ML20205F891

Safety Evaluation Authorizing Licensee Requests for Second 10-year Interval for Pumps & Valves IST Program

ML20205F891
Person / Time
Site:	Hope Creek
Issue date:	03/18/1999
From:	NRC (Affiliation Not Assigned)
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ML20205F881	List: ML20205F877 ML20205F891
References
NUDOCS 9904070050
Download: ML20205F891 (51)

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'2 j NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001

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SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO THE INSERVICE TESTING PROGRAM. SECOND 10-YEAR INTERVAL PUBLIC SERVICE ELECTRIC & GAS COMPANY HOPE CREEK GENERATING STATION DOCKET NO. 50-354

1.0 INTRODUCTION

The Code of Federal Reoulations,10 CFR 50.55a, requires that inservice testing (IST) of certain American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code) (the Code) Class 1,2, and 3 pumps and valves be performed in accordance with Section XI of the ASME Code and applicable addenda, except where alternatives have been authorized or relief has been requested by the licensee and granted by the Commission pursuant to Sections (a)(3)(i), (a)(3)(ii), or (f)(6)(i) of 10 CFR 50.55a. In proposing alternatives or requesting relief, the licensee must demonstrate that: (1) the proposed alternatives provide an acceptable level of quality and safety; (2) compliance would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety; or (3) conformance is impractical for its facility. The Nuclear Regulatory Commission's (NRC) guidance contained in Generic Letter (GL) 89-04, " Guidance on Developing Acceptable Inservice Testing Programs," provides alternatives to the Code requirements determined to be acceptable to the staff. Alternatives that conform with the guidance in GL 89-04 may be implemented prior to receiving NRC approval, but should be included as relief requests for review by the staff. When alternatives are implemented in accordance with the relevant position in the GL, the staff has determined that relief should be granted pursuant to 10 CFR 50.55a(f)(6)(i) on the grounds that it is authorized by law, will not endanger life or property or the common defense and security, and is otherwise in the pub 4c interest, in making this determination, the staff considers the burden on the licensee that would result if the requirements were imposed.

Section 50.55a authorizes the Commission to approve alternatives and to grant relief from ASME Code requirements upon making the necessary findings. The NRC staff's findings with respect to authorizing attemati"es and granting or not granting the relief requested as part of the licensee's IST program are cc nined in this Safety Evaluation (SE).

Public Service Electric and Gas Company (the licensee) based the Hope Creek IST program on the requirements of the 1989 Edition of ASME Section XI, Subsections IWP and IWV, which is

' incorporated by reference in 10 CFR 50.55a. ASME Operations and Maintenance (OM)

Standard Part 6, for IST of pumps is referenced by Subsection IWP and OM Standard, Part 10, for IST of valves is referenced by Subsection IWV. The relief reauests were reviewed against the requirements of the 1989 Edition of ASME Section XI for pumps and valves. A summary of the NRC's action on each relief request is provided in Attachment 1. The test deferrals for 9904070050 990318 PDR ADOCK 05000354 P PDR

valves which are in accordance with Part 10 have been reviewed and are summarized in Tables 4.1 and 4.2 of the Technical Evaluation Report (TER) which is included as Attachment 2 to this SE. Refueling Outage Justification RJ-8 was determined by Brookhaven National Laboratory (BNL) to be a relief request and was evaluated as such in Table 4.1.

2.0 - EVALUATION l 2.1 Relief Reauests The Mechanical Engineering Branch, with technical assistance from BNL, has reviewed the -

information concerning IST Program requests for relief submitted by the licensee for the second 10-year interval for Hope Creek in letters dated December 22,1997, and April 7,1998. The staff adopts the evaluations and recommendations for granting relief or authorizing alternatives contained in the TER prepared by BNL, as reflected or modified by this SE.

For the Hope Creek IST Program, relief is granted from, or altematives are authorized in lieu of,  !

the testing requirements which have been determined to be impractical to perform, where an attemative provides an acceptable level of qua!ity and safety, or where compliance would result in a hardship or unusual difficulty without a compensating increase in quality or safety. No relief requests were recommended for denialin the BNL TER. A summary of the relief request determinatie ns is set forth in Attachment 1.

i The granting of relief is based upon the fulfillment of any commitments made by the licensee in I its basis for each relief request and the alternatives proposed. Program changes involving new  ;

or revised relief requests must be submitted to the NRC for review. Program changes that ade' 1 or delete components from the IST Program should also be periodically provided to the NRC.  !

With respect to Relief Request No. V-01, Section 3.1 of the BNL TER concluded that relief was not required since the proposed alternative testing complies with the guidance in NUREG-1482, Section 3.4, concerning skid-mounted components. However, since this guidance has not yet been endorsed by the OM codes and standards, the staff takes exception to the BNL  ;

conclusion. The staff's evaluation of Relief Request No. V-01 is shown below.

2.1.1 Valve Relief Request No. V-01 The licensee has requested relief from the stroke time test and acceptance criteria requirements of OM-10, Paragraphs 4.2.1.4 and 4.2.1.8 respectively, for the emergency diesel generator (EDG) air-start solenoid valves listed below. The licensee has proposed to test these solenoid valves quarterly in conjunction with Hope Creek Technical Specification (TS) 4.8.1.2.

1KJSV-7535A 1KJSV-7536A 1KJSV-7535B 1KJSV-7536B 1KJSV-7535C 1KJSV-7536C 1KJSV-7535D 1KJSV-7536D

i 2.1.1.1 Licensee's Basis for Requesting Relief The licensee states:

It is impractical to directly measure the stroke times of these valves due to a lack of remote or local position indication. These valves are sealed, rapid-acting solenoid valves and have no extemalindication of the valve stem or obtruator movement. Also, these valves are not provided with individual handswitches and cannot be independently operated. Valve operation is controlled by the EDG start control circuitry. It would be an undue burden to modify the valve control circuitry just to meet Code requirements, since the expense of such a modification for all four EDGs (8 valves) would constitute a hardship without a compensating increase in plant safety. Failure or significant degradation of these valves would be evidenced by failure of the diesel to meet the start time limit specified in the Technical Specification.

Additionally, these valves are integral components of the EDG skids and can be considered skid-mounted. Per Section 3.4 of NUREG-1482, the staff has determined that the testing of the major component is an acceptable means for verifying the operational readiness of skid-mounted and component subassemblies. Hope Creek Technical Specification 4.8.1.1.2 specifies the surveillance testing required to prove EDG operabiP i and requires, in part, that each EDG start from a standby condition and achieve 7J50 volts and 258.8 bz. in <10 seconds. Performance of this surveillance will verify the operational readiness of these solenoid valves.

2.1.1.2 Altemate Testing -

The licensee proposes:

Verification of the stroke times of these valves will be performed quarterly coincident with

. the required operability testing specified by Hope Creek Technical Specification 4.8.1.2.

The valve stroke times will be indirectly observed by verifying that the EDG start parameters are achieved in less than or equal to 10 seconds. Individual valve operation will be verified by observing a subsequent pressure drop in the associated starting air reservoir. This position is supt orted by Section 3.4 of NUREG-1482 and was previously approved per NRC SER dateo November 12,1996 (TAC M9632u).

