cd-ktheseactions,thestaffconcludesthattheBBS'operatingprocedures for the TDI engines will provide the appropriate guidance and instruction to operators.

(3) .

-+:6 Conclusions J q This the en & : evaluation precede final completion of the s

l NRC/PNL review of the proposed generic resolution of the Owners Group Phase I issues and of the total DR/0R program at River Bend. The NRC staff and PNL conclude that these reviews have progressed sufficiently /

, s that all significant issues warranting priority attention as a th basis for issuance of an operating license for River Bend have been ,

adequately resolved.

r

Accordingly, the NRC staff concludes that the TDI diesel generators Oud5 M atKwill provide a reliable standby source of onsite power in GbC-accordance with Geae-M Desir CH+=rinn 17. This finding is subject ,

831(1'0 n l~ %

j.d ? to (1) license conditions identified in Section Mof this SSER pertaining to the engine maintenance /surveill n (M S) rogram,(2)special 3,6 reporting requirements identified in Section &rs, (3) 1 pad g,3 1 ( 1 restriction requirements as identified in Section 3,4, and 4) a license g

condition making operation beyond the first refueling outage subject to NRC staff appro9a1 -based on the staff's final review of the Owners Group generic findings and of the overall Q ggt River Bend. This finding is also based in part upon JStf conunitments in its letter dated July 29, 1985j to complete the following actions:

9t.,3' (1) Incorporate additional ite identified in ection ft into the M/S program for EDGs 1A and IB by August 30,1985g (2) Perform QA check to ensure completeness and accuracy of implementation and procedural documents relating to t,he {S prqgram for EDGs 1A and t s.m.w- ,f 1B by August 30, 1985 see Section 4,4 of this SSER).

(3) Review and revise as nec,essary E G 1A and IB operating procedures as y.>.rp.

described in CSection 3.7 of this S ER, p@r,m- te plant criticality.

8.3.2 DC 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 editorial 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.

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 protection. In a letter dated July 24, 1985, the applicant provided the setpoint calculations for the first and second levels of undervoltage protection. The setpoints for the Division I and II vital buses are 2970 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 a4.s-Division III vital bus ps 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.

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

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 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 Division III bus from the offsite power system.

The second delay is approximately 60 seconds. After this delay, if the operator has failed to restore adequate voltages, the Class 1E system is automatically separated from the offsite power 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-of-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, therefore, acceptable. Therefore, Confirmatory Item 46 is closed.

(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.

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 8-5 RIVER BEND SSER 3 SEC 8 08/01/85 l

leads used on differential protection circuits, and trip coil circuits in circuit breakers. In a letter dated July 24, 1985, the applicant provided justification for the lack of protection on these circuits. The current transformer leads on differential protection circuits are acceptable because a high current exists on these circuits only momentarily when a fault is sensed An open circuit and is quickly cleared by the differential protection circuit.

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-voltage. The lack of redundant protection on trip coil circuits is acceptable because these circuits are fed from an ungrounded 125-V dc power supply, and the portion of the circuit passing through the penetration is confined to only The only type of failure one leg (positive or negative) of the power supply.

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 dc 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 low-voltage control circuits which are deenergized during plant operation.

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.

The other remaining electrical penetration revi-provisions are acceptable.

sions made in FSAR Amendments 19 and 20 have been reviewed and are als acceptable. Therefore, Confirmatory Item 71 is closed.

8-6 RIVER BEND SSER 3 SEC 8 08/01/85

8.4.5 Physical Identification and Independence of Redundant Safety-Related Electrical Systems 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 IE ladder-type trays except where the cables exit from the subject tray. This statement was based on a similar statement in FSAR Chapter 8. FSAR Amendment 20 has subsequently deleted this statement. The staff has reviewed the separation details for these circuits contained in River Bend drawings 12210-EE-34ZE-7 and 12210-EE-34ZH-6 and finds that they comply with the requirements of IEEE Std. 384 and RG 1.75 and are, therefore, acceptable.

In a previous supplement (SSER 2), the staff evaluated the use of red- and blue-colored jacketed cables in unscheduled non-Class IE circuits (these colored cables are normally only used to identify Class IE circuits), and found them acceptable with the restrictions outlined in FSAR Amendment 16. FSARAmendmentC 20 has added additional categories where these cables are used. These are in 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 locations, and no safety-related circuits are installed in direct-burial cable trenches. The staff finds that these exceptions to cable color coding will not decrease the effectiveness of the color-coding system used at River Bend and are, therefore, acceptable.

8.4.6 Non fety Loads on Emergency Sources In SSER 2 the staff stated a need to review the applicant's evaluation with regard to the acceptability of non-Class IE slide wire transducers and limit switches. In a letter dated July 5, 1985, the applicant provided its evalua-tion. For the slide wire transducers, a qualified resistor limits the avail-able fault current to a small value which has no detrimental effect on the Class 1E power supply should a short or ground occur on the unqualified trans-ducer, For the limit switches, a short or a ground on tho limit switch is the same as if the switch were closed, which also has no detrimental effect on the 8-7 RIVER BEND SSER 3 SEC 8 08/01/85

Class 1E power supply. Both the slide wire transducer and limit switch circuits as designed are, therefore, acceptable.

In FSAR Amendment 20, the applicant added non-Class 1E motor heaters to the list of non-Class 1E loads powered from Class IE power supplies. ~ The motor heaters are powered from a Class IE 120-V panelboard. There is a single Class 1E 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 1E 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.

Section 3/4.8.4.4 of the River Bend Technical Specifications requires that upon installation of the second overcurrent protective device, the circuit breakers in the circuit be listed in the Technical Specifications and they be periodic-ally tested. With these provisions, the staff finds this item acceptable.

Therefore, Confirmatory Item 49 is closed.

8-8 RIVER BEND SSER 3 SEC 8 08/01/85

1

. l I'

4

(

i 9 AUXILIARY SYSTEMS 9.2 Water Systems

-9.2.5 Ultimate Heat Sink

! In FSAR Amendment 16, the applicant identified a reduction of the diesel gen-erator loading resulting from delayed starting of the ultimate heat sink (VHS) 4 fans based on the ultimate water temperature rise in the UHS basin. In order i 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 l 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 i

July 18, 1985, the applicant committed to provide the design of the temperature j monitoring system for staff review and approval before its installation.

i

! As an interim measure, the applicant has committed to manually taking daily i 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-l 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.

1 On the basis of its review, the staff concludes that the UHS design is accept-l 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.

i' (2) The applicant will have installed the temperature-monitoring system and proposed modification to the Technical Specifications (both to delete the i interim Technical Specifications and to incorporate the new design into i the Technical Specifications) before startup after the first refueling i outage, l

i 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 i hypochlorite feed.Lgg the recirculation system. In the submittal dated July 18,

{ 9dC 198 E Y.he applicant stated that the hypochlorite feeding system is designed to J

control organic growth in the UHS. A concentration level of 3.0 to 5.0 ppm of l 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 1

i i*

}

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 i for the piping near the standby service water pumps. The hypochlorite system i 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 i not adversely affect the UHS or the standby service water system. .Thus the i 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.

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 l l ~

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-l mencement of the 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-I temperature-monitoring system, the license condition, the installation of a l seismic Category I, Class 1E, basin water temperature monitoring system by the i

first refueling outage, and the interim measurcs, the staff concludes that j manual initiation of the UHS fans before basin water temperature reaches 82'F ,

1 is acceptable. Therefore the requirements of GDC 44, " Cooling Water," as j related to the ability of the UHS to accept the heat rejected by the plant, i 1 are satisfied.

On the basis of the above evaluation, the staff concludes that the UHS meets I GDC 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.

I 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 D SSWS 4 pumps in the B loop are powered from the Division II diesel generator. In i

FSAR Amendment 16, the applicant removed the C SSWS pump and the associated i instrumentation and controls from the Division I diesel generator and proposed i powering it only from the Division III (HPCS) diesel generator. Thus the C '

i SSWS pump only operates when the Division III diesel generator operates.

I j The applicant provided a failure modes and effects analysis which demonstrates l i the ability of the SSWS to withstand any single failure and provide sufficient ,

l 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. l J

! In its SER, the staff also stated that each SSWS pump was capable of handling l 50% of the cooling water for design-basis accidents and, therefore, only two River Bend SSER 3 9-2 l

'pc h f

. pumps were needed for safe shutdown. Althoughthesepym/e ps are rated as 50%

for design-basis accidents, whose the single failure ih the Division III (HPCS) diesel generator sthree pumps are needed for a safe shutdown. This is accept-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 cvailable.

Each SSWS loop returns the cooling water to the ultimate heat sink, which is a 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 to an area of the cooling tower which is served by the Division I powered fans. A crosstie between the redundant loops enables the A and C SSWS pumps to supply water to the components and systems which would normally be serviced by the B 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 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 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 operable SSWS pumps and the cooling tower fans, the staff concludes that the standby service water system meets GDC 44, as related to the capability of transferring heat loads from safety-related components to the ultimate heat sink under emergency conditions including a single active failure, and is, therefore, acceptable.

9.3 Process Auxiliaries 9.3.3 Equipment and Floor Drainage Systems In its SER, the staff stated that the floor drains were pumped from the ECCS 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 service water system; the standby gas treatment system; the floor drains in g' gg the auxiliary building crescent area at elevation 7Q; some unit coolers; MSIV positive leakage control system; HVAC systems for the reactor, auxiliary, turbine, and containment buildings; some compressor / dryer systems; some fire protection sprinkler drains; and miscellaneous area floor drains for such 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.

River Bend SSER 3 9-3

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- {

I lation valves, and level-detection instrumentation are seismic Category I and l 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, j 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 i air-operated valves to the radwaste system. The air-operated valves are fail- l closed valves which prevent inadvertent pumping to the radwaste system during l 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

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 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-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 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 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 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 and II diesel generators operating, one 50%-capacity water chiller would be 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 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. l

~

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.

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 building HVAC systems, as follows:

(7) motor generator building (heating and ventilation system)

(8) demineralized water pumphouse (heating and ventilation system)

River Bend SSER 3 9-5

(9) circulating water pumphouse and switchgear room (heating and ventilation system)

(10) cooling tower switchgear 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 requirements 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

(53e g w prrachment 1

. Chemical Engineering Bra Fire Protection Section Supplemental Safe y Evaluation Report River Bend 5 ation Unit No. 1

{/ Docke 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 9B 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 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.S.a (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 s or at the first opening on both sides of the barrier regardless of 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 performance 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.

Following the fire exposure, tha 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 sill provide an (quivalent level of protection to' that

achieved by compliance with Section C.5.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.S.a.(3).

In our SER we stated that radiation shielding materials are non-combustible and met Section C.S.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 1/2 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 safe 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.S.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 building 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 service water. In the event that pumps ISWP*28, 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 price to exceeding 5 percent of rated power. Wo find this dtwiation ac eptable.

B. Fire Protection of Safe Shutdown Capability 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 require repairs. For a fire in the main control room, air compressor ILSV*C3A may have to be started by use of jumpers at standby motor control center IEHS*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 compressor will not need to be jump started until well into the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, if at 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 1EHS*MCC26, in order to permit operation of the RHR in the shutdown cooling mode.

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 committed to maintain the materials for these repairs onsite and in a separate fire area and to have procedures in effect to implement these repairs.

Based on the applicant's commitments, the limited number of repairs, and the anticipated amount of time available to make the repairs, we conclude that the repairs to achieve and maintain cold shutdown are acceptable.

During the site audit, we observed that area-wide automatic fire suppression was not provided in the following areas:

ET Electrical Tunnel PT Pipe Tunnel AB Auxiliary Building Piping and Electrical Tunnel C-2A - Control Building Cable Chases C Control Building Cable Chases C-2C - Control Building Cable Chases C Control Building, Elev. 70 Each of these areas is equipped with an area-wide fire detection system; a cable-tray fire suppression system; portable fire extinguishers; manual hose stations; and a 1-hour fire rated barrier around one shutdown division. If a fire were to occur in any of the areas, it would be detected in its early stages by the fire detection system. The fire brigade would then extinguish the fire. If room temperatures rose significantly, the cable-tray sprinkler system would activate. Water from this system would protect vulnerable cables and would limit fire spread. During the time celay between the advent of a fire and its eventual control, damage would be confined to this area by the fire-rated perimeter construction. Also, because one shutdown division is protected by a fire barrier, there is reasonable assurance r 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 in the above areas is an acceptable deviation from Section C.S.b of BTP CMER 9.5-1.

t ,

, C. Alternate Shutdown Capability ,

l The lighting for the control room.and the remote shutdown panel area are l 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 connitted to perform all operator actions which I

are not perf ormed in the main control roon or at the remote shutdown panel area within eicht hours. The only exception is the operation or repair of volve 1LiL*F009 an RHR isolation valve. The operation of this valve is t.ct necessary until approaching cold shutdown. The

- guidelines identified the neeo to be able to be in colc shutecwr in 7L hours, thus this valve neec not be operated for approximately CL hcers after the fire. This is sufficient time for the operators to l use portable lights, as necessary, to locate and operate the valve.

Therefore, we conclude that operation of valve 1Eli*F009 after the eight hours of emergency lighting is acceptable, in a submittal dated July 19, 1985, the applicant stated that all circuits necessary for alternate shutdown from outside of the control room are in compliance with the guidelines of I & E Bulletin 85-09. Compliance 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 guidclines of I & E Bulletin 85-09 and cn the applicent'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 6pplicant 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 modificetions 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 L.5.6 with respect to alternate shutdown prior to exceeding 5 percent power. Based on the alternate shutdown not being ava11(ble in the event of a fire in the nuin control roon, we require that a condition be placed on the license, as follows:

l

. The applicant shall complete all modificat' ions 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, prior to exceeding 5 percent of rated power. ,

The applicant has comunitted to station e continuous fire watch in the control room at core load until the alternate shutdown system is fully completed and operational.

Opt. ration of the plant up to 5 percent or rated power will not involvo significant fission product inventory; therefore, the risk to the health als safety of the public is not incrt.ased. Moreover, because the applicer.t h65 cot.111tted to station a contiruces fire watch in the control room, we fino that adequate interin fire protection measures have been provideo.

Therefore, the applicant's request for deviation from our guidelines

~

should be granted. The alternate shutdown system for the control room should be completed prior to exceeding the 5 percent power milestone.

VI. Fire Detection and Suppression ,

A Fire Detection In our 5ER we stated that the fire detection system is designed in accordance with NFPA 720 " Standard for the Installation, Mainten-ance, and Use of Proprietary Protective Signaling Systems." Informa-tion was not available during one site visit to verify this requirement.

, By letter dated June 28, 1985, the applicant verifiea that the system had been tested and found acceptable for listing by underwriters Laboratories, Inc. We find this acceptable.

B. Fire protection Water Supply System In our SER we stated that the fire pumg installation was designed and installed in accordance with NFPA 20 Standard for the Installation of Centrifugal Fire Pumps." During our site audit, we observed that butterfly valves were installed in the suction lines to the fire pumps.