2.1.1.3 Evaluation Paragraph 4.2.1.4(b) of OM-10 requires that the stroke times of all power operated valves be measured to the nearest second. In addition, Paragraph 4.2.1.8(e) requires that power-operated valves which stroke in less than 2 seconds (referred to as rapid-acting valves) be assigned a limiting stroke time of 2 seconds and exempted from the requirements of 4.2.1.8(c) and (d).

These valves are solenoid-operated valves with no valve pos% iindication. Local observation

f I

of the stem is not possible because the valves are sealed. The valves have a safety function to open to admit starting air to the air distribution header on each EDG.

l The licensee has proposed to use two acceptance criteria in lieu of stroke timing to determine

degradation in each valve. The first will use the EDG TS acceptance criterion for the 10 second time limit to reach the starting parameters to indirectly measure the valves ability to stroke to the open position. The second is the observation of the drop in air pressure of the associated starting air reservoir to ensure that the valves have moved to the open position.

Section 3.4 of NUREG-1482, " Guidelines for Inservice Testing of Nuclear Power Plants," states that testing of the major component is an acceptable means for verifying the operational readiness of the skid-mounted components and their sub-assemblies. The proposed testing provides an acceptable level of quality and safety because the proposed testing is consistent with the guidance provided in NUREG-1482.

2.1.1.4 Conclusion The proposed alternative to the stroke time test and acceptance criteria requirements of OM-10, Paragraphs 4.2.1.4 and 4.2.1.8 respectively, for the EDG air-start solenoid valves listed above is authorized pursuant to 10 CFR 50.55a(a)(3)(i) based on the alternative providing an acceptable level of quality and safety.

2.2 ~ Deferred Test Justifications The test deferrals of valves as allowed by OM-10 were reviewed as part of BNL's evaluation.

Results of the review are provided in Section 4 of the TER with recommendations for further review by the licensee for specific deferrals. Results of the review of deferred test justifications do not necessarily constitute final approval and are subject to NRC inspection.

2.3 . System Review BNL, using the Hope Creek Updated Final Safety Analysis Report, conducted a scope review of the containment spray, component cooling water and safety injection systems against the requirements of Section XI and the regulations. The review revealed a number of items that did not appear to be in compliance with the Code requirements (see Section 6 of the TER). The licensee should review these items, as well as other systems that might contain similar issues,  ;

and revise their program and take any necessary ac* ions as appropriate.

2.4 Relief Reauests in Accordance with NRC GL E,9-04 l For any relief granted based on following the positions stated in GL 89-04, the staff (with 1 technical assistance from BNL) has reviewed the information submitted by the licensee to determine whether the proposed attemative testing follows the relevant position in the GL.  !

Comments related to relief requests which the licensee states are in accordance with GL 89-04 are included in Section 6.

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New or revised relief requests that meet the positions stated in GL 89-04, Attachment 1, should be submitted to the NRC but may be implemented prior to staff approval provided the guidance in GL 89-04, Section D, is followed.

2.5 Action items

. For several IST Progr& relief requests, the staff identified certain action items for the licensee

! to complete. These au.sa items are identified in Section 6 of the TER and should be addressed -

l- within one year from the Gate of this SE or by the end of the next refueling outage, whichever is later. In addition, the licensee should address program scope issues identified in Section 6 of the TER within one year from the date of this SE or by the end of the next refueling outage, whichever is later. Licensee actions to address the action items in this SE are subject to NRC inspection. The licensee is requested to respond to the NRC within one year of the date of this l

SE describing actions taken, actions in progress, or actions to be taken, to address each of these items.

3.0 CONCLUSION

l The Hope Creek IST Program requests for relief from the Code requirements have been  ;

reviewed by the staff with the assistance of its contractor, BNL. The TER provides BNL's

evaluation of these relief requests. The staff has reviewed the TER and adopts the evaluations and recommendations for granting relief or authorizing attematives, as reflected or modified by this SE. The authorizing of alternatives or granting of reliefis based upon the fulfillment of any commitments made by the licensee in its basis for each relief request and the attematives proposed. The implementation of the IST Program and relief requests is subject to inspection by the NRC.

The licensee should refer to Section 6 of the TER for a discussion of action items identified during the review. The licensee should address each action item in accordance with the guidance therein. The action items identified in Section 6 of the TER should be addressed within one year of the date of this SE or by the end of the next refueling outage, whichever is later, unless otherwise specified in the TER.

The staff concludes that the relief requests as evaluated and modified by this SE provide reasonable assurance of the operational readiness of the pumps and valves to perform their safety-related functions. The staff has determined that:

1)' With respect to Relief Requests Nos. P-01 and P-02, compliance with the Code would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. Therefore, the proposed altematives are authorized pursuant to 10 CFR 50.55a(a)(3)(ii). l l

2) With respect to Relief Request Nos. P-03, V-01, and V-02, the proposed alternatives l provide an acceptable level of quality and safety. Therefore, the proposed attematives are authorized pursuant to 10 CFR 50.55a(a)(3)(i).

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3) With respect to Relief Requests Nos. V-03 and RJ-8, the requirements of the Code are impractical. Therefore, relief is granted pursuant to 10 CFR 50.55a(f)(6)(i). The relief granted is authorized by law and wi!I not endanger life or property, or the common defense and security, and is otherwise in the public interest. In making this~

determination, the staff has considered the burden on the licensee if the requirements were imposed on the facility.

Principal Contributor: J. Colaccino Attachments: 1. Summary of Hope Creek Pump and Valve Relief Requests

2. Technical Evaluation Report, dated December 16,1998 Date: ,

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Technical Evaluation Report l Pump and Valve Inservice Testing Program Hope Creek Nuclear Generating Station 1.0 . INTRODUCTION Contained herein is a technical evaluation of American Society of Mechanical Engineers -  ;

(ASME)Section XI pump and valve inservice testing (IST) program relief requests and deferral justifications submitted by Public Service Electric and Gas Company (PSE&G) for its Hope i Creek Nuclear Generating Station. - Additionally, this technical evaluation report contains, for selected systems, a review of the scope of Hope Creek's ASME Section XI Pump and Valve Inservice Testing Program. Hope Creek is a General Electric Boiling Water Reactor (BWR) that began commercial operation in December 1986.  !

PSE&G submitted the Second Ten-Year Interval Inservice Testing Program on December 22, 1997 (Ref.1). The licensee states that this program is based on the requirements of the 1989 Edition of the ASME Section XI Code. This program revision supersedes all previous  :

submittals. The licensee in the transmittal letter states that the second ten year interval extends i from December 20,1997 to December 20,2006 having been reduced one year to compensate  !

for the first interval which was extended one year. ASME Section XI, TIWA-2430(c) allows

)

each interval to be extended or decreased by as much as one year. Adjustments shall not cause l successive intervals to be altered by more than one year from the original pattern ofintervals.

The !!censee's proposal complies with the Code. In addition, the licensee submitted pump relief request, P-03, on April 7,1998 (Ref. 2).

Title 10 of We Code of Federal Regulations, {50.55a T(f) (Ref. 3) requires that inservice testing

' of ASME Code Class 1,2, and 3 pumps and valves be performed in accordance with Section XI of the ASME Boiler and Pressure Vessel Code (Ref. 4) and applicable addenda, except where

. specific relief has been requested by the licensee and granted by the Commission pursuant to 50.55a T(f)(6)(i), or where an alternative has been requested and authorized pursuant to 50.55a T(a)(3)(i) or (a)(3)(ii). Section 50.55a T(f)(4)(iv) provides that inservice testing of pumps and valves may meet the requirements set forth in subsequent editions add addenda that are incerporated by reference in paragraph (b) of 50.55a, subject to the limitations and madifications listed, and subject to Commission approval. In rulemaking to 10CFR50.55a, erTective September 8,1992 (see Federal Register, Vol. 57, No.152, page 34666), the 1989 Edition of ASME Section XI was incorporated into paragraph (b) of 50.55a. The 1989 Edition provides that the rules for inservice testing of pumps and valves are as specified in ASME/ ANSI OMa-1988 Pait 6 and 10, and OM-1987 Part 1 (Refs. 5-7).

- The review of the IST Program was performed utilizing the Standard Review Plan, Section 3.9.6; Generic Letter 89-04," Guidance on Developing Acceptable Inservice Testing Programs,"

the Minutes of the Public Meeting on Generic Letter 89-04, and Supplement to the Minutes; I

NUREG-1482; NUREG/CR-6396; and the recently published summary of the public workshops held in January and February 1997 on IST (References 8-14). The IST Program requirements apply only to component (i.e., pump and valve) testing, and are not intended to provide a basis to change the licensee's current Technical Specifications for system test requirements.

Section 2 of this report presents the three pump relief reguests submitted by PSE&G and Brookhaven National Laboratory's (BNL) evaluation. Similar information is presented in Section 3 for the three relief requests submitted by PSE&G for the valve testing program, and in Table 4.1 for refueling outage justification RJ-8, which should be submitted as a relief request in future program revisions. Section 4 contains the evaluation of 31 justifications to defer valve testing to cold shutdowns or refueling outages.

Results of the IST scope review for selected systems is presented in Section 5. Section 6 summarizes the recommended actions for the licensee, resulting from the relief request and deferred testing justification evaluations, and the review of the IST Program scope for selected systems. BNL recommends that the licensee re alve these items in accordance with the evaluations, conclusions, and guidelines presented in this rept 2.0 PUMP IST PROGRAM RELIEF REQUESTS In accordance with 650.55a, PSE&G has submitted three relief requests for pumps at ilope Creek which are subject to inservice testing under the requirements of ASME Section XI. The relief requests have been reviewed to verify their technical basis and determine their acceptability. The relief reques's, along with the technical evaluation by BNL, are summarized below.

2.1 Pump Relief Request P-01, HPCI Pump and llPCI Booster Pump ReliefRequest: The licensee has requested relief from the requirements of OMa-1988, Part 6, $4.6.1.1, which specifies that pump flow rate instrumentation accuracy shall be within 2%, for the High Pressure Coolant Injection Pump (IIPCI) and High Pressure Coolant injection Booster Pump.

Licensee's Basis For Relief "The permanently installed flow instrument iBJFIC-R600-E41 does not meet the 2 percent acceptable instrument accuracy specified in OM-6, Table 1. The table below lists the actual instrument loop accuracy. This loop accuracy has been calculated from the transmitter to the indicator in the main control room.

Installation of temporary field instrumentation is not viable since speed and flow must be set and controlled at the reference values from the main control room and the test duration is severely limited due to heat addition to the suppression pool.

As indicated in the table below, the installed instrumentation has a full-scale range of 6000 gpm, which only slightly exceeds the pump flow reference valve of 5600 gpm (full scale equals 1.07 times reference) with an accuracy of+3.41% and -2.22% of full scale. This results in flow rate measurements accurate to +3.65% or -2.38% of indicated at reference conditions, which is more conservative (than) the 6% minimum accuracy allowed by the combination ofinstrument full-scale range and accuracy allowed in OM-6. This accuracy provides adequate assurance of operability. Installation of a new flow rate instrument would constitute a hardship and a burden without a compensating increase in plant safety since it would be expensive and would not provide better indication accuracy or readability. The current instrumentation provides sufficient repeatability to allow for an evaluation of the pump hydraulic condition and detect pump degradation."

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l Supporting Data Table:

l Instrument Number IBJFIC-R600 Actual Instrument Range 0-6000 gpm Actual Gauge (Loop) Accuracy +3.41%

-2.22%

Test Reference Value 5600 gpm Code Allowable Instrument Range - 16,800 gpm (3X ref. value)

Code Allowable Instrument Tolerance 336 gpm (2% of Code Allowable Range)

Code Allowable Indicated Accuracy 6%

(at reference value)

Actual Instrument Tolerance +204.6 gpm

-133.2 gpm ActualIndicated Accuracy +3.65%

(at reference value) -2.3 8%

froposedAlternative Testing: The existing permanently installed flow instrumentation will be used for pump inservice testing.

Evaluation: OMa-1988, Part 6, j 4.6.1.1 requires that the accuracy of flow rate instruments be within 2% of full scale for analog instruments. Additionally, j 4.6.1.2 requires the full-scale range of each analog instrument be no greater than three times the reference value. The NRC in NUREG-1482, Section 5.5.1 addresses the situation where the range of a analog instrument is greater than 3 times the reference value, but the accuracy is more conservative than the Code. The NUREG states that the NRC will grant relief when the combination of the range and accuracy yields a reading at least equivalent to the reading achieved from instruments that meet the code requirements (i.e., up to 16%).

In this relief request the range meets the Code requirements, however, the accuracy slightly exceeds the Code requirements. Considered together, the reading accuracy achieved from the installed instruments is +3.65% or -2.38%, which meets the intent of the Code and yields an acceptable level of quality and safety. Compliance with the Code would require the purchase of new instrumentation which would be burdensome to the licensee without a compensating increase in the level of quality and safety.

Therefore, it is recommended that the alternative be authorized in accordance with 10CFR50.55a(a)(3)(ii). If at a later date, the licensee replaces this instrument, the Code accuracy and range requirements must, however, be met.

2.2 Pump Relief Request P-02, RCIC Pump ReliefRequest: The licensee has requested relief from the requirements of OMa-1988, Part 6,54.6.1.1, 3

which specifies that pump flow rate instrumentation accuracy shall be within 12%, for the reactor coolant isolation cooling (RCIC) pump.

Licensee 's Basis For Relief "The permanently installed flow instrument IBDFIC-R600-E51 does not  ;

meet the 2 percent acceptable instrument accuracy specified in OM-6, Table 1. The table below lists the I actual instrument loop accuracy. This loop accuracy has been calculated from the transmitter to the indicator in the main control room.

Installation of temporary field instrumentation is not viable since :, peed and flow must be set and controlled at the reference values from the main control room and the test duration is severely limited due to heat addition to the suppression pool.

1 As indicated in the table below, the installed instrumentation has a full-scale range of 700 gpm, which l only slightly exceeds the pump flow reference valve of 600 gpm (full scale equals 1.17 times reference) with and accuracy of +3.4% and -1.8% of full scale. This results in flow rate measurements accurate to

+3.97% or -2.1% of indicated at reference conditions, which is more conservative that 6% minimum accuracy allowed by the combination ofinstrument full-scale range and accuracy allowed in OM-6.