The use of butterfly valves in fire pump suction lines is not in accordance with NFPA 20. The applicant verbally cosmitted to replace the butterfly valves with approved OS&Y valves. By letter dated June 28, 1985, the applicant informed us that all of the butterfly valves l

installed in the fire punip suction lines were replaced with 058Y valves l 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 puro, the fire protection watt.r supply system has a hydro-pneuteetic tant to maintain system pressure. In fact, the system does not have such a tank. We find that the fire service jockey purip along is adequate to maintain pressure in the fire protection water supply bystou and reet the guidelines. Therefore, we find that the use of o tire service jockey puy withet e hydro-pneuntic t.m6 is ct'rtpdit..

k

l-l -b-l l

In our SER we also stated that the water supply for fire protection is taken from two 265,000-gallon water storage tanks and found the size of these tanks to be an acceptable deviat'on from the guidelines of I Section C.6.b(11) of BTP CMEB 9.5-1 n.; ich requires a minimum capacity l 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

! sprinkler or deluge system deraand of 1400 9pm plus 500 gpm for hose streams for two hours with 6 raorgin of 13,000 gallons. In addition, the tanks are filleo automatically by the shallw ull trakeup pump at a rate of 800 grr s,hcr. the water level talls i f ut bolw the overflow level. Based en the ave 11able water capacity uno the outcrietic makeup, we find the existing tanks tu be on acceptable denotion from the guide-lines of Section C.0.b(11) 01 b1P CMEB 9.5.1.

l C. Sprinkler and Stand Pipe Systems In our SER we stated that manual hose stations ate located throughuut the plant in accoroance with NFPA 14. " Standard for the Insth11ation 1 of Standpipe and Hose Systems," and that, with the eu.eption of the '

electiital tunnel, all areas of the plant can Le reached with an effective hose streura with a r:eximum of 75 feet of hose. In the l electrical tunnel, we concludcd that the applicant demonstrated that adequate flow and pressure is availabic from the water supply systen if 150 feet of hose is used. By letters dated hay 1"/, 1905, and July 26, 1985, tho appitcant identified seven additional areas where

! 150 feet of hoso is used.

1he plant water distribution system is capable of supplying hose streams '

tr. t1ese areas with adequate quantity of water and pressure through 150 f eet of hose. In addition, sufficient space is availabic in each of l

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 Ictter is an acceptable deviation frota Section C.6.c of BTP CMEB 9.5-1.

Vll. Fire Protection for Specific Plant Areas D. Switchucar Rooms During our site audit we observed that curbs were but it. stalled to prevent water from flowing between the Division 1 and Division 2 switchgear rooms. By letter dated June ib.1985, the applicant infonned us that curbs hoc Lun installed between Fire Areas C-14 and C-15 to prevent water flow between the Centrol Building switch-gear rooms. We find this acceptable.

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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. SealingInsideConduits(SectionV.A)

2. Steel Plate Enclosed Combustible Radiation Shielding (Section V.A) '

l 3. Non-labeled Fire Doors (Section V.A) l 4. Lack of Area-wide Fire Suppression Systems (Section V.8)

! 5. Use of Water Curtains to Separate Fire Areas (Section V.P) l 6. Fire kater Supply Tank Size (Section VI.P) l

7. Fire Hose Stations 111th 150 Feet of Hose (Section VI.C) 1

8. Carpet in the Control Room (Section ill.L, Based on our evaluation, we find that the applicant's fire protection i program with approved deviations is in conformance with the guidelines

of BTP CMEB 9.5-1, Sections 111.0, III.J and 111.0 of Appendix R to [

l 10 CFR 50, and GDC 3 and is, therefore, acceptable. '

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Attachment 2 River Bend Station Unit 1 i 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 l Analysis Report for the facility (or as described in submittals dated l ----------) and as approved in the SER dated ---------(and Supplements

dated ----------) subject to provisions 2, 3, 4, 5, and 6 below.  ;

l 2. The licensee may make no change to the approved fire protection program l

which would significantly decrease the level of fire protection in the t

! plant without prior approval of the Commission. To make such a change  !

~

.. the licensee must submit an application for license amendment pursuant i to 10 CFR 50.90.

i

3. The licensee may make changes to features of the approved fire protection j program which do not significantly decrease the level of fire protection  !

without prior Comission approval provided (a) such changes do not t otherwise involve a change in a license condition or technical I l

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 i fire protection program approved by the Commission prior to license issuance. The licensee shall maintain, in an auditable form, a current l record of all such changes, including an analysis of the effects of the chanpe on the fire protection program, and shall make such records l avai able to NRC inspectors upon request. All changes to the approved I program shall be reported annually to the Director of the Office of l Nuclear Reactor Regulation, along with the FSAR revisions required by  :

10 CFR 50.71(e). l

, 4. Prior to exceeding five wrcent of rated power. Gulf States Utilities Company shall complete tte fire wrapping of electrical raceways in l the Control Butiding, j

5. Prior to exceeding five percent of rated power, Gulf States Utilities  !

Company shall complete the fire wrapping of electrical raceways in the l Fuel Building. I

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 j room, from outside of the control room, including revision of the plant  :

procedures and re-training of the operators. [

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l 13 CONDUCT OF OPERATIONS 13.5 Station Administrative Procedures 13.5.2 Operating, Maintenance, and Other Procedures l 13.5.2.2 Operating and Maintenance Procedures Program In Section 13.5.2.2 of SER, the staff described the review and approval of the applicant's operating and maintenance procedures program through FSAR Amend-ment 11. The applicant transmitted FSAR Amendments 16 and 20, which included

, the applicant's changes to FSAR Section 13.5, " Procedures." The staff reviewed these changes and determined that the applicant's operating and maintenance

! procedures program continues to meet the relevant requirements of 10 CFR 50.34, j and remains consistent with Regulatory Guide (RG) 1.33, ANSI N18.7-1976/ANS 1

I 3.2, and SRP Section 13.5.2, " Operating and Maintenance Procedures." ,

13.5.2.3 Reanalysis of Transients and /necidents; Development of Emergency l Operating Procedures

), $ -

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 l and justification of safety-significant differences between the River Bend

! plant-specific technical guidelines and the NRC-approved 8WR Owners Group tech-I nical guidelines. These cJ fferences and justifications were provided in a let-l ter from the applicant, dated January 15, 1985. Supplemental information was  ;

provided to the staff on February 11, 1985.

The staff's review consisted of evaluating the justification for each deviation from the generic technical guidelines using plant-specific procedures, supple-

. mented with several telephone discussions with the applicant, i 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 to 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, l 27, 35, 39, and 52 of Attachment 1 to the applicant's January 15, 1985 letter.

l In letters dated April 17, May 15, and July 15, 1985, the applicant satisfac-l torily identified and justified these changes to its plant procedures. The l applicant is expected to incorporate the technical content of these letters in River Bend SSER 3 13-1

E l

'* 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 clartfy the deviations on pages 18, 34, and 50. The staff has confirmed the acceptability of these revised deviations.

l l The staff identified three errors associated with the deviations reviewed.

i First, although the justification on page 1 of Attachment I stated that generic l emergency procedures guidelines (EPG) Cautions 1-8 were addressed in training i and not contained in the procedures, two cautions which the operators would be en 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-l 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 l 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 I the primary containment when containment 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 56 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 offsite radioactive releases by selective use of vent paths (

) The staff must complete its review of this item before the plant can operate above 55 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 i 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 River Bend $$ER 3 13-2

, 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, " Operating and Maintenance Procedures" which address the development of flowchart 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.

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r River Bend SSER 3 13-3 l

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14 INITIAL TEST PROGRAM The Initial Plant Test Program of the River Bend Station Unit I 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.

4 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 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 mirror-image location (assumed to be instrumented) is placed on thermal limits, the misloaded bundle will exceed operating limits.

River Bend SSER 3 15-1

Document Name:

RIVER BEND SSER 3 SEC 18 v Requestor's ID: C' LINDA Author's Name: lWyp N cgw G Stern / Sanders ggq udf[

Document Comments:

8/1/85 Final KEEP THIS SHEET WITH DOCUMENT M db ,

(Mog lW)

W w.,_____________._ _ _ _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - ---- - - - ~

18 HUMAN FACTORS ENGINEERING l

In the discussion that follows, the staff closed out the open licensing issues of the detailed control room design review (DCRDR) required by Supplement 1 to NUREG-0737. The Lawrence Livermore National Laboratory (LLNL) Technical Evalu-ation Report (TER) dated January 29, 1985 (see Appendix J of Supplement 2 to SER)3and 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-tal Summary Report (SSR) No. 1 dated May 14, 1985. The staff reviewed the SSR No. 2 dated June 12, 1985, which resolved the concerns expressed in Appendix B

.. 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:

(1) confirmed the continued participation of human factors specialists in the remaining DCRDR activities (2) submitted additional task analysis documentation results discussed in SSER 2 under " Function and Task Analyses" (3) confirmed that the remaining control room survey items have been completed and the submittal of acceptable resolutions and implementation schedules for human engineering discrepancies (HEDs) have been identified (4) provided acceptable responses to the specific concerns regarding resolu-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

- (5) confirmed that all control room modifications resulting from the DCRDR 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 these actions have been completed before issuing the low power license. How-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 corrected before exceeding 5% of rated power. The 11 HEDs will be corrected during the first refueling outage. The staff has determined that the confirma-tion of actions required to correct certain HEDs before licensing could be deferred until before issuance of a full power license without affecting safe operation of the plant. The identification of all HEDs requiring corrective action and the applicant's accepted proposed schedules for implementing the River Bend SSER 3 18-1

actions are contained in the River Bend DCRDR Summary Report dated October 31, 1984, in supplements dated May 14 and June 12, 13a5, and in the applicant's letter of July 30, 1985.

On the basis of the staff's review of the River Bend Program Plan, DCRDR Summary Report, and supplements, and an onsite, in progress audit, the staff has concluded that except for completing the implementation of corrective actions for certain HEDs, the applicant has satisfactorily completed its DCRDR 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.

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l River Bend SSER 3 18-2

e I* Document Name:

RIVER BEND SSER 3 APP L Requestor's ID

JANE Author's Name: 4 Stern / Sanders Document. Comments:

8/1/85 Final 1

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f APPENDIX L PRESERVICE INSPECTION RELIEF REQUEST EVALUATION I. INTRODUCTION This section was prepared with the technical assistance of Department of Energy (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 River 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 beundary 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 the 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

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 Code 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 during the component fab-rication. Successful performance of preservice examination 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.

In cases 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 which 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 to the Code refer to the ASME Code,Section XI, 1977 Edition, including addenda through Summer 1978.

A. Relief Request R0001, Examination Category B-J, Pressure-Retaining Piping 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 ICS-006-057-1 057BFW004 Pipe to flange MSS-024-600-1 600A25W05E Sweep-o-let to flange 600A25WO5D Sweep-o-let to flange MSS-024-700-1 700A2SWO8M Sweep-o-let to flange 700A2SWO8L Sweep-o-let to flange 700A1SWO8K Sweep-o-let to flange 700A25WO8J Sweep-o-let to flange 700A25WO8H Sweep-o-let to flange

. MSS-024-800-1 800A2SWO7K Sweep-o-let to flange 800A2SWO7J Sweep-o-let to flange 800A25WO7M Sweep-o-let to flange 800A25WO7L Sweep-o-let to flange 800A2SWO7N 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 900A25WO6H Sweep-o-let to flange 1B13*D020 1-ICS-014A-SW001 Tee to flange 1-ICS-014A-SW002 Tee to flange 1-ICS-014A-SWOO3 Tee to flange 1-ICS-014A-SW004 Tee to flange River Bend SSER 3 3 Appendix L

Reason for Request: Because of the confi9 ration (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.

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-ponent. This relief request is acceptable for PSI based on the following con-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.

B. Relief Request R0002, Examination Category B-J, Pressure-Retaining Pipino Welds (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 B-J, Item B9.10.

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-FW009 60 l

__1-SLS-037C-FW004 65 Reactor Core Isolation Cooling System Welds Approximate % Examined hl-ICS-001B-SWO10[ 75 Main Steam Piping Sweep-0-Let Welds Approximate % Examined

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l -MSS-600A2-SWO5D l 75 jl-MSS-900A2-SWO6Es 75 River Bend SSER 3 4 Appendix L

Reason for Request: Because of the location and configuration of adjacent component supports or welded pads located on weld metal repair, the required valumetric 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

_ _ =- _ -.

1 l - Staff Evaluation: The staff has determined that disassembly of the pumps would l

be necessary to perform the required examination in the installed configuration.

I This relief request is acceptable based on the following considerations: i (1) These welds have been volumetrically examined by radiography, and found ac-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. l (3) The failure of these welds, thus leading to failure of the pump, would have no adverse affect on plant safety because redundant emergency core  :

{ cooling systems are provided.

, The staff concludes that requiring a surface examination of the welds encased in concrete would result in hardships or unusual difficulties without a sinnif-

! icant increase in the level of quality and safety because the radiography per-

formed during fabrication and the hydrostatic test are equivalent or superior to the required preservice inspection. In the event that these pumps are dis-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 B-0, Peripheral Control Rod Drive Housing Welds, and Examination Category B-G-2, Bolting Located

., on CRD Housings and Incore Housings Code Requirement:

(1) Peripheral control rod drive housing welds are required to be surface examined (liq 11d penetrant) for PSI in accordance with ASME Code Section XI, i IWB-2500-1, Examination Category B-0.

(2) Pressure-retaining bolting for the flange-to-flange joints, located on the control rod drive (CRD) and incore housings, are required to receive a visual examination (VT-1) for PSI in accordance with ASME Code Section XI, IWB-2500-1, Examination Category B-G-2.

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i Code Relief Request: Relief is requested from performing the liquid penetrant examinations on the peripheral CRD 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-i 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 CRD housing would require that the CRD mechanisms be removed, which could result in damage to the drive.

I Staff Evaluation

This relief request is acceptable for preservice inspection for the following considerations:

(1) The peripheral CRD housing welds have been volumetrically and surface ex-l amined by radiographic and liquid penetrant methods, and have been hydro-static tested in accordance with the requirements of ASME Code Section III.

I River Bend SSER 3 6 Appendix L i

(2) All incore and CRD 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 CRD support structure to perform the required surface and visual examinations would result in hardships and unusual difficulties without a compensating increase in the level of quality and safety because the radiography performed during fabrica-tion and the hydrostatic test are equivalent or superior to the required per-service inspection. In the event that the CRD 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, Pumpe, 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 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, Note (1)(c), Item B9.11.

Code Relief Request: Relief is requested from performing 100% of the Code-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-FWB22 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.

l The staff has therefore concluded the limited Section XI volumetric examination, the required Section XI surface examination, and the fabrication examinations performed during construction aae acceptable alternatives for PSI and provide reasonable assurance of the preservice structural integrity of the subject welds.

G. Relief Request R007, Examination Category B-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

h- for PSI in accordance with ASME Code Section XI, IWB-2500-1, Examination Cate-gory B-J, Item B9.12 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 600A2SWO5BL1 600A25W05BL2 1-MSS-024-900-1 900A25WO6BL1 900A2SW06BL2 1-MSS-024-700-1 700A25WO88L1 700A2SWO88L2 1-MSS-024-800-1 800A2SWO78L1 800A25WO7BL2

_ 1-RCS-010-80G-1 800C-FWA16L 1-RCS-010-80D-1 800C-FWA13L 1-RCS-010-80E-1 800C-FWA14L 1-RCS-010-90D-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 1-RCS-020-800-1 800A-SWOO2ABL 1-RCS-020-900-1 900A-SW002 BBL 1-RCS-010-80F-1 800C-FWA15L 1-RCS-010-90E-1 900C-FWB14L 1-RCS-010-90C-1 900C-FWB12L 1-RCS-010-90F-1 900C-FWB15L 1-RCS-010-90G-1 900C-FWB16L 1-RCS-010-80C-1 800C-FWA12L 1-RCS-020-80A-1 800B-SW007ABL 1-RCS-020-800-1 800A-FWA04L 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-cation 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 walds.