This accuracy provides adequate assurance of operability. Installation of a new flow rate instrument ,

would constitute a hardship and a burden without a compensating increase in plant safety since it would j be expensive and would not provide better indication accuracy or readability. The current j instrumentation provides sufficient repeatability to allow for an evaluation of the pump hydraube l condition and detect pump degradation." l l

Supporting Data Table:

Instrument Number IBDFIC-R600 1

Actual Instrument Range 0-700 gpm Actual Gauge (Loop) Accuracy +3.4% i

- 1.8%  !

Test Reference Value 600 gpm Code Allowable Instrument Range 1800 gpm (3X ref. value) ,

1 Code Allowable Instrument Tolerance 336 gpm (sic)

(2% of Code Allowable Range) r de o Allowable Indicated Accuracy 16 %

(at reference value)

Actual Instrument Tolerance +23.8 gpm

-12.6 gpm ActualIndicated Accuracy +3.97%

(at reference value) l -2.1%  !

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Proposed Alternative Testing: The existing permanently installed flow instrumentation will be used for pump inservice testing.

Evaluation: OMa-1988, Part 6,14.6.1.1 requires that the accuracy of flow rate instruments be within 2% of full scale for analog instruments. Additionally, j 4.6.1.2 requires the full-scale range of each analog instrument be no greater than three times the reference value. The NRC in NUREG-1482 Section 5.5.1 addresses the situation where the range of a analog instrument is greater than 3 times the reference value, but the accuracy is more conservative than the Code. The NUREG states that the NRC l will grant relief when the combination of the range and accuracy yields a reading at least equivalent to -

the reading achieved from instruments that meet the code requirements (i.e., up to 16%).

In this relief request the range meets the Code requirements, however, the accuracy slightly excee.ds the Code requirements. Considered together, the reading achieved from the installed instruments is +3.97%

or -2.1% , which meets the intent of the Code and yields an acceptable level of quality and safety.

4 Compliance with the Code would require the purchase of new instrumentation which would be burdensome to the licensee without a compensating increase in the level of quality and safety.

Therefore, it is recommended that the alternative be authorized in accordance with 10CFR50.55a(a)(3)(ii). If at a later date, the licensee replaces this instrument, the Code accuracy and range requirements must, however, be met.

2.3 Pump Relief Request P-03, Generie Use of Analysis in Lieu of Corrective Action ReliefRequest: The licensee has requested generic relief from the requirements of OMa-1988, Part 6, 16,1, which requires if deviations fall within the required action range of Table 3, the pump is required ,

to be declared inoperable until the cause of the deviation has been determined and the condition  !

corrected.

Licensee 's Basis: "The 1983 ASME Section XI Code, Subsection IWP-3230(c) stated that; " Corrective action shall be either replacement or repair per IWP-31111, or shall be an analysis to demonstrate that the condition does not impair pump operability and that the pump will fulfill its function. A new set of reference values shall be established aller such analysis." The OMc-1994 Addenda (ISTB 6.2.2) and the OM 1995 Edition (ISTB 6.2.2) both state that;"If the measured test parameter s alues fall within the required action range of Table 5.2.1-1, Table 5.2.1-2, Table 5.2.2-1, or Table 5.2.3-1, as applicable, the pump shall be declared inoperable until either the cause of the deviation has 1 een determined and the condition is corrected, or an analysis of the pump is performed and new refe ence values are established in accordance with ISTB 4.6."

The Code applicable for the first interval IST Program and the latest issued Code both provide for analysis of pump test data in lieu of repair or replacement of the pump if the test parameters fall within the required action range. The OMa Code-1988 Edition did not include such provisions.

Communications with members of the OM Code Committee indicate that this was an oversight and that it was never intended to delete the ability to analyze the test data and determine if the pump is still capable of performing its intended safety function."

ProposedAlternative Testing: If pump test parameters fall within the required action range, the 1995 OM Code,16.2.2, and related $4.6, will be utilized.

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Evaluation: OMa-1988, Part 6, j 6.1, " Acceptance Criteria," specifies actions required to be taken if l

any of the measured pump parameters fall within the alert or required action ranges. For test results in '

the alert range, the test frequency is required to be doubled until the cause of the deviation is determined

)

and the condition is corrected. For test results in the required action range, the pump shall be declared j

inoperable until the cause of the deviation has been determined and the condition corrected.  ;

4 in ASME OM Code-1995, which is not currently referenced in 10 CFR 50.55a but is included in the j proposed rulemaking without any modincation or limitation (Ref.15), Subsection ISTB,1 ISTB 4.6, l "New Reference Values," allows that "[i]n cases where the pump's test parameters are either within the l alert or required action ranges oflSTB 5.2.1.1, Table ISTB 5.2.1-2, Table ISTB 5.2.2-1, or Table ISTB l

5.23-1, and the pump's continued use at the changed values is supported by an analysis, a new set of reference values may be established." This paragraph clarifies that, if a pump can be shown to be capable of performing its safety function, it may be returned to service with adjusted reference values.

This reHects that there are pumps that have a significant margin over the safety requirements that might degrade from their initial performance, but still are capable of meeting their safety function. Pumps I which do not have margin would not be returned to service without repair or replacement. Paragraph l ISTB 4.6 also states that the analysis shall include both a pump level and a system level verincation of j pump operational readiness, the cause of the change in pump performance, and an evaluation of all ,

trends indicated by available data. Paragraph ISTB 6.2.2, which provides acceptance < iiteria for the i required action range explicitly states that an analysis may be performed and directly references j ISTB 4.6.

l In NRC Generic Letter 91-18, which concerns resolution of degraded and nonconforming conditions and l

operability, j 6.11, " Technical Specification Operability vs. ASME Code,Section XI Operative i Criteria," the NRC indicates that in cases where the required action range limit is more conservative  ;

than its corresponding technical specification limit, the corrective action may not be limited to replacement or repair. The corrective action may consist of an analysis to demonstrate that the specific pump performance degradation does not impair operability and that the pump or valve will still fulfill its j function, such as delivering the required flow. A new required action range may be established after  !

such an analysis which would then allow a new determination of operability. Approval has been l

.uthorized by the NRC to allow licensees to use the OM Code-1995, j 6.2.2 for pumps in the required '

action range because licensees are already allowed to perform an analysis in accordance with Generic ,

Letter 91-18.

The analysis should at least include a comparison of the current measurements for the particular parameter, i.e., flow rate, vibration, discharge pressure or differential pressure, to the baseline measurements, an evaluation of the trend of available data for the parameter, and a determination of the cause and the need for corrective action. Alternate available methods, such as vibration spectral analysis, are expected to be used to support the analysis. Any analysis performed is subject to NRC inspection and must provide reasonable assurance that the degradation mechanism will not cause further degradation such that, before the next pump test or before repairs can be performed, the pump would fail. Additionally, it should be noted that changes to the vibration reference values would affect only the vibration relative alert and required action limits, and not the absolute limits specified by the Code. If the absolute limits are exceeded (i.e.,0.7 ips or 22 mils for the required action range), the licensee would be required to declare the pump inoperable in accordance with the Code.

The use of this analysis is upected to be a rare occurrence. This analysis should be used cautiously, as it is not intended to be used regularly to evaluate the operability of all pumps that fall into the required 6

action range in order to declare the pump operable and dC.ne new reference values where significara degradation has occurred. Repeated application of analysis could lead to stair stepping the Code limits downv ard to the safety limits of the pump. The licensee should have an understanding of the margin of each pump above its design-basis requirements.

Therefore, given the licensee will perform an analysis in accordance with ISTB 4.6 of the 1995 OM Code, it is recommended that the licensee's proposed alternative be authorized pursuant to 10 CFR 50.55a(a)(3)(i), based on the acceptable level of quality and safety that will be provided by the alternative for the required action range.

3.0 VALVE IST PROGRAM RELIEF REQUESTS I

In accordance with 50.55a, PSE&G has submitted three valve relief requests for specific valves at Hope Creek that are subject to inservice testing under the requirements of ASME Section XI. There relief requests have been reviewed to verify their technical basis and determine their acceptability. The relief requests are summarized below, along with the technical evaluation by BNL.

3.1 Valve Relief Request V-01, EDG Air Start Solenoid Valves ReliefRequest: The licensee has requested relief from the requirements of OMa-1988, Part 10,14.2.1 which requires power-operated valves to be exercised with the stroke time measured to at least the nearest second, for the EDG Air Start Solenoid Valves, IKJSV-7535A through D and IKJSV-7536A through D.

Licensee 's Basis For Relief "It is impractical to directly measure the stroke times of these valves due to a lac!; of remote or local position indication. These valves are sealed, rapid-acting solenoid valves and have no external indication of the valve stem or obturator movement.

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Also, these valves are not provided with individual hand switches and cannot be independently operated. -

Valve operation is controlled by the EDG start control circuitry. It would be an undue burden to modify the valve control circuitryjust to meet Code requirements, since the expense of such a modification for ,

e'. four EDGs (8 valves) would constitute a hardship without a compensating increase in plant safety. I Failure or significant degradation of these valves would be evidenced by failure of the diesel to meet the i start time limit specified in the Technical Specification.  !

Additionally, these valves are integral companents of the EDG skids and can be considered skid-mounted. Per Section 3.4 of NUREG-1482, the staff has determined that the testing of the major component is an acceptable means for verifying the operational readiness of skid-mounted and component subassemblies. Hope Creek Technical Specification 4.8.1.1.2 speciEes the surveillance i testing required to prove EDG operability and require: in part, that each EDG start from a standby I condition and achieve 3950 volts and 258.8 hz. in <10 seconds. Performance of this surveillance will  !

verify the operational readiness of these solenoid valves." j Propor,edAlternative Testing: Verification of the stroke times of these salves will be performed quarterly coincident with the required operability testing specified by llope Creek Technical Specification 4.8.1.2. The valve stroke times will be indirectly observed by verifying that the EDG start parameters are achieved in less than or equal to 10 seconds. Individual valve operation will be verified by observing a subsequent pressure drop in the associated starting air reservoir.

7

r Evaluation: OMa-1988, Part 10,54.2.1.4 requires that the stroke time of all power-operated valves be measured to at least the nearest second and that any abnormal or erratic action be recorded and an evaluation be made regarding the need for corrective action. These valves have a safety function in the open position to admit starting air to the air distribution header on each Emergency Dies, I Generator (EDG) to allow engine start in the event of a loss of offsite power or design basis LOCA. The licensee has classified them as ASME Code Class 3 and considers them to be part of the diesel skid. As discussed in NUREG-1482, Section 3.4, pending endorsement of the OM Code which specifically address skid-mounted components (i.e., ASME OMa Code-1996), the NRC has determined that the testing of the major component is an acceptable means for verifymg the operational readiness of the skid j mounted components. As further dinussed in the 1997 NRC IST Workshop meeting minutes, the licensee should state in the IST Program that the surveillance tests of the major component adequately tests the skid-mounted components. The licensee has stated that the diesel start surveillance in accordance with Technical Specification 4.8.1.2 will verify the stroke times of these solenoid valves.

Additionally, due to the redundancy of these valves, the licensee will verify individual valve operation ,

by observing the subsequent pressure drop in the associated starting air reservoir. The licensee's l

proposal complies with the guidance in NUREG-1482, and reliefis not required. The licensee should, '

however, continue to document their approach :n the IST Program.

3.2 Valve Relief Request V-02, Main Steam Safety Relief Valves ReliefRequest: The licensee has requested relief from the test frequency requirements of OM-1987, Part 1,51.3.3 for the fourteen main steam safety relief valves, ISNPSV-F013A through E, I ABPSV-F013F through H, l ABPSV F013J through M, l ABPSV-F013P, and 1 ABPSV-F013R.

Licensee 's Basis For Relief "liope Creek UFSAR 5.2.2.4.2.1.3 discusses the testing frequency of the safety relief valves (SRVs). This section states that liope Creek "can achieve optimum SRV operability by disassembly of the pilot section of at least 50 percent of the operating SRVs after each cycle."

Additionally, this section states that General Electric Service information Letter 196 (SIL 196) will be used to enhar.ce valve operability.

The SIL recommends that refurbishment of the pilot disc and seat be performed at least once every other outage or every three years, whichever comes first, w if the "as received" condition indicates that a sticking pilot disc to seat condition exists (SIL 196, Supplement 14, recommended action #2).

Based on SIL recommendations, it is evident that the concern associated with SRV operation centers on the pilot portion of the valve, and its ability to perform its intended function. A review of NRC Information Notices 82-41,83-39, S3-82,86-12 and 88-30 supports this conclusion, indicating that the pilot portions of these valves require diligent testing.

Hope Creek Technimi Specification 4.4.2.2 requires that at least one-half (1/2) of the safety relief valve pilot stage assembha be removed, set pressure tested and reinstalled or replaced with spares that have been previously set pressure tested and stored per manufacturer's recommendations at least once per 18 months.

Additionally, those removed shall be rotated such that all 14 safety relief valve pilot stage assemblies are removed, set pressure tested, and reinstalled or replaced with spares at least once per 40 months.

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l flope Creek Technical Specification 4.4.2.3 requires that the safety relief valve main (mechanical) stage assemblies be removed, set pressure tested and reinstalled or replaced with spares that have been previously set pressure tested at least once every five years.

For the ADS valves, Hope Creek Technical Specification 4.5.1.d.2.b requires that, every 18 months, each valve be manually opened when the reactor steam dome pressure is greater than or equal to 100 psig and its operation verified by either control valve or bypass valve position response or measured steem flow change.

The Hope Creek Main Steam SRVs are of a two-stage design. The first stage (pilot stage) utilizes a spring loaded pilot disc to sense the set pressure and a pressure loaded stabilizer disc to sense the reseat pressure. Spring force (preload force)is applied to the pilot disc by means of a pilot rod. Thus, the adjustment of the sprir g preload force will determine the set pressure of the valve. The second stage ,

(main stage) is tighti) seated by the combined forces exerted by the preload spring on the main disc and I the system internal pressure acting over the area of the disc. In the closed position, the static pressures will be equal in the valve inlet nozzle and in the chamber over the main stage. This pressure equalization is made possible by the internal passages provided (i.e., pi(s) ton ring gap, vent hole, drain groove and stabilizer disc seat). When the system pressure increases to the valve set pressure, pilot stage operation will vent the chamber over the main stage piston to the downstream of the valve via internal porting. This venting produces a differential pressure across the main stage p!(s) ton in the direction tending to unseat the valve. The main stage piston is sized such that the resultant opening force is greater than the combined spring preload and the system pressure seating force.