H. Relief Request R0008, Examination Category B-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 89.10.

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 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 800B-FWA10 Pipe to valve j 90A-1 900CX-SWO14CA Reducer to tee 90A-1 900C-FWB11 Pipe to tee )

1 River Bend SSER 3 9 Appendix L

System & Line Weld - Weld Configurations 1-RCS-010-90F-1 900C-FhB15 Pipe to sweep-o-let 90G-1 900C-FWB16 Pipe to sweep-o-let 90D-1 900C-FWB13 Pipe to sweep-o-let 90C-1 900C-FWB12 Pipe to sweep-o-let 1-RCS-020-900-1 900A-SW004BA Pipe to tee 900-1 900A-SW004BC 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 900A-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 900-1 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 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 alternatives 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 valvo body internal surfaces are required to receive a visual examination (VT-1) for PSI in accordance with A5ME Code Section XI, IWB-2500-1, B-L-2 Item B12.20 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 Categor:. 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 j limit the ability to perform meaningful ultrasonic examination of the nozzles' inner radii. To perform an alternate surface examination, the tube bundle

) would have to be removed from the heat exchanger. However, a surface examina-4 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 j (1) The subject weld area received radiographic examination and a hydrostatic g

test during fabrication in accordance with ASME Code Section III require-i ments.

1 (2) An ultrasonic examination has been performed on the nozzle-to-vessel welds j per ASME Code Section XI requirements. i 1

(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 i examination requirements.

, (4) If the heat exchanger is disassembled, the applicant has committed to j perform an alternative surface examination.

4 The staff concludes that compliance with the Code requirements would result in j hardships or unusual difficulties without a compensating increase in the level L

of quality and safety and the Section III hydrostatic test provides a reasonable assurance of 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, d

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 i 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 j 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-l lished by the construction code fabrication examinations.

4 1 f River Bend SSER 3 12 Appendix L 1

i  !

l Based on the staff's review and evaluation, it is concluded that the public interest is.not served by imposing certain provisions of Section XI of the 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-tical to implement.

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1 River Bend SSER 3 13 Appendix L i

4

The applicant has provided information addressing compliance with this require-ment of 10 CFR 50.49.

t j The applicant stated that equipment requiring qualification under 10 CFR 50.49(b)(1) l includes all safety-related equipment required to perform its safety function i in a harsh environment. Also included is equipment in any directly mechanically connected auxiliary systems with electrical components (e.g. , cooling water or l

j lubricating systems) which support the safety function of other safety-related

! equipment.

The systems identified by the applicant for the environmental qualification program as being required to function to mitigate the consequences of loss-of-coolant accidents (LOCAs) or high-energy line breaks (HELBs) that have compo-nents located in a harsh environment were compared to FSAR Table 3.2-1, " Equip-ment and Structure Classification." The omission of systems from the harsh environment program was adequately justified by the applicant. Table 3.11.1 lists the systems identified.

To demonstrate compliance with 10 CFR 50.49(b)(2), the applicant stated that equipment requiring qualification under 10 CFR 50.49(b)(2) includes all equip-ment electrically connected directly into the control or power circuitry of the safety-related equipment whose failure under postulated environmental conditions could adversely affect the safety function of other equipment. The identifica-tion of this equipment utilized, among other measures, review of applicable ,

. elementary wiring diagrams.

The staff referred to the information provided by the applicant to meet the re-quirements of degulatory Guide 1.75, " Physical Independence of Electric Systems,"

wherein the applicant provided alternate methods of meeting those requirements. js The alternate methods have been reviewed and found acceptable by the staff. qe U($

b '

Refer to NUREG 0989 Sections 8.4.5 and 8.4.6 dated May 5, 1984 and to Sections "

fo i l 8.4.5 and 8.4.6 of this report for details. In addition, the staff reviewed and found acceptable, the applicant's response to concerns identified in IE information notice 79-22 " Qualification of Control Systems." Accordingly, the ,

staff concludes that the applicant's conformance to 10 CFR 50.49(b)(2) is acceptable.

07/26/85 3-4 RIVER BEND SSER SEC 3.11 INPUT

10 CFR 50.49(b)(3) requires that all installed RG 1.97, Category 1 and 2 instru-mentation located in a harsh environment be included in the equipment qualifica-tion program unless adequate justification is provided. The applicant has indi-cated a commitment to comply with the requirements of 10 CFR 50.49(b)(3); however, in addressing conformance with RG 1.97, the applicant has identified a number of exceptions. The staff will determine the acceptability of these exceptions as part of its review for conformance with RG 1.97. T**e --"4-w may re< ult i nggs, th. auuition or equipmwnw 1; t'- anvirar r-t;l 4 elificet';r r r- .t C__.

3.11.3.2 Qualification Methods 3.11.3.2.1 Electrical Equipment in a Harsh Environment Detailed procedures for qualifying safety-related electrical equipment in a harsh environment are defined in NUREG-0588. The criteria in this NUREG are also applicable to the other equipment important to safety defined in 10 CFR 50.49.

The General Electric (GE) Environmental Qualification Program presented in GE Topical Report NEDE-24326-1-P outlines the methodology used by GE to qualify nuclear steam supply system (NSSS) safety-related electrical equipment subject to a harsh environment. The applicant, in RBS environmental qualification docu-ment (EQD), dated May 1984, adopted this GE program for River Bend Station.

Based on the results of its review of the GE program, the staff found that the GE position on time margin, as presented in Topical Report NEDE-24326-1-P, did not address the requirement of NUREG-0588, which requires that time margin be a minimum of one hour. The staff identified this as an issue to be addressed by each applicant, and requires that time margin be approached in accordance with NUREG-0588, or as amplified in Regulatory Guide 1.89. The applicant has ap-proached time margin in essentially the same manner as that specified in Regula-tory Guide 1.89. The staff has reviewed the applicant's qualification method-ology and finds it acceptable to meet the requirements of NUREG-0588 Category 1.

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07/26/85 3-5 RIVER BEND SSER SEC 3.11 INPUT

i 3.11.3.2.2 Safety-Related Mechanical Equipment in a Harsh Environment Although there are no detailed requirements for mechanical equipment, GDC 1,

" Quality Standards and Records," and 4, " Environmental and Missile Design Bases," and Appendix B to 10 CFR 50, " Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants" (Section III, " Design Control," and XVII, " Quality Assurance Records"), contain the following requirements related to equipment qualifications:

- Components shall be designed to be compatible with the postulated environmental conditions, including those associated with LOCAs.

i - Measures shall be established for the selection and review for suitability

! of application of materials, parts, and equipment that are essential to safety-related functions.

n

- Design control measures shall to =>tablished for verifying the adequacy

- of design.

- Equipment qualification records shall be maintained and shall include the results of tests and materials analyses.

4 The results of the safety-related mechanical equipment qualification program In addition, qualification docu-have been submitted to the staff for review.

mentation for three items of safety-related mechanical equipment has been sub-mitted by the applicant and has been reviewed by the staff. The staff review has verified that the requirements for environmental qualification of safety-related mechanical equipment have been adequately addressed.

3.11.3.3 Service Conditions NOREG-0588 defines the methods to be utilized for determining the environmental

- conditions associated with LOCAs or HELBs, inside or outside of containment.

l The review and evaluation of the adequacy of these environmental conditions are described below.

The staff has reviewed the qualification documentation to I

.i 3-6 RIVER BENO SSER SEC 3.11 INPUT 07/25/85 l l+ WL.15 - Hof (17s gr I.w 4 b &'l-

._. _ _ fP V ~~-_ --~7v--,__.,_._ _

f ensure that the qualification conditions enveloped the environmental conditions 4 established by the applicant.

3.11.3.3.1 Temperature, Pressure, and Humidity Conditions Inside the Drywell

! The applicant provided the LOCA/ main steamline break (MSLB) profiles used for equipment qualification program submittals. The peak values in the drywell shown on these profiles are as follows:

Maximum Maximum pressure, temperature. 'F psia Humidity. %

330 25 100 LOCA/MSLB J

The staff has reviewed these profiles and finds them acceptable for use in equipment qualification; that is, there is reasonable assurance that the actual pressures and temperatures will not exceed these profiles anywhere within the specified environmental zone (except in the break zone).

N 1

3.11.3.3.2 Temperature, Pressure, and Humidity Conditions Outside the Drywell The applicant has provided the temperature, pressure, and humidity conditions associated with HELBs outside the drywell. The criteria used to define the

location of HELBs are described in FSAR Section 3.6.

l

- - The staff has used a screening criterion of saturation temperature at the calcu-4 lated pressure to verify that the peak temperatures identified by the applicant are acceptable.

3.11.3.3.3 Submergence 1

Flood levels for various areas have been calculated, with the flood level in j

the drywell being 109' following a LOCA. The effects of flooding on equipment The applicant have been evaluated to ensure that safe shutdown can be achieved.

has taken appropriate corrective action to relocate or qualify all affected equipment.

i 3-7 RIVER BENO SSER SEC 3.11 INPUT  ;

07/25/85 '

1 3.11.3.3.4 Demineralized Water Spray The applicant stated that RBS does not have a spray system. Therefore, it is not necessary to evaluate the effects of spray on equipment important to safety.

3.11.3.3.5 Aging The aging program requirements for RBS electrical equipment are defined in Cate-gory I of NUREG-0588. All degrading influences must be considered and included in the aging program. Justification for excluding pre-aging of equipment in

- type testing must be established based on equipment design and application, or on state-of-the-art aging techniques. A qualified life is to be established for each equipment item.

In addition to the above, a maintenance / surveillance program must be implemented to identify and prevent significant age-related degradation of electrical and mechanical equipment. The applicant committed to follow the recommendations in RG 1.33, Revision 2, " Quality Assurance Program Requirements (Operation)," which endorses American National Standard ANS-3.2/ ANSI N18.1976, " Administrative Con-

! trols and Quality Assurance for the Operational Phase of Nuclear Power Plants."

This standard defines the scope and content of a maintenance / surveillance pro-gram for safety-related equipment. Provisions for preventing or detecting age-related degradation in safety grade equipment are specified and include (1) utilizing experience with similar equipment, (2) revising and updating the program as experience is gained with the equipment during the life of the plant, (3) reviewing and evaluating malfunctioning equipment and obtaining adequate replacement components, and (4) establishing surveillance tests and inspections based on reliability analyses, frequency and type of service, or age of the items, as appropriate.

The applicant has described a program that incorporates the above guidelines and has stated that the maintenance / surveillance program is in effect at River Bend.

t

07/25/85 3-8 RIVER BEND SSER SEC 3.11 INPUT l

3.11.3.3.6 Radiation (Inside and Outside Containment)

The applicant has provided values of the radiation levels postulated to exist following a LOCA. The accident radiation environments in primary containment have been defined according to NUREG-0588. For this review, the staff has assumed that the values provided have been determined in accordance with the

prescribed criteria. The staff review determined that the values to which the

' equipment is qualified enveloped the requirements identified by the applicant.

The maximum total radiation dose specified by the appifcant for primary contain-

- ment is 1.7 x 10s rads gamma. In the secondary containment, values of up to 1.8 x 10s rads gamma were used in the evaluation of equipment in areas exposed to recirculating fluid lines. These values are acceptable for use in the quali-fication of equipment.

3.11.3.4 Outstanding Equipment For safety-related items not having complete qualification documentation, the applicant has provided commitments for corrective action and schedules for com-pletion. For items identified to date that will not have full qualification before an operating license is issued, analyses have been performed in accord-ance with 10 CFR 50.49(i) to ensure that the plant can be operated safely pend-ing completion of environmental qualification. These analyses have been sub-mitted for consideration. The staff has reviewed the justifications for interim operation and has concluded that reasonable assurance has been provided that the River Bend plants can be operated safely pending completion of environmental qualification.

3.11.4 Qualification of Equipment The following subsections presents the staff's assessment based on the appli-cant's submittal, audit of documentation contained in the applicant's qualifi-cation files, and previous staff evaluations of equipment in other plants.

4 07/25/85 3-9 RIVER BEND SSER SEC 3.11 INPUT

1 3.11.4.1 Electrical Equipment Important to Safety The staff has separated the electrical equipment in a harsh environment into two categories: (1)equipmentrequiringadditionalinformationand/orcorrec-tive action, (2) equipment considered acceptable, based on the staff's review.

Tables 3.11.2 and 3.11.3 list equipment in each of these categories, respectively.

3.11.4.1.1 Equipment Requiring Additional Information and/or Corrective Action Table 3.11.2 identifies equipment in this category. Corrective action or defi-ciencies are noted by = latter =rrerdfr.g to th: iviluwing iegend:

6 Me 4able. .

he Legend N .__ . --

40 f$

gg)O QD qualification information being developed, justification for interim ogewdyow provided, j

.- The deficiencies have been determined on the basis of all the information avail-able to the staff at the time of review and do not necessarily mean that thc equipment is unqualified. However, the deficiencies are cause for concern and require further case-by-case evaluation. The applicant has indicated that all of the concerns identified have been reviewed and all deficiencies identified have been adequately resolved and are auditable. In accordance with 10 CFR 50.49(1) acceptable justifications for interim operation have been submitted for equip-ment items not having complete qualification.

3.11.4.1.2 Equipment Considered Acceptable On the basis of the staff review, the items identified in Table 3.11.3 have been determined to be acceptable.  !

3.11.4.2 Environmental Qualification Audit On January 26, 27, and 28, 1985, the staff, with assistance from EG&G Idaho, Inc. , conducted an audit of the applicant's qualification documentation and equipment installed at the plant. Twelve equipment items were reviewed to 07/25/85 3-10 RIVER BEND SSER SEC 3.11 INPUT

l l

l l

determine if the documents in the qualification files supported the qualifica- l tion status determined by the applicant.

The equipment items selected for audit were

1. Conax Electrical Penetration (SRN-241211-1)

2. Limitorque Valve Actuators, inside containment (SRN-228212-1)

3. Limitorque Valve Actuators, outside containment with paramount motors (SRN-228212-2)

4. Asco Solenoid Valve (SRN-228218-3)

5. Rosemount Transmitters (SRN-247481-1)

6. Mercury / Buchanan Terminal Boards (SRN-247411-2)

7. Endevco Primary Position Element (SRN-247529-2)

8. Okonite 600V Control Cable (SRN-241240-1)

9. Westinghouse Pump Motor (SRN-237160-1)

10. Hydrogen Igniter Assembly, by Power Systems Division (SRN-211161-1)

11. Namco Limit Switch (SRN-505B)

12. Sheffer MSIV Actuator (SRN-505A)

These files were reviewed to determine if qualification has been demonstrated based on the documents contained in the files. Several deficiencies were noted and discussed with the applicant at the time of the audit. These deficiencies were also provided to the applicant in June 1985 and transmitted to the appli- R cant by letter dated July 17, 1985. The applicant responded by letters dated June 19 and July 19, 1985. The staff reviewed the responses and concluded that the deficiencies have been adequately resolved.

As part of the audit, the equipment as actually installed was inspected during a plant walkdown. The purpose of the walkdown was to verify that the manufac-turer, model number, location and installation are consistant with qualification documents.

3.11.5 Conclusion The staff has reviewed the River Bend program for the environmental qualifica-tion of electrical equipment important to safety and safety-related mechanical 07/26/85 3-11 RIVER BENO SSER SEC 3.11 INPUT

equipment. The purpose of the review was to determine the adequacy and scope of the qualification program and to verify that the methods used to demonstrate qualification is in compliance with applicable regulations and standards.

Our review has determined that the following license condition should be included ,

in the RBS license:

1. All electrical equipment within the scope of 10 CFR 50.49 must be environ-mentally qualified by November 30, 1985.

Based on the results of our review, we conclude that the applicant's environmental qualification program is acceptable and that adequate justification for interim operation has been provided for equipment nn+ 6 ving complete qualification. We further conclude that the applicant has d . rated conformance with the require-ments for environmental qualification as detailed in 10 CFR 50.49, and relevant parts of GDC 1 and 4, and Sections II, XI, and XVII of Appendix B to 10 CFR 50, 1

and with the criteria specified in NUREG-0588.

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l 07/25/85 3-12 RIVER BEND SSER SEC 3.11 INPUT

Table 3.11.1 Safety-Related Systems River Bend Station Environmental Qualification Program Reactor System Nuclear Boiler System -

Recirculation System CRD Hydraulic System Standby Liquid Control System Reactor Protection System

.. Process Radiation Monitors RHR System Low Pressure Core Spray High Pressure Core Spray RCIC System Reactor Water Cleanup System Fuel Pool Cooling and Cleanup System

. Main Control Room Panels Local Panels and Racks Standby Service Water System Normal Service Water System Instrument and Service Air Systems Combustible Gas Control System Standby Gas Treatment System Containment Ventilation System

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Auxiliary Building Ventilation System Power Conversion System Condensate Makeup and Drawoff System Auxiliary AC Power System (Class IE)

Reactor Plant Component Cooling Water Equipment and Floor Drainage Systems Fuel Building Ventilation System Area Radiation Monitoring System Leak Detection System 07/25/85 3-13 RIVER BEND SSER SEC 3.11 INPUT

._ _ ~. - . _ _. _. -- . _ _ _ _ _ _

Table 3.11.1 Safety-Related Systems River Bend Station Environmental Qualification Program (cont'd)

Main Stean-Position Leakage Control System (MS-PLCS) and Penetration Valve Leakage Control System (PVLCS)

Drywell Ventilation System Annulus Mixing System Annulus Pressure Control System

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Containment and Drywell Purge System Post-Accident Sampling System W

0 4

3-14 RIVEP. BEND SSER SEC 3.11 INPUT 07/25/85

i Table 3.11.2 Equipment requiring corrective action Deficiency /

• h Model number Component description Manufacturer corrective action

1. Cable Repair Kit Okonite Okoguard QD

2. Raychem Heat-Shrink Raychem WCFS-N, NMCK, QD NCBK, NESK, NPK, NMCK8, NHVBC, 51119-6-1500, GCA, EPPA-109N

3. Heat Tracing Thermon -

QD

4. Heater Nuthern A-1057 QD

5. Motor (Pump) Reliance 184HP QD

6. Cable Rockbestos -

QD

7. 480V Load Center Powell AKDG QD Electrical

8. 480 Motor Control Center Gould Inc. Series 5600 QD

9. Radioactivity Element GA Tech RD-52, R0-72 QD (Pump)

10. Control Switches General Electric CR 2940 QD

11. Thermal Flow Detecting Fluid Components FR72-1R, FR72-4R QD Element Inc.

12. Electrohydraulic Borg Warner EC QD Actuator

13. Pressure Transmitter Rosemount 1152 Series QD Limitorque/ SMC-D4-2, 3 QD

14. NOV-AC/B Insulated Outside Containment Paramount M Gb-

%# jd k. Go9Q e.

3-15 RIVER BEND SSER SEC 3.11 INPUT 07/25/85

Table 3.11.3 Equipment considered acceptable

' Deficiency /

Component description Manufacturer Model numbgr ,. corrective action Hydrogen Igniter Assemby Power Systems --

Division Resistance Temperature Detector PYC0 122-3046-04 Unit Cooler Motor Westinghouse 445TCZ ,

Unit Cooler Motor Westinghouse 326TCZ Unit Cooler Motor Westinghouse 324TCZ Unit Cooler Motor Westinghouse 256TCZ Unit Cooler Motor Westinghouse 215TCZ Unit Cooler Motor Westinghouse 213TCZ Hydrogen Mixing Fan Motor Westinghouse TBFC 145T Fan, Ventilation and Filter Westinghouse 00P 365TZ Fan, Ventilation and Filter Westinghouse FBFC 143T Fan, Ventilation and Filter Westinghouse 00P 326TZ

' Fan, Ventilation and Filter Westinghouse TEFC Fan, Ventilation and Filter Westinghouse TBDP449TS Limit Switch NAMCO EA180 Solenoid Valve ASCO NP8321ASE Electrical Penetration CONAX Solenoid Valve TRCP 82B-002 Solenoid Valve TRCP 202683-1 ,

H Recombiner Power Supply Westinghouse B H Recombiner Westinghouse B Heater Nuthern A-1057 Flow Switch CEMCO RH-15 Temperature Switch Fenwal 54-301 Temperature Switch Fenwal 54-302

" #9"' "" **

MOV-AC/RH Insulated Inside and Outside Containment a rque SB, SM and E MOV-AC/B Insulated Outside Containment Series MOV-DC/RH Insulated Outside Limitorque SMB Series Containment Limit Switch NAMCO EA-180, EA-740 07/25/85 3-16 RIVER BEND SSER SEC 3.11 INPUT l

l Table 3.11.3 Equipment considered acceptable (cont'd) o

.SP (Dsficiency/

Component description Manufacturer Model number (correctiveaction Solenoid Operated Valve ASCO HV-206-832-6F Pump Motor Westinghouse 184T-TEFC, 213T-TEFC SKV Power Cables Anaconda --

600V Power Cable Okonite --

600V Control Cable Okonite

. 300V Instrument Cable Rockbestos Firewall III 300V Coax. and Twinax Rockbestos RSS-6 Instrument Cable 300V Instrument Cable Rockbestos XLPE/ Neoprene Extension Wire (Thermocouple) Rockbestos XLPE/ Neoprene l Instrument Cable Bran-Rex Co. --

Terminal Cabinet Terminal GE EB-25 Boards Splice (Terminal Cabinet) Raychem Splice Transformer for 480V Load Southern 1500 KVA Center Transformer Terminal Racks-Wire Racks Mercury /Eaton Instrument Rack Hydrogen Analyzer-Remote Comsip Inc. Part of KMS* PNL 10A Cabinet Hydrogen Analyzer-Local Comsip Inc. KIII Cabinet RTD PYC0 122-3046-12 RTD PYC0 122-4030-04 Solenoid Valve ASCO NP8320 Solenoid Valve Target Rock 77KK-002, 77KK-003, 77KK-008, 77KK-001, 77KK-004, 77KK-005, 77KK-010, 77KK-011, 77KK-015, 77KK-009, 77KK-012, 77KK-013, 77KK-014 Position Transmitter Rack TEC --

Primary Position Element Endevco .E2273AM1 Position Transmitter TEC 504A l

Level Transmitter Gould Inc. PD3218 Temperature Element PYCG 102-9039-11 07/25/85 3-17 RIVER BEND SSER SEC 3.11 INPUT

Table 3.11.3 Equipment considered acceptable (cont'd)

Component description Deficiency /

Manufacturer Model number corrective action Insulated Detector GE NA-05 Pressure Switch Barksdale TC 9622-3

. Level Switch Magnetrol 5.0-751 Limit Switch NAMCO EA170-51101 Pump Motor GE SK6336XC322A, SK6339XC185A, SK6348XC98A MSIV Actuator Sheffer Corp. SA-A070 MSIV Limit Switch NAMCO EA740, REV.N RCIC Turbine Terry Corp. GS-2 Pump Fotor GE SK324AN2960 l

Solenoid Valve, 3-way ASCO HVA-176-816-1

~

Pilot Solenoid Valve VALCOR V70900-45

~

Backup Scram Solenoid Valve VALCOR V70900-43 Explosive Valve CONAX 7048-17000-01 Motor (Compressor) Reliance 326TS Motor (Pump) Reliance --

Transformer Southern SN-4475-1, 2 i

Transformer Co. 3,4,5,6,7, 8, 9, 10, 11, 12, 13 120V Distribution Panel Square D NQOB SKV Switchgear Brown Boveria SHK250 Transmitter Rosemount 1153B Series Electrical Penetration CONAX 7437-10000,10001, 10002, 10003, 10004, 10005 MOV-AC/RH Insulated Limitorque/ SMB and SB Series Ins,ide Containment Reliance Main Steam Safety / Relief Crosby HB-65-DF Valve Terminal Boards Mercury / Buchanan NQB-112 07/25/85 3-18 RIVER BEND SSER SEC 3.11 INPUT

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SAFETY EVALUATION REPORT TMI ACTION--NUREG-0737 (II.D.1)

RELIEF AND SAFETY VALVE TESTING FOR RIVER BEND STATION -

UNIT 1 .

DOCKET NO. 50-458

1. INTRODUCTION

1.1 Background

Light water reactor experience has included a number of instances of improper performance of relief and safety valves installed in the primary coolant systems. There have been instances of valves opening below set pressure, valves opening above set pressure and valves failing to open or reseat. From these past instances of improper valve performance, it is not known whether they occurred because of a limited qualification of the valve or because of a basic unreliability of the valve design. It is known that the failure of a power-operated relief valve to reseat was a significant contributor to the TMI-2

- sequence of events; however, such an event in a Boiling Water Reactor (BWR) would not have the same severe consequences. Nevertheless, these facts led the task force which prepared NUREG-0578(1) to recommend that programs be developed and executed which would reexamine the performance capabilities of BWR safety and relief valves for unusual but credible events. These programs were deemed necessary to reconfirm that the General Design Criteria 14,15 and 30 of Appendix A to Part 50 of the Code of Federal Regulations, 10 CFR are indeed satisfied.

1

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• l 1.2 General Design Criteria and NUREG Requirements l General Design Criteria 14, 15, and 30 require that (1) the reactor primary coolant pressure boundary be designed, fabricated and tested so as to have an extremely low probability of abnormal leakage, (2) the reactor coolant system and associated auxiliary, cont'rol and protection systems be designed with sufficient margin to assure that the design conditions are not exceeded during normal operation or anticipated transient events and (3) the components which are part of the reactor coolant pressure boundary shall be constructed to the highest quality standards prsctical.

To reconfirm the integrity of relief and safety valve systems and thereby assure that the General Design Criteria are met, the NUREG-0578 position was issued as a requirement in a letter dated September 13, 1979 by the Division of Licensing (DL), Office of Nuclear Reactor Regulation (NRR) to ALL OPERATING NUCLEAR POWER PLANTS. This requirement has since been incorporated as Item II.D.1 of NUREG-0737(2) (Clarification of TMI Action Plan Requirements)

.which was issued for implementation on October 31, 1980. As stated in the NUREG reports, each boiling water reactor Licensee or Applicant shall:

1. Conduct testing to qualify reactor coolant system relief and safety valves under expected operating conditions for design basis transients and accidents.

2. Determine valve expected operating conditions through the use of analyses of accidents and anticipated operational occurrences referenced in Regulatory Guide 1.70, Rev. 2.

3. Choose the single failures such that the dynamic forces on the safety relief valves are maximized.

4. Use the highest test pressures predicted by conventional safety analysis procedures. .

2

5. Include in the relief and safety valve qualification program the qualifi* cation of the associated control circuitry, piping and a supports.

I

6. Test data including criteria for success or failure of valves

- tested must be provided for Nuclear Regulatory Commission,(NRC) staff review and evaluation. These test data should include data l that would permit plant-specific evaluation of discharge piping -

and supports that are not directly tested. ,

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7. Each Licensee or Applicant must submit a correlation or other evidence to substantiate that the valves tested in a generic test program demonstrate the functionability of as-installed primary relief and safety valves. This correlation must show that the test conditions used are equivalent to expected operating and accident conditions as prescribed in the Final Safety Analysis Report (FSAR). The effect of as-built relief and safety valve discharge piping on valve operability must be accounted for if it is different from the generic test loop piping.

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2. BWR OWNERS' GROUP RELIEF AND SAFETY VALVE PROGRAM To respond to the NUREG requirements listed above, the BWR Owners' Group contracted the General Electric Company (GE) to design and conduct a Safety / Relief Valve Test Program.(3) The program describes the safety / relief valves to be tested, the test facility requirements, the test sequence, the valve acceptance criteria and the procedure for obtaining, analyzing and reporting the test data. Prior to its acceptance, the test program received extensive NRC review and comment followed by responses from the GE/BWR Owners' Group. Six NRC questions and Owners' Group responses dealing with justification of the applicability of test results to the in plant safety / relief valves are contained in the enclosure to I Reference 4. The NRC review of the response to these questions is contained in Reference 5. Based on this review, the concerns expressed in the questions were appropriately resolved. .

The early BWRs contain a combination of dual function safety / relief valves (SRV), power actuated reitef valves (PARV) and single function safety valves (SV). At the River Bend Sta' tion, Unit 1, there are 16 dual

( function SRV's. There are no PARV's or SV's at the River Bend Station.

The qualification of the SRVs for steam discharge under expected operating and accident conditions has been demonstrated by vendor production tests and is confirmed routinely by in plant startup and operability tests. Based on this, it was agreed that the valves should be tested for those events that result in liquid or two phase flow at the SRV.

The test sequence and conditions established in the test program were 1

based on an evaluation of expected operating conditions determined through the use of analyses of accident and anticipated operational occurrences referenced in Regulatory Guide 1.70, Rev. 2. Enclosure 2 to Reference 3 provides this evaluation which indicated that there is one event which is significantly likely to occur and can lead to the discharge of liquid or 4

i two phase flow from the SRVs. This event combined with the single failure requirement of NtJREG 0737 results in the conclusion that a test should be performed simulating the alternate shutdown cooling mode which utilizes the SRVs as a return flow path for low pressure liquid to the suppression pool.

i At a meeting on March 10,1981,(6) the BWR Owners' Group presented results of a study by Science Applications, Inc. (SAI) which showed that

the probability of getting liquid to the steamline, and hence to the SRV's, is approximately 10 -2 per reactor year. However, even if the water level increases to the mid plane of the steam line nozzle on the vessel, which is not likely," the fluid quality at the valve was calculated by GE to be greater than 20%.(3) Because the steam lines typically drop about 45 feet vertically from the vessel nozzles to the horizontal runs on which the SRVs are mounted, much of the liquid which gets to the steam lines would be entrained as droplets. Therefore, the two phase mixture upstream -

of the SRVs, should liquid reach the level of the steam lines, would exist as a froth, droplet, annular or stratified flow regime, and slug flow or subcooled liquid flow would be unlikely.

Even if two phase discharge through a SRV should result in a stuck open valve, the results of the blowdown are not severe. As discussed in Reference 7, historically there have been a total of 53 inadvertent blowdown events due to pressure relief system valve malfunctions from 1969 through April 1978. These events varied in consequences from a short duration pressure transient to a rapid depressurization and cooldown of the primary coolant system from approximately,1100 psig to a few hundred psig.

No fuel failures due to these transients have been reported.