The true setpoint adjustment (and operability determination) of the valve is contained within the pilot portion of the SRV. By applying the SRV testing frequency required by OM-1 to the pilot portion (achieved by meeting Technical Specification 4.4.2.2), set point accuracy and pilot sticking verification can be maintained, providing an acceptable level of safety. Testing of the mair. body (mechanical portion), whid contains only the main disc, piston rings and a preload spring that is non-adjustable, at the OM-1 specified frequency will not result in a significant increase in the level of safety. Testing of the inechanical portion of all 14 SRVs to provide verification of blowdown and liow rates is conducted every 5 years when the valves are tested as a complete assembly per Techmcal Specification 4.4.2.3."

ProposedAlternative Testing: Tne Main Steam SRVs will be tested in acecrdance with Technical Specifications 4.4.2.2 and 4.4.2.3. At least one-half (50%) of the SRVs pilot stage will be removed and set pressure tested or replaced with previously tested assemblies every 18 months. Additionally, those removed shall be rotated such that all 14 safety relief valve pilot stage assemblies are removed, set pressure tested, and reinstalled or replaced with spares at least once per 40 months. In the event the "as-found" setpoin' fails the setpoint testing, sample expansion of the other pilot valves will be conducted in accordance with paragraph 1.3.3.1.(e) of OM-1. All 14 main stages (with the entire assembly) will be removed, tested and reinstalled or replaced every 5 years. Hope Creek anticipates that this maintenance activity will occur in a single outage every 5 years.

Evaluation: These valves have a safety function to provide overpressure protection for the main steam header and the reactor vessel. Additionally, valves 1 SNPSV-F013 A through E also serve an ECCS function in the Automatic Depressurization System (ADS) to depressurize the reactor vessel in the event 3 of a small break LOCA coincident with a fai!are of the High Pressure Coolant Injection (HPCI) system.

l The valves are two stage Target Rock valves. Each valve consists of a main stage and a pilot stage.1he l l

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licensee has classified these valves as IST Category C, as discussed in technical position paper TP-6 included in the IST Program, and as such, are required to be tested in accordance with OM-1987, Part 1.

1 The technical position states that the ADS /PSV valves were previously classiGed as B/C and references NUREG-1482, Section 4.3.4 as the basis for reclassifying the valves as C. The NUREG mentions an ASME Code initiative to review the category of the ADS valves. Since the publication of the NUREG, the Code was revised in the 1996 Addenda to exclude Category A and B safety and relief valves from the valve position indication verincation and inservice exercising requirements, however, the Code has net addressed the classincation of these valves. Based on the definition of Category C as valves that are "self-actuating" and given that these valves may also be actuated by an operator or logic signal, it would  ;

app ur that the previous categorization of B/C would be more appropriate. Regardless of the categorization, based on the clariGeation in the 1996 Addenda, the testing requirements (i.e., in accordance with Appendix I only for Category B/C or C) would be the same.

OM-1987, Part 1,11.3.3 requires all Class 1 valves of each type and manufacturer to be tested within each subsequent five year period, with a minirnum of 20% of the valves tested within any 24 months, where the 20% shall be previously untested valves, if they exist. Paragraph 3.3.1.1 addresses main steam pressure relief valves with auxiliary actuating devices. This paragraph requires these tests, in the following sequence:

a) visual examination; b) seat tightness determination; c) set pressure determination; d) determination of compliance with the Owner's seat tightness criteria; e) determination of electrical characteristics and pressure integrity of solenoid valve (s);

f) determination of pressure integrity and stroke capability of air actuator; g) determination of operation and electrical characteristics of position indicators; h) determination of operation and electrical characteristics of bellows alarm switch; and i) determination of actuating pressure of auxiliary actuating device sensing element, where applicaMe, and electrical continuity.

The licensec has proposed to test the main steam SRVs in accordance with the Technical Specifications.

The pilot stage will be tested separately from the main valve using a schedule of 7 pilot assemblies (i.e.,

50%) every 18 months. At least one-half (1/2) of the safety relief valve pilot stage assemblies be removed, set pressure tested and reinstalled or replaced with spares that have been previously set pressure tested and stored per manufacturer's recommendations at least once per 18 months.

Additionally, those removed shall be rotated such that all 14 safety relief valve pilot stage assemblies are removed, set pressure tested, and reinstalled or replaced with spares at least once per 40 months.

This would result in the pilots being tested more frequently than required by the code (i.e., once every 3.5 years, versus once every 5 years), however, the complete sequence of tests will not be performed.  ;

The main stage with the entire assembly will be tested once every 5 years, during a single outage. l Although the proposal does not meet the sampling approach required by the Code, given the increased 5 frequency of the pilot valve test and that the test frequency complies with the code required frequency (i.e., once every 5 years), this proposal should provide an acceptable level of quality and safety. j Therefore, it is recommended that the alternative be authorized in accordance with j 10CFR50.55a(a)(3)(i).

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3.3 Valve Relief Request V-03, CRD IICU Scram Valves l

ReliefRequest: The licensee has requested relief from OMa-1983, Part 10, j 4.2.1 which specifies the test frequency requirements and requires that all power operated valves shall have their stroke time measured, for the CRD llCU scram velves associated with the 185 llCUs, IBFXV-126, IBFXV-127, and IBFXV-139.

Licensee 's Basis For Relief "It is impractical to directly measure the stroke times of these valves due to a lack of remote or local position indicanon. These valves are sealed, rapid-acting solenoid valves and have no external indication of the valve stem or obturator movement. Also, these valves operate in pairs and are not provided with individual hand switches and cannot be independently operated. Valve operation is controlled by the reactor protection circuitry. Operation of these valves at power would result in rod insertion and subsequent reactor shutdown.

Hope Creek Technical Specification 3.1.3.2 specifies a maximum scram insertion time. Technical Specification 4.1.3.2 specifies the required rod testing to ensure control rod maximum scram insertion times are not exceeded. Failure or significant degradation of these valves would be evidenced by a failure of the control rod to meet the insertion time limit specified in the Technical Specification.

Verification of rod drop times within specification adequately ensures operational readiness of these valves."

Proposed Alternative Testing: These valves will be exercised open and closed and fail-safe tested l during control rod scram time tests on the control rods as required by Hope Creek Technical Specification 4.1.3.2.a for all control rods prior to thermal power exceeding 40% of rated thermal power following core alterations or after a reactor shutdown that is greater than 120 days; and Technical Specificatiu 4.1.3.2.c for at least 10% of the control rods, on a rotating basis, at least once per 120 days of power operation.

Control rod scram timing will be used to indirectly measure :he valve stroke times. Maximum stroke time will be 7 seconds, as indicated in Technical Specification 3.1.3.2. Failure of the rods to meet scram timing requirements will result in evaluation and corrective action, as required.

Evaluation: OMa-1988, Part 10,14.2.1 requires the stroke time of all power-operated valves to be measured quarterly if practicable, otherwise at cold shutdowns. If full-stroke exercising during cc!d shutdowns is also impracticable, it may be deferred to refueling outages.