In Reference 8, the BWR Owners' Group discusses the consequences of ,

the worst case transient for maintaining the core covered (loss of feedwater) combined with the worst single failure (failure of the high

a. Feedwater pumps would be tripped prior to the water level reaching the mid plane by the L8 high level trip, turbine vibration trip, or by operator action.

l 1 5 l

pressure injection system) and one stuck open relief valve. Reference plant analyses for a BWR/4 and BWR/5 show that the Reactor Core Isolation Cooling (RCIC) system can automatically provide sufficient inventory to keep the core covered. The capability is not a design basis for the RCIC system and not all plants have been analyzed to demonstrate this .

capability. If a plant should not have this capability, manual depressurization to low pressure core cooling systems will avoid core uncovery for the case of loss of feedwater plus worst single failure plus a stuck open relief valve. Therefore, even for the loss of feedwater transient with the worst single failure, a stuck open relief valve does not uncover fuel.

At the March 10, 1981 meeting,(6) the BWR Owners' Group presented an analysis that showed that even if a slug of subcooled water exists upstream of the SRVs, the probability of rupturing the discharge line is -

7 x 10~4per event. The Staff has not reviewed the supporting analysis for this value; however, even if the failure probability is as high as 10

-2 per event, the combined probability is no greater than for a steam line break inside containment. GE states that the steam line break, which has been analyzed and found to be acceptable, would be more severe (effects on the core and containment) than a break in a SRV discharge line with a stuck open SRV because the assumed break area is larger.

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In summary, based on the BWR operating history of inadvertent SRV blowdowns, the low likelihood of severe consequences, and the bounding design basis steam line break, the staff decided not to require high pressure testing with saturated liquid or subcooled water.

Based on the above, the Applicant has complied with NUREG Requirements 1-4 (Paragraph 1.2 above). That is, an acceptable test program was established which adhered to the Staff guidelines on the selection of test conditions and the maximization of system loads. That portion of Item 5 dealing with the qualification of the associated control circuitry is considered to be satisfied as a result of the anticipated licensing action for compliance with 10 CFR, Part 50.49.

6

3. BWR OWNERS' GROUP TEST RESULT AND ANALYSIS In October 1981, the BWR Owners' Group published a technical report (9) documenting the results of the prototypical safety / relief valve tests conducted in accordance with the accepted Test Program.(3) The tests were performed by the General Electric Company for the BWR Owners' Group at the Wyle Laboratory in Huntsville, Alabama. The test report, which was reviewed by the Staff, describes the test facility, the basis for the test conditions and valve selection, the instrumentation and its accuracy, and analyzes the results with respect to valve operability, piping and support loads and the applicability of the test results to the in plant safety and relief valves.

With the completion of the testing and the submittal of the test report, the Applicant complied with NUREG Requirement No. 6 listed in 1.2 above. However, the subsequent Staff review of the test results ,

generated four plant specific questions stated in Reference 10 which required resolution. Reference 11, representing the River Bend Station response to the four plant specific questions, was submitted for review on May 15, 1985.

O 7

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4. REVIEW AND EVALUATION i

4.1 Review of Test Results and Analysis An extensive review (12,13) of the test results(9) was conducted by i NRC consultants (EG&G Idaho, Inc.) at the Idaho National Engineering

.s Laboratory. The review addressed not only the test results but also the

! applicability of the test results and equipment to the River Bend Station safety-relief valve systems. The four plant specific questions generated by j

the review and the Applicant's responses to those questions are discussed in Paragraph 4.4 below.

4.2 Valves Tested The generic test program required the testino of six different i

safety / relief valves. Included was a Crosby (8 x R x 10) Safety Relief Valve, Style HB-65-BP. This valve is a direct acting, dual function, spring loaded SRV with no material, dimensional or operational differences compared to the in plant valves. Thus, the test results are directly applicable to

. the in plant valves at the River Bend Station.

4.3 Test Conditions As discussed in Section 2.0 herein, test conditions to envelop the expected BWR Safety / Relief Valve events were developed in accordance with NRC guidelines. They were accepted and are presented in Reference 3. The review of the test results indicates that the actual test conditions were in accordance with the established test program.

l 4.4 Evaluation of Responses to Plant Specific Questions The response to Question No. 1 indicates that there are valve discharge line differences between the test configuration and the in plant configuration. However, it is pointed out that these differences result in 4

bounding loads on the SRV's. The first segment of test piping downstream of the test valve is comparable in length to in plant segment (12 ft.),

8

which would result in an equivalent moment at the test valve. Discharge from the tee quencher'at the end of the River Bend SRV discharge line cannot transmit loads to the valve as the test system could because the in plant line is anchored between the quencher and the valve. Thus, this portion of the response is considered to be acceptable. The second part of the response addressed the back pressure (dynamic, hydraulic) loads on the test and in plant valves. The Applicant addressed both transient and steady state back pressure loads. The steady state back pressure for the test valve was forced to be greater than that expected in plant by installing a predetermined orifice plate in the discharge line before the ram's head and above the water line. The response also indicated that the high pressure steam test preceding the low pressure water test would produce the greater transient back pressures between the two tests. This would be true due to the higher pressure upstream of the SRV and the shorter valve opening time.

Based on the above discussion, the response to the first question is -

considered by the Staff to be acceptable.

The response to the second question described the support system components in the River Bend discharge 11n'es indicating that spring hangers do exist at the River Bend Station whereas the test facility piping did not include spring hangers. The basic argument defending the adequacy of the spring hangers (in fact, all supports) is that they were designed for the much larger, high steam pressure relief valve opening loads. In this case, therefore, sufficient margin is available in the in plant spring hangers to account for the additional load due to the dead weight in the water-filled, low pressure event. The test results indicated significantly lower dynamic loads during the water discharge event than during the high pressure steam discharge case and the point made in this response (as well as in the response te Question No.1) is that the test program was designed primarily to demonstrate valve and system adequacy under the prototypical water discharge events (i.e., the alternate shutdown cooling mode).

Thus, with the in plant safety / relief valve discharge piping and support system designed for the high pressure steam discharge event and with the ,

satisfactory response of the test valves, the discharge piping and support 9 l i

1

.I

system to the low pressure water blowdown, the reply to the second question is considered by 1.he Staff to be acceptable.

Question No. 3 asked the Applicant to describe and compare expected events at River Bend Station with the test conditions of the generic test program. The Applicant summarizes the analysis procedure (3) using Regulatory Guide 1.70 which arrived at 13 events that would result in liquid or two phase flow through the SRV's and maximize the dynamic forces on the valve. As indicated in Section 2.0 herein, this analysis concluded that the

- alternate shutdown cooling mode is the only expected event which will result in liquid at the valve inlet. To simulate this event the test program (3) used a 15-50 F subcooled liquid at 20-250 psig at the SRV inlet prior to

. valve opening. The Applicant indicates that the fluid / flow conditions tested conservatively bound the River Bend Station conditions expected for the alternate shutdown cooling mode of operation. The Applicant's response to .

the third question is acceptable to the Staff.

The response to the fourth question addresses the determination and future use of the valve flow coefficient, C .y The response indicates that the value of the liquid flow coefficient, in itself, is not of direct interest. The flow capacity of the valves as measured during the tests is the data of interest. The flow capacity of the system SRV's is larger than the capacity of the coolant source pump of the residual heat removal (RHR) system and therefore sufficient to remove decay heat. The answer to this

~

question is considered to be acceptable to the Staff.

Considering the above evaluations, the Staff finds that the Applicant for the River Bend Station, Unit I has provided an acceptable response to NUREG Item 7 and to the piping and support concerns of NUREG Item 5 (Paragraph 1.2 herein).

4.5 Supporting Information 4.5.1 Additional Questions Two other questions generated by the staff concerning (1) valve functional deficiencies encountered during invalidated test runs and (2) the 10

effect of steam cycling on valve performance have been addressed previously by other Licensee's using the Crosby (8 x R x 10) SRV. The staff accepted those responses based on the following:

1. Previous submittals by other Licensees have stated, "All the valves 4 subjected to test runs, valid or invalid, opened and closed without loss of pressure integrity or damage." This statement was j supported by the Wyle Laboratory test log sheet for the Crosby  ;

valve.

2. Although the test program did not subject the valves to steam

cycling, the valve vendor has subjected his valves to high pressure steam flow cycling and no loss of valve performance has been noted.

4 A

Because of this prior acceptance, the Applicant for the River Bend Station, - ,

, Unit 1, was not requested to respond to these concerns.

4.5.2 High Pressure Steam Flow / Discharge Piping Response The applicability of the response of the safety-relief valve discharge piping system to the response of the in plant piping system has been accepted above. In the test report,(9) it is indicated that, (1) the analytically predicted response of the test piping and supports was comparable to the measured values, and (2) the maximum test piping response to liquid flow was

- generally less~than 30% of that due to test steam flow conditions. Further, as part of the initial review, the loads on the in plant piping and supports due to steam discharge were found to be acceptable by the Staff. It should also be mentioned that the adequacy of the River Bend SRV discharge piping under high pressure steam loads, is investigated as part of the Staff's normal licensing review.

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5. EVALUATION

SUMMARY

i The Applicant for the River Bend Station, Unit I has provided an acceptable response to the requirements of NUREG-0737, and thereby, reconfirmed that the General Design Criteria 14, 15 and 30 of Appendix A to  ;

10 CFR-50 have been met. The rationale for this conclusion is given below.

The Applicant with concurrence by the Staff developed an acceptable Relief and Safety Valve Test Program designed to qualify the operability of the prototypical valves and to demonstrate that their operation would not invalidate the integrity of the associated equipment and piping. The subsequent tests were successfully completed under operating conditions which by analysis bounded the most probable maximum forces expected from

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anticipated design basis events. The generic test results showed that the valves tested functioned correctly and safely for all steam and water -

f discharge events specified in the test program and that the pressure boundary component design criteria were not exceeded. Analysis and review of the test results and the Applicant justifications indicated the direct applicability of prototypical valve and valve system performances to the in plant valves and systems intended to be covered by the generic test program.

Thus, the requirements of Item II.D.1 of NUREG 0737 have been met (Items 1-7 in Paragraph 1.2) and, thereby, assure that the reactor primary coolant pressure boundary will have, by testing, a low probability of abnormal leakage (General Design Criterion No. 14) and that the reactor primary coolant pressure boundary and its associated components (piping, valves and supports) have been designed with sufficient margin such that design conditions are not exceeded during relief / safety valve events (General Design Criterion No. 15).

Further, the prototypical tests and the successful performance of the valves and associated components demonstrated that this equipment has been constructed in accordance with high quality standards (General Design Criterion 30).

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REFERENCES

1. TMI-2 Lessons Learned Task Force Status Report and Short-Term Recommendations, NUREG-0578, July 1979.

2. Clarification of TMI Action Plan Requirements, NUREG-0737, November 1980. ,

3. Letter, D. B. Waters (BWR Owners' Group), to Richard H. Vollmer (NRC)

"NUREG-0578 Requirement 2.1.2 - Performance Testing of BWR and PWR Relief and Safety Valves," September 17, 1980.

4. Letter, D. B. Waters, Chairman BWR Owners' Group to D. G. Eisenhut, Director, Division of Licensing, NRR, USNRC, " Responses to NRC Questions

.. on the BWR S/RV Test Program," BWR06-8135, March 31, 1981.

5. Letter, B. F. Saffell to R. E. Tiller, Comments on BWR Owners' Group Responses to NRC Questions on Safety / Relief Valve Low Pressure Program - Saff-95-81, April 23, 1981.

6. Memorandum to Themis P. Speis from Wayne Hodges, " Summary of March 10 Meeting with General Electric to Discuss BWR Liquid Overfill Events," -

May 1981.

7. Technical Resort on Operating Experience with BWR Pressure Relief Systems, NUR EG-0462, July 1978.

8. Letter to Darrell G. Eisenhut (NRC) from David B. Waters (BWR Owners' Group), BWROG-80-12, "BWR Owners' Group Evaluation of NUREG-0737 Requirements," December 29, 1980.

9. Analysis of Generic BWR Safety Relief Valve Operability Test Results, General Electric NEDE-2 4988-P, October 1981.

10. Letter from A. Schewencer, USNRC to W. J. Cahill Jr., Gulf States Utilities Company, TMI Action Plan, Item II.0-1, Performance Testing of BWR Relief and Safety Valves, November 9, 1984.

11. Letter, J. E. Booker (Gulf States Utilities Company) to H. R. Denton (NRR-USNRC), " River Bend Station Unit 1, Docket No. 50-458,"

May 15, 1985.

12. Letter, B. F. Saffell to R. E. Tiller, " Review of BWR/GE Safety Relief Valve Test Report (A6356)" Saff-14-82, January 13, 1982.

13. Letter, B. F. Saffell to D. E. Solecki, "Open Questions-BWR/GE Safety / Relief Valve Test Report, BWR Owners' Safety / Relief Submittals (A6356)"-Saff-178-82, May 4, 1982.

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TABLE OF CONTENTS P_a2.8 ABSTRACT ................................................................ iii 1

INTRODUCTION AND GENERAL DISCUSSION ................................ 1-1 1.1 Introduction ................................................. 1-1 1 1.5 Outstanding Issues ........................................... 1-1.6 Confirmatory Issues .......................................... 1-1.7 License Conditions ........................................... 1-l 2 SITE CHARACTERISTICS ............................................... 2-1 i

2.1 Geology and Demography ....................................... 2-1 s-y, II );{i l: . L .* '

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-iW5 Steb H i i.y o f 51 ope s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-1 3 DESIGN CRITERIA FOR STRUCTURES, SYSTEMS, AND COMP 0N~NTS ............ 3-1 3.6 Protection Against Dynamic Effects Associated With the

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Postulated Rupture of Piping ................................. 3-1 p ,g .si for Prctecken A d m

f.icatt ag,se cau... .dabst . - . Pc>h afec) Ryfuu

. . - . . . & 3 _1 3.6.2 Deted ation of Ruptt.re Location and Dynamic Effects y Associated With the Postulated Rupture of Piping ..... 3-1" 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 PLmp and Valve Operability ........................... 3- b River Bend SSER 3 dit V

- - ~ . - - - _.- -_ -- .-- . _ _ -

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CONTENTS (CORTIs0ED)

P, age 4 REACTOR ............................................................ 4-1 4.6 Functional Design of Reactivity Control Systems .............. 4-1 5 REACTOR COOLANT 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 ............................................ 5b 6 ENGINEERED SAFETY FEATURES ......................................... 6-1 6.2 Containment Systems .......................................... 6-1 6.2.1 Containment Functional Design ........................ 6- I 6.6 Inservice Inspection of Class 2 and 3 Components ............. 6- 1 6.6.3 Evaluation of Compliance With 10 CFR 50.55a(g) ....... 6-1 7 INSTRUMENTATION AND CONTROLS ....................................... 7-1 7.2 Reactor Protection System .................................... 7-1 7.2.2 Specific Findings .................................... 7-1 7.3 Engineered Safety Features Systems ........................... 7- Y 7.3.2 Specific Findings .................................... 7-t/

River Bend SSER 3

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1 CONTENTS (CpliTiNUED)

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7. 6 Interlock Systems Important to Safety . . . . . . . . . . . . . . . . . . . . . . . . 7- 6 7.6.2 Specific Findings .................................... 7- $

7.7 Control Systems .............................................. 7- 7 7.7.2 Specific Findings .................................... 7- 7

\iN 8 ELECTRIC POWER SYSTEMS ............................................. 8-1 8.3 Onsite I ri;r.:)YPower Systems ............................... 8-8.3.1 AC Power System [.................................... 8-8.3.2 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 .......... 8-8.4.6 Non-Safety Loads on Emergency Sources ................ 8-9 AUXILIARY SYSTEMS .................................................. 9-1 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 u

CONTENTS (CpHTINUED)

Pa2!

9.3.3 Equipment and Floor Drainage System .................. 9-3 9.3.5 Standby Liquid Control System ........................ 9If 9.4 Air Conditioning, Heating, Cooling, and Ventilation Systems ...................................................... 98 9.4.1 Control Building Ventilation System (Control Room Area Ventilation System) ........................ 9- f 9.4.6 Miscellaneous Building Heating, Ventilation, and Air Conditioning (HVAC) Systems .................. 9- 5 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 TEST PROGRAM ............................................... 14-1 15 TRANSIENT AND ACCIDENT ANALYSIS .................................... 15-1 15.4 Reactivity and Power Distribution Anomalies .................. 15-1 15.4.2 Rod Withdrawal Error at Power ........................ 15-1 15.4.7 Operation of a Fuel Assembly in an Improper Position--Fuel Misloading Event ...................... 15-1 18 HUMAN FACTORS ENGINEERING .......................................... 18-1 River Bend SSER 3 viri

CONTENTS (C0dI50ED)

APPENDICES APPENDIX A CONTINUATION OF CHRONOLOGY OF NRC STAFF RADIOLOGICAL REVIEW 0F RIVER BEND STATION 1

APPENDIX B BIBLIOGRAPHY

, APPENDIX 0 ACRONYMS AND INITIALISMS APPENDIX E PRINCIPAL STAFF CONTRIBUTORS l APPENDIX L PRESERVICE INSPECTION RELIEF REQUEST EVALUATION i

l APPENDIX M TECHNICAL EVALUATION REPORT: REVIEW AND EVALUATION OF TRANSAMERICA DELAVAL, INC., DIESEL ENGINE RELIABILITY AND l 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 l

REVIEW FOR GULF STATES UTILITIES COMPANY RIVER BEND STATION l

FIGURE 2.4 Plant boundary and exclusion area for River Bend Station (revised from SER) ................................................ 2-2 TABLES l

1.3 Listing of outstanding issues ...................................... 1-1.4 Listing of confirmatory issues ..................................... 1-1.5 Listing of license conditions ...................................... 1-River Bend SSER 3 vii l '

CONTENTS (CONTINUED)

!Laat 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 7.1 Safety-related air conditioning units, unit coolers, and area serviced ........................................................... 7-4 f,t .ItemsrWcn.r,ir,d/l.,rin6!uSiCYil'hI28i'fSti-(f SkHcm sbabg diesel Sur Willsi.cc pir n . . , ,<' A*

River Bend SSER 3 v4++

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1 2 SITE CHARACTERISTICS i 2.1 Geography and Demography 2.1.1 Site Location and Description i 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 I 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-l 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.

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4 River Bend SSER 3 2-1

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1 J 6 3 DESIGN CRITERIA FOR STRUCTURES, SYSTEMS, AND COMPONENTS 2

3.6 Protection Against Dynamic Effects Associated With the Postulated Rupture I of Piping pkmt DM90 fh ,

3.6.1 Protection Against .,........ m.._ .. . . _ _

A Rupture of Piping (Ottt ude CentWemt3.____ _. ... ... Postulated

) In its SER, the staff stated that the applicant's analysis indicated that the j main steam isolation valve (MSIV) closure would be expected to terminate the j blowdown from a main steamline break within 5.5 seconds. Furthermore, the applicant was to provide detailed information from this analysis for staff re-i 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 MSIVs 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 af ter a high-energy-line break (HELB). By letter dated Jun Me985, the applicant has

, subsequently provided the additional information. The 4taff reviewed the infor-mation and performed an independent analysis of the sub(compartment environmen- /

4 tal conditions following a HELB. Staff analysis indicates that the applicant has appropriately determined the subcompartment conditions by predicting more j

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 i flooding resulting from moderate-energy-line cracks. The applicant has now completed its analyses and has provided the results in FSAR Amendment 21. The i 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 4

- _. = _ - - . _ . _ . - - .

ASB 3-1 in evaluating the effects of high- and moderate-energy pipe failures and the guidance of Regulatory Guide (RG) 1.29 (Rev. 3), Position C.2, as l 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.

l On the basis of the above evaluation, the staff concludes that the design of I the facility meets the requirements of General Design Criterion (GDC) 4, with l

regard to protection against environmental conditions and 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 Postulated 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 outsida 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. l l

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 i 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.  ;

1 A flow transient analysis was perforned using the computer program WATHAM to determine the forcing functions associated with the reverse flow condition during a postulated pipe break. The hydrodynamic torque exerted on the valve l disk by the reverse flow was applied to determine the valve closing time and the impact speed of the disk onto its seat.

l l A stress analysis was performed to determine the ability of the feedwater isola-i 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- i

! water check valves is maintained. l On the t, asis of the results of the applicant's analysis confirming the ability i

of the feedwater isolation check valves to perform their intended function fol-

! lowing a feedwater line break outside containment, the staff concludes that the l l 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 L____-____-____-__

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, 3.7.3B, 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 adequacy 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 methodologies 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, 3.7.3B, 3.9.2A, 3.9.28, 3.10A, and 3.108 and visited the plant site from October 29 through November 2, 1984. 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 balar,ce of plant (B0P) 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 The was followed by a review of the corresponding qualifi-field installation of the equipment was inspected in cation documents.

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 River Bend SSER 3 3-3

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-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 3.2.

(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 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 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 left 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 power licenses are subject to the following conditions:

(1) The full-power license is conditioned upon the applicant modifying all hydraulic control units during the third refueling outsge. 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. _ v, J, (3) Thelowpowerlicenseiscondj 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 AOS 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 th 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

1 3.10.2 Pump and Valve Operability 3.10.2.1 Introduction To ensure that an applicant has developed and implemented a program regarding 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 I 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 guidelines on how to satisfy the requirements of applicable portions of 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.

3.10.2.2 Discussion In performing the first step of the audit, the staff reviewed FSAR Sec-l tion 3.9.3.2. The onsite audit, or second step, was performed by the PV0RT 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),

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-nents 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 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 February 6, 1985 letter.

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-bility assurance. These items are perceived by the staff to be systematic in ;F G nature and they cut across specific equipment items. These item Tare discussed below in Section 3.10.2.3.

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River Bend SSER 3 3-6 l

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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 lon_g 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 l

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has been improved. Additionally, details of the GE and S&W review and i 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 to identify limited life parts and ensure their replacement at appropriate intervals.

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-fied 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.

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l (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-i tional tests completed before fuel load.

The applicant's letter of July 25, 1985, indicates that all preoperational tests are complete. 7,ds 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.

1 (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 j 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 l load falls within the pump and valve area of review. That is the Borg Warner globe valve for which the seismic qualification of the valve actuator remains to be completed.

l The Borg Warner globe valves are covered by a license condition (see Sec- j tion 3.10.1 of this supplement). Thus, there are no outstanding open issues I

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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-Term Operaaility Deep Draft Pumps, IE Bulletin 79-15

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In response to IE Bulletin 79-15, the applicant identified the deep draft pumps

\$g5g 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 4 1 FSAR Section 9.2.7.4. The applicant has used the guidelines endorsed by the f, dp* staff and has completed the performance / endurance testing as indicated in the lD

\g, FSAR.

100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />.

The tests included verification of performance at normal flow for p L Y 5 9,

3-8 River Bend SSER 3 Y

. 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.

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Table 3.1 SQRT findings on seismic and dynamic qualification (revised from SSER 2)

SQRT Applicant Equipment name Status Remarks ID No. and description Safety function Findings Resolution ID No.

1C11*ACTD001 Hydraulic control Translates scram signal The additional brace Qualified to a limited Closed See GSU letter NSSS-1 R8G-20996 dated unit: Assembly con- into hydraulic energy used during qualiff- life based on SRV sists of N2 cylinder, to insert the control cation test of the fatigue test data prior 5/15/85. This water accumulator rod drive and allow its equipment was missing to failure of the hanger is a Itcense and various valves. return flow to discharge from the installed and subsequent addition condition on full-through the exhaust unit. of the second brace. power operation.

valve.

Plant control console: Supports instruments The dynaefc similar- Additional documents / Closed See GSU letter NSSS-2 H13-P680 R8G-20996 dated A U shaped monitoring which are used to ity between the clarifications were monitor and control the tested specimen and provided to show sial- 5/15/85.

benchboard.

safe operation and the River Bend con- larity, test mounting, shutdown of the plant. sole was not estab- and capability g values.

lished.

The tast mounting was not documented in the test report.

For components c,ualif t-cation, the capability g values were not de-fined and demonstrated to envelop the required response spectra over the entire frequency range.

The installation con- The vertical board and Closed See GSU letter NSSS-3 C61-P001 Remote shutdown Provides redundant R8G-20996 dated means for safe shut- dition of being next the adjacent cabinet vertical board are being bolted 5/15/85.

down of the plant. to another cabinet and the wall was not together.

addressed in the qualification.

pe" Assembly is required to Qualification, verified Closed NSSS-4 E1Z-C002A, C RHR pump and motor during audit.

pump water in the sup-pression pool during pool 8 cooling modes and LPCI -~

vessel injection modes.

N p m. s. ,

).

+k _ _ .

Table 3.1 (Continued)

Applicant Equipment name Status Remarks SQRT and description Safety function Findings Resolution ID No. ID No.

Dynaalc similarity Additional documents / Closed See GSU letter NSSS-5 H13-P601 Reactor core cooling Contains instruments NIG-20996 dated bench board: Moni- that are used for manual between the tested clarification were specimen and the provided to show sini- 5/15/85.

toring panel, control for accident larity, test sounting, sitigation of the emer- River Bend unit was gency core cooling not established. capability g values, system. device qualification Test mounting was below 5 Hz, 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 missing.

Controller and recorder units were sliding during tests. It could not be verified free documentation presented whether River Bend panel contains these devices.

Site inspection revealed

• the following:

One unistrut was loose.

GE ERIS terminals were

• very flexible. e Additional documents Closed See GSU letter NSSS-6 H13-P670 Neutron / process Provides information The cabinet was in- RBG-209% dated radiation monitoring about power levels and stalled with %"- were provided to show diameter bolts al- \"-diameter bolts ade- 5/15/85.

system. power distribution in quate for River Bend.

the reactor, and is though the specimen tied to a trip system was tested with 5/8"-

(reactor protection diameter bolts.

system).

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Table 3.1 (Continued)

Applicant Equipment name Resolution Status Remarks SQRT and description Safety function Findings ID No. ID No.

Additional documents Closed See GSU letter H22-PO41, 42 Main steam flow Supports Class IE Transmitters were RBG-209% dated NSSS-7 devices. not environmentally were provided to demon-local panel strate qualification 5/15/85.

aged before seismic testing, of aged transmitters and use or proper Transmitter output calibration.

variation was de-tected during testing apparently incause ' '

incomplete instruc-tion was provided by GE to testing engineers regarding calibration.

GSU/GE is to confire that River Bend in-sta11ation engineers have received the com-plete instruction and the transaltters are properly calibrated.

Adequacy of the Additional documents Closed See GSU letter NSSS-8 821-F0288 Main steam isolation Isolates the steamline were provided to indi- R8G-209% dated upon demand. valve body was not valve cate that the valve 5/15/85.

demonstrated.

body was analyzed sepa-GSU is to confirm rately and to confirm compliance with GE's field modifications.

recommendation regard-ing the following required for quali-fication:

Bracket modifica-tion for limit switch.

Elimination of junc-tion box.

The source of River 8 Bend-specific RRS was

- not presented during the audit.

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Table 3.1 (Continued)

Equipment name Status Remarks SQRT Applicant Safety function Findings Resolution ID No. ID No. and description Qualificatiodverified Closed 1CCP*MOV138 10" motor-operated Is required to isolate during audit.

80P-1 the containment and to valve intercept the water flow of the reactor plant component cooling water system (RPCCW) to the non-regenerative heat exchanger. il cJc" Closed Are required at penetra- Qualified w*

BOP-2 1RCP*TCA03 Termination cabinets tions to contain the de,.) .,4.t ,

wiring used in instru-mentation monitoring and control of equipment used in various safety-related functions.

Additional documents Closed See GSU letter Motor control center: Required to provide Qualification of were provided to quali- RBG-20996 BOP-3 1EHS*MCC devices apparently dated 5/15/85.

A two-bay rectangular Class IE power covered by Gould fy devices; document cabinet containing distribution, reports R-STS-10, 31 test mounting; confirm starters, circuit and analysis was not testing of both ener-breakers, Switches, available for review. gized and deenergized terminal, blocks, etc. conditions; and circuit Testing of mounting breaker qualification was not documented, was included in the documentation package.

It is not clear from test report whether the MCC was tested for 5 OBE and 1 SSE for both the energized and deenergized conditions.

Supplemental eval-uation report for HE 4-3 circuit breakers was not part of the

• qualification docu- i mentation package.

Table 3.1 (Continued)

Applicant Equipment name Status Remarks SQRT and description Safety function Findings Resolution ID No. ID No.

The site inspection Installation deficien- Closed See GSU letter 80P-4 1E12*PC003 Centrifugal fill Maintains the RHR sys- R8G-20996 dated pump: A pump / motor tem piping filled and revealed the following cies were corrected.

deficiencies: 5/15/85.

assembly. ready for main RHR pump starttp.

The shin stack was loose.

One nut in the seal housing was loose and another was missing.

The motor nameplate was missing.

p*

Qualification, verified Closed BOP-5 1HVC*ACU18 Control building air Maintains the control during audit conditioning unit building at design tem-perature and humidity.

TOW D'**

Qualjffee Closed Operates only during Air-operated damper: M*

BOP-6 1HVR*AOD10A It is duct mounted LOCA when it bypasses gM MW and supported from the air to the standby the ceiling gas treatment building.

eJ'e Leakage air system Provides pressurized Quallflee W Closed ILSV*C3A 80P-7 compressor: A single air to containment iso- *%

rotary compressor lation valves to prevent with electric motor release of fission prod-drive ucts after LOCA.

Dynamic similarity Additional documents Closed See GSU letter Transformer Furnishes power to R8G-20996 80P-8 ISCM*XRC14 various Class IE instru- between the tested were provided to jus-specimen and the River tify similarity, test dated 5/15/85.

ments as part of the mounting, anomalies, uninterrupted power Bend transformer was supply system. not established. and site installation. -

Test mounting was not completely documented in the test report.

Test anomalies were

. mentioned, but neither described nor justi-fled in the test report.

i ,

h Table 3.1 (Continued)~.

SQRT Applicant Equipment name Resolution Status Remarks ID No. and description Safety function Findings ID No.

Site inspection re-BOP-8 wealed the following:

(Cont' d)

There was no con-tact between the baseplate and con-crete in most places.

Side panels were loose.

Baseplate was not addressed in the qualification docu-ments presented.

Only a summary of The original test Closed See GSU letter BOP-9 1EJS*LDCIA Load centers Are required to fur- R8G-209%

nish power distribu- test report was report was made avall-tion to HVAC systems in available. The able after the audit. dated 5/15/85.

the control and diesel original Wyle Test generator building and Report is needed also to Class IE motor for review and control centers. documentation.

Torsional frequency Additional documents Closed See GSU letter BOP-10 ISWP*P2B Standby service water Provides cooling water were provided to jus- RBG-209%

pump: An electrical- for safety-related of assembly needs to be computed and com- tify torsional fre- dated 5/15/85 ly driven vertical equipment when normal service water is lost, pared to motor's quency and pump turbine pump. operability.

operational speed.

Operability of pump under seismic load needs to be assured.

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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, i

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 R8G-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 B0P equipment pro-curement specifications were epgraded 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.