The subject valves have a safety function in ensuring rod insertion during a reactor scram. Valve I BFXV-126 is an ASME Code Class 3 valve and opens to vent the control rod drive to the scram discharge volume. Valve Ibfxv-127 opens to allow HCU accumulator pressure to exert force to insert the control rod into the core. Valve Ibfxv-139 opens to exhaust instrument air and open the scram inlet 4

and outlet valves. Valves IBFXV-127 and 139 are not ASME Code Class valves.

These valves are not provided with position indication, therefore measuring their full-stroke time in accordance with the Code is impractical. Additionally, operation of these valves at power would result in rod insenion and subsequent reactor shutdown, which is impractical. As discussed in Generic Letter 89-04, Position 7, the rod scram test frequency identified in the technical speci9 cation may be used as the valve testing frequency to minimize rapid reactivity transients and wear of the control rod mechanisms, and verifying that the associated control rod meets the scram insertion time limits defined 11

in the Technical Specifications can be an acceptabb alternative method of detecting degradation of these

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valves in lieu of valve stroke measurement. Therefore, the licensee's proposal to exercise these valves by performing the Technical Specification control rod scram test pursuant to Generic Letter 89-04, Position 7, should provide reasonable assurance of the valves' operational readiness and it is recommended that relief be granted in accordance with 10CFR50.55a(f)(6)(i) for valve IBFXV-126.

Reliefis not required for the other two valves identified in the request, since they are not ASME Code Class.

4.0 VALVE TESTING DEFERRAL JUSTIFICATIONS PSE&G has submitted 19 justifications for deferring valve testing to cold shutdowns and twelve l justifications for deferring testing to refueling outages. Thesejustifications document the impracticality '

of testing 226 valves quarterly, during power operation. Thesejustifications were reviewed to verify their technical basis.

As discussed in Generic Letter 91-18 (Ref.16), it is not the intent of IST to cause unwarranted plant j shutdowns or to unnecessarily chalknge other safety systems. Generally, those tests involving the potential for a plant trip, or damage to a system or component, or excessive personnel hazards are not considered practical. Removing one train for testing or entering a Technical Specification limiting condition of operation is not sufficient basis for not performing the required tests, unless the testing renders systems inoperable for extended periods of time (Reference NUREG-1482, Section 3.1.1).

Other factors, such as the effect on plant safety and the difficulty of the test, may be considered.

Valves, whose failure in a non-conservative position during exercising would cause a loss of system function, such as non-redundant valves in lines (e.g., a single line from the RWST or accumulator discharge), or the RHR pump discharge crossover valves for PWRs whose licensing basis assumes that all four cold legs ace being supplied by water from at least one pump, should not be exercised during conditions when the system is required to be operable.- Other valves may fall into this category under certain system configurations or plant operating modes, e.g., when one train of a redundant ECCS system is inoperable, non-redundant valves in the remaining train should not be cycled because their failure would cause a total loss of system function, or when one valve in a containment penetration is open and inoperable, the redundant valve should not be exercised during this system configuration.

BNL's evaluation of each deferraljustification is provided in Tables 4.1 and 4.2. The anomalies associated with the specificjustifications are provided in Section 6.0 of this TER. 1 I

i 5.0 IST SYSTEM SCOPE REVIEW I

The review performed for this TER did not include verification that all pumps and valves within the  !

scope of 10 CFR 50.55a and Section XI are contained in the IST Program, and did not ensure that all I applicable testing requirements have been identified. The IST Program's scope was, however, reviewed for selected systems. The pumps and valves in the reactor coolant injection system (RCIC), residual heat removal system (RHR) and service water system (excluding the lube water subsystem on drawing M-10-1, Sheet 3) were reviewed against the requirements of Section XI and the regulatiens. The UFSAR was used to determine if the specified valve categories and valve functions were consistent with the plant's safety analyses. The review results showed compliance with the Code, except for the items discussed in 6.11 through 6.19. The licensee should review these items and make changes to the IST 12

i Program, where appropriate. Additionally, the licensee should verify that there are not similar problems I with the IST Program for other systems.

l 6.0 IST PROGRAM RECOMMENDEI) ACTION ITEMS Inconsistencies, omissions, and required licensee actions identiHed during the review of the licensee's second interval Inservice Testing Program are summarized below. The licensee should resolve these l

items in accordance with the evaluations presented in this report.

6.1 It is recommended that the use of existing flow instrumentation for the HPCI and RCIC pumps be authorized (Relief Requests P-01 and P-02) However, if at a later date, the licensee replaces the HPSI or RCIC flow instruments, the Code accuracy and range requirements must be met.

6.2 The licensee should review the guidance provided in TER Section 2.3, regarding the use of analysis in lieu of pump corrective actions. i 6.3 The supporting table in Relief Request P-02 incorrectly identiDes the Code allowable instrument tolerance as 336 gpm. Based on 2% of the Code allowable range (i.e.,1800 gpm),

the value should be 136 gpm. Additionally, the request is identified as P-01 on page A4 5 of 6 l of the IST Program.

6.4 The valve P&lD coordinates in Table 3 of the IST Program are often incorrect, as are the referenced drawings. Additionally, Table 1 of the IST Program ," System and P&lD Listing,"

does not contain all the pertiner.t drawings (e.g., M-51-1, sheet 1 or M-10-1, Sheets 1 and 2).

6.5 Per RJ-2, the subject valves will be full stroke exercised to the closed position on a refueling outage frequency. Per Table 3, the valves are exercised open and closed on a refueling outage frequency. The licensee should review the function and test'ng of the valves and revise the justincation or Table accordingly.

6.6 The licensee indicated in RJ-5 that exercising the excess How valves requires isolation of their associated safety-related instrumentation, which could disable safety initiation logic or unnecessarily challenge safety systems. While these are acceptable reasons for deferring quarterly at-power testing, it has been observed (based on testing conducted at other BWRs prior to refueling outages while the reactors were still at power) that the testing of some excess now check valves at pcwer may be practical. The licensee should review each valve and ensure aat excess Dow check valves are tested quarterly at power where practicable.

Additionally, the Code allows deferral of testing to cold snutdowns or refueling outages based on impracticality. The licensee has proposed testing the valves once every 18 months in RJ-5, without regard to the plant's operating mode. Testing at a frequency other than at cold shutdowns or refueling requires a relief request. The licensee should revise thejustification accordingly or submit a relief request.

6.7 Per RJ-6,7 and 12, the subject valves will be exercised on a cold shutdown frequency. The Valve Test Table and Justi6 cation, however, support testing at refueling outages. The refueling outagejustiGcation alternate testing section should be revised to agree with the Valve Test 13

Table and justification. Additionally, RJ-6 incorrectly identifies I BBV-044, the correct valve number is I BBV-047.

6.8 The deferral of testing in RJ-8 does not comply with the Code, however, the proposed alternate was evaluated in Table 4.1 and it is recommended that relief be granted in accordance with 10CFR50 55a(f)(6)(i). The licensee should submit this information in the form of a relief request in future program revisions.

6.9 The alternate testing section of the CS-7 indicates that all the valves will be stroke timed closed only. The ftmetion section of thejustification, however, indicates an open and closed safety function for all the valves. Additionally, per the Table valves IBCHV-F017C&D and IBEllV-F005A&B are only stroke exercised open, and 1 BCHV-F022 and 23 are only exercised closed.

The licensee should review the function and testing of these valves and revise the program accordingly.