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Table 3.2 PV0RT 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 operated gate sponse to either mentation demonstrating qualification by simi-valve (NSSS) a suppression larity analysis extending test results from a i

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 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 Term 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 (NSSS) integrity.

1E12- MOVF021 14" motor- Containment Staff concerns regarding stem leakoff require- Closed operated globe isolation. ments, welding discrepancies, and document issue valve (B0P) 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 operated control room ing serialization procedures have been satisfac-butterfly during LOCA. torily addressed in GSU's March 29, 1985 letter.

valve (B0P) l

/

1 l

' Table 3.2 (Continued)

Findings / resolution Status Plant ID No. Description Safety function Staff concerns regarding serialization discre- Closed 1CCP-MOV138 10" motor- Outboard con-operated tainment iso- pancy, stroke time, stem leakoff, space heaters, gate valve lation valve. and checkout procedure revisions have been satis-factorily addressed by GSU in the March 29, 1985, (BOP) letter and the May 10, 1985, Bethesda audit.

Closed B21-A0VF.32A 20" check Containment iso- Satisfactory.

.l valve (B0P) lation and

reactor cool-ant pressure boundary.

Staff concerns regarding an installation error Closed E33-SOV14 2" solenoid- Provides initial noted during site audit, opening air pressure, operated globe pressurization valve (80P) 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.

Staff concerns regarding the use of manufac- Closed E12-C002C RHR pump Supplies water to the core in turer's acceptance criteria, reject and accept-(NSSS) ance tags, serialization discrepancy, conformance the event of an accident. to IEEE standards, and age-sensitive components have been satisfactorily addressed in GSU's Suppression March 29, 1985, letter and the May 10, 1985, l pool cooling. Bethesda audit.

Staff concerns regarding effects of using sup- Closed E12PC003 RHR sub- Maintains RHR 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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A

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3 I D P3. //

cv-, , -- - - , . - , - -,.

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).

3.10.2 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 The first step is a re-Qualification Branch (EQB) performs a two-step audit.

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.

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),

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-The SRP Section 3.10 provides detailed guide-ment" of the Standard Review P.lan.

lines on how to satisfy the requirements of applicable portions of 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.

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1 RIVER BEND SER SEC 3.10 INPUT 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 A sample of three Company (GSU) meets the criteria of Sect ion 3.10 of the SRP.

MSSS 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-ters operability program (s), etc.).

A post-audit meeting with the staff and the utility (GSU) and Stone & Webster and General Electric was held at the Nuclear Regulatory Comm'ission 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 In addition to resolution of equipment specific items resulting from the audit.

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 l The generic items determined during the site audit are listed below with their resolution and status.

1 i

2 RIVER BEND SER SEC 3.10 INPUT j

07/29/85

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, capability, and qualification information of the actual equipment. The applicant is to develop a more systematic program to perform'the accep-tance review of safety-related pumps and valves. y Re olution: The applicant has demonstrated during 't ;;;;t =ditImeetings i et,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: In the applic nt's letter of March 29, 1985, reference is made to a November 8, letter (RBS-19,377) directing SWEC to per-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 SWEC to develop a procedure to address the ongoing review of qualifica-tion documents for maintenance and surveillance requirements.

Status: Closed.

3. Procedures should be established to return tested equipment to its qualified status.

07/29/85 3 RIVER BEND SER SEC 3.10 INPUT u

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! b Resolution: The applicant in the March 29, 1985 letter and the May 10, i 1985 audit at Bethesda provided additional information and documenta-tion demonstrating the adequacy of the existing procedures.

Status: Closed.

Components were found to be incorrectly or improperly installed. Pro-1 4.

cedures should be established verifying equipment installation require-ments and qualification.

Resolution: The applicant's response in the March 29, 1985 letter and

• p the subsequent audit M ,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 i

! 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.

. 'i F-Status: Applicant's letter of July 22, 1985 indicates that of all the ll safety-related pumps and valves, only the Borg Warner globe valve All actuator will be seismically qualified after the fuel load.

.i other pumps and valves are scheduled to be qualified prior to fuel ll loading. The seismic qualification of the Borg Warner globe valve is addressed in Section 3.10.1 of this report. In theirletter of 4

July 26,1985, the applicant confirmed that all pumps and valves important to safety have been qualified. This issue is closed.

4 RIVER BEND SER SEC 3.10 INPUT 07/29/85

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e

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.

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.

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 resolved and are discussed in the Table 3.10.2.1. In a letter from Booker to _

Denton, dated July 22, 1985, the applicant has stated that there are only four dofequipae that will not be qualified prior to fuel loading. Only one of the four items to be qualified after fuel load is related to pump and valve operability qualification. That item, the Borg Warner globe valve, requires

- completion of seismic qualification of the valve actuator.

1 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 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 Part 50, Appendix B to 10 CFR Part 50, and Appendix A to 10 CFR Part 100.

1

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5 RIVER BEND SER SEC 3.10 INPUT 07/29/85

~3 10 2-S Lena Term Operability Deep Draft Pumps - IE Bulletin 79-15 In response to the IE Bulletin 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 FSAR. 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.

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07/29/85 6 RIVER BEND SER SEC 3.10 INPUT

h ,

Table 3.10.2.1 Audit Findings. Page 1 of 4 O"

Status Plant 10 No. Description Safety Function Findings / Resolution i -

v b Applicant resolved Closed E22-F015 20-inch motor Open in re-i operated gate sponse to earlier concerns by valve (NSSS). either a sup- providing documenta-pression pool tion demonstrating i high-level sig- qualification by sini-nel or a low larity analysis ex-i condensate tank tending test results level - con- from a similar 24-inch tainment isola valve.

tion.. .

ISWP-P2A Standby ser- Provide

• cool Applicant provided ad- Closed

vice water ing water for ditional documentation pump (80P). safety-related and analysis results equipment if at the May 10, 1 .

' normal service Bethesda e iii.w- ster water is lost. sponding to staff con-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 i

Operability of Deep

' Draft Pumps (IE Bulle-tin 79-15) concerns g4 -

for this pump %

staff review as noted I in the February 6, 1985 letter to GSU from the NRC.

i .

Table 3.10.2.1 Audit Findings. Page 2 of 4 i

Plant 10 No._ - Description Safety Function Findings / Resolution Status Remark [ D @-

20-inch flow Maintain

• pres- Satisfactory. Closed 833-F060A control sure boundary l

valve integrity.

(NSSS).

14-inch motor Containment Staff concerns regard-1 1E12-MOVF021 operated isolation. ing stem leakoff re-globe valve quirements, welding J

(80P). discrepancies, and K document issue dates Closed have been satisfac-torily addressed in the applicant's letter li of March 29, 1985 and during the Bethesda May 10, 1985 audit.

24-inch MD Isolate main Serial no. discrepancy 1HVC-MDV1B butterfly control room and staff concerns re-valve (BOP). during LOCA. garding serialization l procedures have been Closed satisfactorily ad-dressed in the appli-cant's March 29, 1985

} letter.

4 10-inch Outboard con- Staff concerns regard- Closed ICCP-MDV138 l motor oper- tainment iso- ing serialization dis-l

! ated gate lation valve. crepancy, stroke time, -

stem leakoff, space ,

valve (BOP). heaters, and Checkout Procedure revisions f; have been satisfactor-11y addressed by the applicant in the March 29, 1985 letter and t

Table 3.10.2.1 Audit Findings. Page 3 of 4 o

Description Safety Function Findings / Resolution Status Remarks Plant 10 No.

the May 10, 1985 at Bethesda. 'sT#

20-inch Containment Satisfactory. Closed B21-A0VF32A check valve isolation and (80P). reactor cool ent pressure boundary.

2-inch Provide ini- Staff concerns regard- Closed E33-50V14 solenoid tial pressuri- ing an installation operated zation of main error noted during globe valve steam positive site audit, opening (80P). leak control air pressure, spring

^

system. closure forces, and air quality have been satisfactorily ad-dressed in the appli-4 cants March 29, 1985 letter and the May 10, 4

1985 Bethesda audit.

RHR pump Supply water to Staff concerns regard Closed

E12-C002C (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, conforinance to IEEE, -

and age sensitive com-ponents have been sat-isfactorily addressed in the applicant's March 29, 1985 letter and the May 10, 1985 Bethesda audit.

. s Table 3.10.2.1 Audit Findings. Page 4 of 4 .

o Description Safety Function Findings / Resolution Status Remarks Plant 10 No.

RHR - sub Maintain RHR Staff concerns regard Closed.

E12PC003 system fill system piping ing effects of using puap (80P). 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

3.10 Seismic and Dynamic Qualification of Safety-Related Electrical and Mechanical Equipment 3.10.1 Seismic and Dynamic and Qualification 3.10.1.1 Introduction As part of the review of the applicant's Final Safety Analysis Report (FSAR)

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 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 judgement of the completeness and adequacy of the seismic and dynamic qualification program.

Guidance for the evaluation is provided by the Standard Review Plan (SRP)

Section 3.10, and its ancillary documents, Regulatory Guides (R.G.) 1.100, 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- l

'ormance 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 performed by a Seismic Qualification i l

whichengineers fr : of^S+sH th. E46ipeent Quattf1 cation I Review Team (SQRT) cus*UsJs h** consists 1.;nch (N^C/EQG) and,the Brookhaven National Laboratory (BNL, Long Island).

3.10.1.2 Discussion l The SQRT has reviewed the equipment seismic and dynamic qualification informa-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 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 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 Summary of 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 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 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 1

i 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.

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

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 applicant ,

was to develop a more systematic program to perform the acceptance review of all safety-related equipment. f

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 k 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

4. There were, equipment p+eees found to be incorrectly or improperly installed. l Thc applicant was to develop a procedure to check proper mounting of all safety-related equipment consistent with the qualification mounting con-figuration.

yieces of

. - - 5. It was observed that for manygequipment the enclosure panel was partially removed or screws were loose reportedly in order to facilitate preopera-tional testing. The applicant was to develop a procedure to insure that L 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.

(

3.10.1-3 RIVER BEND SER SEC 3.10.1 07/26/85 L ._ '

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l 7. The qualification of those pieces of equipment which were originally quali-I fled to meet IEEE Std 344-1971, should be identified and upgraded to meet l

l 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.

1 l

3.10.1.5 License Conditions Me fo#suig4*cere e :kernse conofd'en wi// de hcogookablkA S bh05<

ope +a frnp The River ":nd rnal Lord, L:; I;wer :nd N11 P:wcr License e re 5_.bj t to th- 6 ,

~

i

'011:e ng conditient:c 0 -

applica.d sbo,N., prico -l0 SUup N0"'Inf  ; f' >*

1. Theg 11 P:u:r Licen: is conditi;ned spen t;,, .yplicent ;;;difying =11 hydraulic control units.during th: th'rd rek !'n; cutege. The modifica-tion consists of installing the additional brace used during the qualifi- i 6

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 1(fe based on SRV fatigue test data.

S kJI, prior. 4c erceeding Ge peread rated powen perk

2. The Lee Peu:r Licen:; is cenditien.J oyen the applicant p;rfer;;;ing an I independe t internal audit of seismic qualification documentation and MPt*t 7 pe, tin g results to the staff,pri;r t; exceeding 5% pv- r. Issues iden-tified by the audit must be resolved to the staff's satisfaction prior to exceeding 5% power.

g;J < 0.00 , prior k eyceediq fi" P***I '**'N P'*$ '** PW W l

l 3. The,L; In::r Li :n;; is Gnditi:n d ;;r the ea=1-tien, ^ the seismic qualification of panel board IENB*PNLO4A, prier tv wm.wwding 5% p; ;r

-- m H

n - Low power operation prior to completion of qualification is justified based on similarity of the unqualified panel board to other panel boards which have been qualified for River Bend requirements.

aprued stodt, prier -ia eyceed;ng he. pea:a.J ra.holpowew, completo

4. The Lee Peeer License is renditi:n;d up;n th; c g p1=i.ivo ef the seismic qualification of the HPCS Diesel Generator, prier te au.. ding 5% r ewe 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

f l

HPCS Diesel Generator is justified because the Automatic Depressurization System (ADS) is redundant to the HPCS system. The ADS is fully qualified.

mlid M , prior k epe% Spercs-tp W pouse", conpLete 4

5. The,Lcw P; cr L' cense 1: :enditiened uper th: :::pictier:Neismicquali-fication of Borg Warner globe valves purchased under GSU siiecification No. 247.97, prier t: :nce: ding ;% power. Low power operation prior to com-pletion of seismic qualification is justified because of similarity between the valve actuators 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, appliM dalig doNP CYC-- I

6. The 3 Lcw ";wer and I:1' ": ;r Licen;;s ere ;;nditi;ned up;n th: ::;picti:n ad the seismic qualification of the In-Vessel Rack (MPL No. F16-E006) its prior to,use.derin;; the fir:t 7:ft:'a; eute;;e. The In-Vaas.1 ".::P tha' W bc ;tei wa iii Lii= pl nt ei wiiouse priv. iv wumpier. ion of seis M '

qe:14'icatica. d -

e Se l

l l

l l

l l

07/26/85 3.10.1-5 RIVER BEND SER SEC 3.10.1

)

l l

l

n Table 3.10.1.1 S

bw D Equipment Name

• SQRT Appiteent and Description Safety function Findings Resolution Status Remarks ID No. ID No.

1C11*ACTD001 Hydraulic Control Translates scram signal The additional brace Qualified to a limited Closed See GSU letter NSSS-1 R9G-20996 dated Unit. Assembly con- into hydraulle energy used during qualift- 11fe based on SRV fatigue test data prior 5-15-85. This sists of Na cylinder, ,to insert the control cation test of the is a License water accumulator rod drive and allow its equipment was missing to failure of the hanger and various valves. return flow to discharge from the installed and subsequent addition Condition on Full through the exhaust unit, of the second brace. Power Operation.

valve.

Plant Control Console. The console supports 1. The dynamic sin- Additional documents / Closed See GSU 1etter NS$$-2 M13-P680 R8G-20996 dated A U-shaped monitoring instruments which are 11arity between the clarifications were used to monitor and tested specimen and provided to show sini- 5-15-85.

benchboard.

control the safe opera- the River Bend con- 1erity, test mounting, w tion and shutdown of sole was not estab- and capability g-values.

- the plant. 11shed.

2. The test mounting l [ was not documented a

'

• in the test report.

3. For components qualification, the capability g-values were not defined and demonstrated to en-velop the RRS over the entire frequen-m cy range.

c It provides redundant The installation con- The vertical board,and Closed . See GSU 1etter E NSSS-3 C61-P001 Remote Shutdown R9G-20996 Jated means for safe shut- dition of being next the adjacent cabinet g Vertical Board ,

5-15-85.

down of the plant, to another cabinet are being bolted g and the well was not together.

addressed in the h qualification.

N n

i' a

t  ;

e Table 3.10.1.1 (Continued) k

$ SQRT App 1tcent Equipment Name

ID No. ID No. and Description Safety Function Findings Resolution Status Remarks NSSS-4 E12-C002A.C RHR Pump and Motor The assembly is required QtaliAca.h'on  ;--m >==:e to pump water in the sup-pression pool during pool Ver1Real during d**Y~

g"g cooling modes and LPCI u vessel injection modes.

MS$5-5 H13-P601 Reactor Core Cooling It contains instruments 1. Dynamic sinflarity Additional documents / Closed See GSU 1etter Bench Board. A 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 sist- 5-15-85.

mitigation of the emer- River Bend was not larity, test mounting, gency core cooling established. capability g-values, system. 2. Test mounting was device qualification i., not completely docu- below 5 Hz, controller mented in the test and recorder informa-

.O report. tion, and installation T* 3. For component correction.

" qualification, the capability g-values were not defined and demonstrated to envelop the RRS over the entire frequency range.

4. Qualification of some devices below 5 Hz was missing.

5 5. Controller and 5 recorder units were ,

" sliding during tests.

E It could not be veri-d ffed from documentation vi presented whether River 9 Bend panel contains un these devices.

n O

o Table 3.10.1.1 (Continued)

S N

b* SQRT App 1tcant Equipment Name Status Remarks and Description Safety Function Findings Resolution ID Mo. ID No.

6. Site inspectfon NSSS-5 revealed the following:

(Cont'd) a) One unistrut was loose.

b) GE ERIS terminals were very flexible.

The cabinet was in- Additional documents Closed See GSU letter MSSS-6 H13-P670 Neutron / Process Provides information R9G-20996 dated Radiation Monitoring about power levels and stalled with 1/2" provided to show in.

diameter bolts al- dia. bolts adequate 5-15-85.

System. power distribution in the reactor, and is though the specimen for River Bend.

tied to a trip system was tested with S/8" (Reactor Protection diameter bolts.

w

• System).

P 1. Transmitters were Additional documents Closed See GSU letter 7' NSSS-7 H22-PO41,42 Main Steam Flow It supports Class 1E R8G-209% dated

" devices not environmentally provided to demonstrate Local Panel 5-15-85.

aged prior to seismic quellfication of aged testing. transmitters and use

2. Transmitter output or proper calibration.

variation was de-tected during testing apparently due to incomplete instruc-tion provided by GE to testing engineers 3 regarding calibration. .

N

" GSU/GE is to confim '

" that River Bend in-staiiation engineers 5 have received the com-plete instruction and 9 the transmitters are properly calibrated.

E O

t e

Table 3.10.1.1 (Continued)

S

$ SQRT App 11 cant Equipment Name Safety Function Findings Resolution Status Remarks

• ID Mo. ID Mo. and Description Main Steam Isolation It isolates the steam 1. Adequacy of the Additional documents Closed See GSU letter MSSS-8 821-F0288 Valve line upon demand. valve body was not provided to indicate RBG-20996 dated demonstrated. that the valve body 5-15-85.

2. GSU is to confirm was analyzed separately compliance with GE's and to confirm field recommendation regard- modifications.

ing the following required for qua11-fication:

a) Bracket modifica-tion for Limit Switch.

b) Elimination of junc-tion box.

w*

3. The source of River

.O bend specific RRS was 7 not presented durfng the

• audtt.

80P-1 1CCP*MOV138 10" Motor Operated The valve is required QualifiCAk b ;iii.J -

Valve to isolate the contain-ment and to intercept Verifid g . aua(3 (bM the water flow of the reactor plant component cooling water system (RPCCW) to the non-E regenerative heat

% exchanger. .

1RCP*TCA03 6%ek Termination Betrtes- The cabinets are required QuobCierke" '

W

% BOP-2 at penetrations to contain Vfdit 5

w the wiring used in instru- M* M.*h bo6k 9 mentation monitoring and I w

control of equipment used in various safety related R functions.

w

e Table 3.10.1.1 (Continued) o s"

M

'm SQRT Appilcant Equipment Name Safety Function Findings Resolution Status Remarks

• ID Mo. ID No. and Description

1. Qualification of Additional documents Closed See GSU letter B0P-3 IEHS*MCC Motor Control Center. MCC is required to pro-R8G-209%

A two-bay rectangular vide Class IE power devices apparently provided to qualify cabinet containing distributton. covered by Gould devices; document test dated 5-15-85.

starters, circuit reports R-STS-10,31 mounting; confirm test-breakers, switches, and analysis was not ing of both energized teminal, blocks, etc. available for review. and de-energized condi-

2. Testing mounting tions; e M inclusion of was not documented. circuit breaker qualift-

3. It is not clear cation in the documenta-from test report tion packagt.

whether the MCC was tested for 5 OBE and 1 SSE for both the energized and de-o"

- energized conditions.

' 4. Supplemental eval-o untion report for HE 4-3 circuit breakers was not part of the qualification docu-mentation package.

It maintains the RHR The site inspection Installation deficien- Closed See GSU letter B0P-4 1E12*PC003 Centrifugal fill system pfptng filled and revealed the following cies were corrected. R8G-209% dated

o pump. A pump / motor 5-15-85.

2 assembly, ready for main RHR pump deficiencies:

9 startup. 1. The shim stack was loose. .

a G 2. One nut in the seal '

" housing was loose and another was missing.

M

" 3. The motor name plate was missing.

M n

e O

I '

4 Table 3.10.1.1 (Continued)

O h

b SQRT Applicant Equipment Name ID No. ID No. and Description Safety Function Findings Resolution Status Remarks 80P-5 IHYC*ACU18 Control building air It maintains the control hatlibcANo~ Qualified conditioning unit. butiding at design tem- yp; ped (f,ggof perature and humidity. A,.; Mib 90P-6 1HVR*A0010A Air operated desper. It operates only during y Quetttted It is duct mounted LOCA when it bypasses and supported from the air to the Standby g*

the ceiling. Gas Treatment Butiding.

80P-7 ILSV*C3A Leakage Air system It provides pressurized QarTT7Ed compressor. A single air to containment iso- ##

rotary compressor lation valves to prevent gl,3 coq w with electric motor release of fission pro-

., drive ducts after LOCA.

7 BOP-8 15CM*MRC14 Transformer It furnishes power to 1. Dynamic stellarity Additional documents Closed See CSU letter O various Class IE instru- between the tested provided to justify R8G-209%

ments as part of the specimen and the River similarity, test dated 5-15-85.

Uninterrupted Power Bend transformer was mounting, anomalles, Supply System. not established. and site installation.

2. Test mounting was not completely docu-mented in the test report.

= 3. Test anomalies were mentioned, but neither described nor justi-9 fled in the test g report. '

g 4. Site inspection re-u, vealed the following:

9 a) There was no con-u, tact between the base E plate and concrete in w

most places

~

o

f Table 3.10.1.1 (Continued)

S N.

v Appiteent Equipment Name Resolution Status Remarks 3 SQRT and Description Safety Function Findings ID No. ID No.

b) Side panels were 90P-9 loose (Cont'd) > c) Base plate was not addressed in the quali-fication documents presented.

Only a summiery of The original test Closed See GSU letter IEJS*LDCIA Load Centers They are required to report was made avail- R8G-209%

90P-9 furnish power distribu- test report was able after the audit. dated 5-15-85.

tion to HVAC systems in available. The the Control and Diesel original Wyle Test Generator Building and Report is needed also to Class IE Motor for review and w documentation.

Control Centers.

j

'g See GSU letter Additfonal documents Closed Standby Service water it provides cooling wa- 1. Torsional fre- R9G-20996 80P-10 ISWP*P29 ter for safety related quency of assembly provided to justify N pump. An electrical- needs to be computed torsional frequency dated 5-15-85 Iy driven vertical equipment when normal and compared to and pump operabllity, turbine pump, service water is lost. motor's operational speed.

2. Operability of

• pump under seismic load needs to be assured.

5 9

f*1 5

i M

=

t's n

5 o

i .

Table 3.10.1.2 o

b Generic Issues l i R

! 3 Generic

• Issue No. Resolution Status Remarks l

e 1, 2 During a meeting between staff and applicant Confirmatory See GSU letter

! RBG-21093, 5-24-85.

j in Bethesda on June 10, 1985, the applicant demonstrated improvement of their qualifica- This is License 1

j tion documentation and review program. The Condition for applicant is committed to perform an inde- exceeding 5% power.

3 pendent internal audit and report the results

l to the NRC prior to exceeding 5% power.

J 3 The applicant has developed a procedure to Confirmatory See GSU letter l RBS-19377, 11-8-84.

perform a review of all qualification l documents and extract the preventive main- Effectiveness to w

tenance requirements necessary for the be verified in a future audit.

g qualification, I w Closed 4 4, 5 During a meeting between staff and applicant w in Bethesda on May 10, 1985, the applicant 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 GSU letter of the as-built piping analysis, and con- RBG-21575, 7-19-85.

f,

" cluded that g-values obtained from the

$ analysis are not higher than the g-values i g used to qualify the equipment. .

During the May 10 meeting in Bethesda, the Closed '.

h 7 applicant showed that all BOP equipment

! y, l

R procurement specifications were upgraded to the IEEE 344-1975 requirements.

i w N

j P *See section 3.10.1.4 of this SER for statement of issues.

w 5

l.

-_--___ _- - --_ __-_ _ - - _ - - _ . _ _ - _ _ _ - - - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ - - - _ _ - ____m__-.__-----_m._ _ -----__-m___ _--__.--- - _ _ - _ _ _ _ - __ ___ _ _ -

' e .

Table 3.10.1.2 (Continued)

O hun

! 5 Generic

• Issue No. Resolution Status Remarks

.t vi 8 The applicant is committed to confirm Confit1aatory See GSU letter completion of qualification of all RBG-20594 3-29-85.

safety-related equipment.

I l

O L

d i

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!E l *

! 5 ,

1 ,

m m -

.i rr,

, n

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3103 r!:.EsSa.fe) a-ol Relief Valve (rmr twTesfing zt.b.1)

Me s4aff wM A assisk afcaduHa h Au. Es,c .:<L ., &

< Aas cqlefeel ils review af inka/r% .submilled

.by M.e g ea d 1 A cone feskn y of'

& relief vs/ves he 8'ver Banal I. 'tk e.

~

safe) rfaff finds% inkdtn submilled demon afra./e.s fAe ability af %. reaak. coolan F sysk rebef undes eppec /eo/

a<d sa.feG va./ves la G<ne/ro'n yerahng condi/r'an.s L e4estp-ba. sis a -fra.ssieJ.s

and accidenis as deRned un6 fniz w Hu

.2r b . L . M de lu.i Is al' Mss review an u:sA,ded A A :pe+d4k _

/ _.

?

1

Ae Quo},'hea.M o f

.g. to. 2. 7 Veb'f;&(y+h(rmr;%2Z'K420 mt c

SAFETY EVALUATION TMI ACTION PLAN II.K.3.28 VERIFY QUALIFICATION OF ACCUMULATORS ON ADS VALVES RIVER BEND STATION UNIT 1 _

DOCKET NO. 50-458 3 10. 3. 7. I

% BACKGROUND g ger Safety Analysis Reports aim that air r nitrogen ccumulators 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

• 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.

3 10. 42. 7. a.

4 DISCUSSION The commitment 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. s B. Galf States Utilities Company letter from J.E. Booker to H.R. Denton, NRC, dated May 13, 1985.

3,/0.a.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. Eacn 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 i

are supplied from the Penetration Valve Leakage Control System (PVLCS), a nuclear safety related Seismic Category I system.

_ . _ _ _ . - . _ _ _ ._ , _ . . _ . . _ . , . _ _ _ , . - _ _ _ _ _ _ _ _ _ ___ _ _ . . _ , , , , . . _ , . . . _ . .~-.

_ _ . . _ . _ . __. __. _=_ _____ __ _ ___ _ - _ _ _ _ _

i I .

The realignment from the main steam system air compressors to the PVLCS is ~

performed by the plant operators from the main control room.

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 SCFH.

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.

1 sh. tot be hcerpeW i& R B5 ~ 8 +8fDlc.hs

...........y... ._

..n 8urveillance reautrementL associated with the ADS _;p

• m-l I"5 j accumulatorsystemandbackupsystemhcri't;thatthePVLCSaccumulato sure is greater than 101 psig.et h::t ::: pe 24;-,5. ,

The allowable leakage rate of 1 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.

l 2 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. i

~ l

} .10 . 2 o 7. '{ l 4

3. EVALUATION 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 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 supplies. The applicant has pr;;fd:d : it:t.-:.t :-'fyint that the ADS accumulators have sufficient inventory to assure operability of the ADS valves during this 20-minute interval, gg The accumulator on each ADS valve has a 60-gallon capacity which is designed for two actuations at 70 percent of drywell design pressure. This capability is equivalent to 4 to 5 actuations at atmospheric pressure.

.- . . ~ - , - . - . ----_.--_-.--_---_w_.---__---___-..--.-_.-- - -

The staff concludes that the applicant has demonstrated the long and short tenn capability of the automatic depressurization system and isb if ,

therefore acceptable.

M he applicant states that the allowable leakage rate of 1 SCFH is W l compatible with the ECCS performance avaluations and assumptions, and th O

calculations for sizing the ADS air supply. Therefore, .____......, . . 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.

dThe applicant has provided information acceptable to the staff hdicativedescrbj

.e4 the development of surveillance, maintenance, and leak testing programs for the ADS accumulator system and associated alarms and instrumentation.

[ 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.

3Jo,,1.7.c

-@ CONCLUSION Based on the information provided by the applicant summarized in Section 5 3.lo.a.~13 and the evaluation performed highlighted in SectionA the staff concludes that the40 u" Stoio; 'Jtilities C::p=y has verifiejTqualification of the raccumulatorhifon ADS valves for River Bend StatiorhUnit 1, thereby satisfying i the requirements of TMI Action Item II.K.3.28. g 3,lo.2 .7.8/

l l

Safety Evaluation Report Office of Nuclear Reactor Regulation Equipment Qualification Branch Docket No. 50-458 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 life 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 III, 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-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-neers (IEEE) Standard 323; and various NRC Regulatory Guides (RGs) and industry standards.

3.11.2 Background NUREG-0588 was issued in December 1979 to promote a more orderly and systematic implementation of equipment qualification programs by industry and to provide guidance to the NRC staff for its use in ongoing licensing reviews.

The positions contained in that report provide guidance on (1) how to establish environmental service conditions, (2) how to select methods that are considered l 07/24/85 3-1 RIVER BEND SSER 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 79-01B, " Environmental Qualification of Class 1E 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 1

j 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 l

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 f .

! to safety located in a harsh environment. In conformance with 10 CFR 50.49,

'alectrical equipment for River Bend Station (RBS), Unit 1 may be qualified i according to the criteria specified in Category 1 of NUREG-0588.

The qualification requirements for mechanical equipment are principally con-l tained in Appendices A and B of 10 CFR 50. The qualification methods defined

]II

• in NUREG-0588 can also be applied to mechanical equipment.

.i-i j

To document the degree to which the environmental qualification program complies with the NRC environmental qualification requirements and criteria, the appli-l cant provided equipment qualification information by letters dated March 1,

! October 19, and December 14, 1984, February 15, March 12 and 15, April 26, May 13, June 19, and July 19, 1985, to supplement the information in the FSAR l

Section 3.11.

' The staff has reviewed the adequacy of the RBS environmental qualification pro-gram for electrical equipment important to safety as defined in 10 CFR 50.49 The scope of this and the program for safety-related mechanical equipment.

3-2 RIVER BEND SSER SEC 3.11 INPUT 07/26/85

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 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 submittals 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 the requirements in 10 CFR 50.49 form the bases for the staff evaluation.

The staff performed an audit of the applicant's qualification documentation and installed 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 Important to Safety

{

t q

10 CFR 50.49 identifies three categories of electrical equipment that must be

! qualified in accordance with the provisions of the rule.

1 -

(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).

3-3 RIVER BEND SSER SEC 3.11 INPUT 07/26/85

. - - _ - . - - _. .__ .. --- .. _ _ _ - _ _ _ _ _ ._. __