6.10 No exercise closed test is specified in Table 3 for the CS-8 subject valses. However, these l valves are PlVs and have a safety ftmetion to close per thejustification. The licensee should evaluate the practicality of testing the valves in the closed direction and revise the table and justification accordingly. )

l 6.11 The downstream condensate storage tank supply to RHR loop (i.e., I APV-043,46,55, and 58) and RCIC (i.e., I APV-051) check valves are included in the IST Program with a safety function to close. These simple check valves do not have position indication and there are no test connections between these valves and the upstream valves. It is not apparent how these in I series check valves are verified closed. The licensee is referred to NUREG-1482, Section 4.1.1 for guidance regarding closure verification for series check valves without intermediate test connections. Additionally, the upstream valves (i.e., l APV-042,45,50,54, and 57), which )

provide the safety related boundary, are not included in the IST program. The licensee should l review the function of these valves, and revise the program, as necessary.

6.12 The IST Program Valve Test Table, Table 3, only includes a safety function to close for the RCIC pump discharge check valve, IBDV-010. This valve also has a safety function to open, and the table includes an exercise open. The licensee should correct the safety position entry.

6. 3 The IST Program Valve Test Table, Table 3, includes safety functions in the open and closed dkection for the RCIC pump CST suction check valve (IBDV-002). It is unclear how this valve is verified to close quarterly since there is no position indication and during the quarterly RCIC puup test the RCIC system takes suction from the CST and not the suppression chamber.

The licensee should review the testing performed for this valve, and revise the program accordingly.

6.14 The IST Program Valve Test Table, Table 3, does not include any testing for the RCIC pump suppression chamber suction check valve, IBDV-004, although an active safety function to open is indicated. The licensee should review the testing performed for this valve, and revise the program accordingly.

6.15 The RCIC turbine exhaust and vacuum pump di.ccharge check valves, IFCV-003 and IFCV-010, are exercised closed per the IST Prog - i Valve Test Table, Table 3. There is no position 14

I indication and it is not apparent how these valves are verified closed quarterly. The licensee snould review the test ing performed for these valves, and revise the program accordingly.

6.16 There are numerous instances of normally open valves in the RCIC system where Table 3 of the IST Program includes both an open and closed safety function, but the valves are only required to be exercised closed (e.g., IFCHV-F059, F007, F008, F062, F084,4282, and 1FCXV-41508).

The licersee should review the functions of these valves, and revise the IST Program accordingly. Per the Code, valves are required to be exercised to the position (s) required for the valves to fulfill their safety function (s). The licensee is referred to the IST Workshop Minutes (Ref.14), Question 2.1.9, for additional guidance.

6.17 The RCIC vacuum tank condensate pump discharge check valves, IFCV-030 and 1BDV-023 have a safety function to open per Table 3 of the IST Program. The pump itself, however, is not included in the IST Program. The licensee should review the function of this pump and the associated valves and revise the program accordingly. The licensee is also referred to TER Section 6.23 on skid-mounted equipment. i 6.18 Table 3 of the IST Program includes only an open safety function for the service water to fuel pool cooling makeup check valves (1BCV-423 and IEAV-557). The license should review the function of the valves to ensure that they do not have a safety function to close to prevent the fuel pool to drain to the open service water system. The three other motor-operated valves in each of these lines also only have a safety function to open.

6.19 it appears that the 26" manual butterfly valves at the inlet of the SACS heat exchangers have l position indication, and as such, are required by the Code to have their position indication verified once every 2 years. The licensee should review these valves and revise the program, as necessary.

6.20 Technical Position TP-1, Section Ill(b) states that following maintenance, deviations between l the previous and new reference values will be identified, and analyzed to determine whether the change is consistent with the maintenance performed, ifit is consistent, the new reference value will be used. If the change is inconsistent with the maintenance, the IST Program Manager may elect to perform further evaluations and deternie if the previous value should remain as the reference value. The NRC in Ref.14, Question 1.5.3 has provided some guidance on this issue. The response to the question states that the Code requires new reference values to be determined or the previous reference value to reconfirmed. There are no provisions for a tolerance around the previous values or an evaluation. This issue has been brought to the ASME's attention and the Code Committee is pursuing resolution. Until such time as the ASME provides clarification through an interpretation or a code change, the licensee must comply with the Code, or submit a relief request 6.21 Technical Position TP-2, which discusses th. allowable variance from pump reference points, states that "To meet the requirements of NUREG-1482, the sum of the specified tolerance (rounded to the nearest readable increment) and the indicated accuracy must be less than or equal to 2 percent of full scale." If this is met, the TP-2 states that no relief, NRC approval, or further evaluation is required. NUREG-1482, Section 5.3, however, states that "A total tolerance of 2 percent of the reference value, not full scale, is allowed without approval from the NRC. The licensee should revise the position and the implementing procedures to comply 15

I 1

I with the guidance in the NUREG. Additional guidance from the NRC is provided in Ref.14, Question 3.2.1 and 3.2.2.

6.22 Technical Position TP 3, discusses check valve sample disassembly. OMa-1988, Part 10 now includes check valve disassembly as a means to verify valve obturator position. The Code requires each valve to be disassembled and inspected each refueling outage. If a sample program is proposed, a relief request is necessary, w hich includes a discussion of the burden of disassembling e.ach valve each refueling outage. Additionally, if the licensee is proposing to disassemble and inspect valves at a refueling frequency, even if a sample program is not proposed, a refueling outagejustification is required. The licensee has not included any relief requests for sample disassembly and inspection or proposed disassembly and inspection in any of the refueling outagejustifications.

6.23 Technical Position TP-4 discusses skid-mo nted components and states that "The individual components will not be specifically listed in the IST Program and will not be individually tested." As discussed in Ref.14, Question 1.6.3, there is no requirement for the format of information presented in the IST Program. The licensee should, however, document in the IST Program or basis document individual components that are considered skid-mounted and that their operational readiness is verified during the test of the major component. This documentation, either in the IST Program or basis document, may be subject to NRC inspector review.

7.0 REFERENCES

1. Letter, E.C. Simpson, PSE&G, to USNRC, "lST Program Submittal-Interval 2," LR-N970808, December 22,1997. l

2. Letter, E.C. Simpson, PSE&G, to USNRC,"ASME Boiler and Pressure Vessel Code Pump l Inservice Testing Relief Request," LR-N98172, April 7,1998. )

1. Title 10, Code of Federal Regulations, Section 50.55a, Codes and Standards. j

4. ASME Boiler and Pressure Vessel Code,Section XI, Rules for Inservice inspection of Nuclear Power Plant Components,1989 Edition. i

5. ASME/ ANSI OM-1987, Part 1," Requirements for Inservice Performance Testing of Nuclear Power Plant Pressure Relief Devices."

6. ASME/ ANSI OMa-1988, Part 6," Inservice Testing of Pumps in Light-Water Reactor Power Piants."

7. ASME/ ANSI OMa-1988, Part 10, " Inservice Testing of Valves in Light-Water Reactor Power Plants."

8. Standard Review Plan, NUREG 0800, Section 3.9.6, Inservice Testing of Pumps and Valves, Rev. 2, July 1981.

16

i.

. 9. - NRC Generic Letter 89-04," Guidance on Developing Acceptable Inservice Testing Programs,"

April 3,1989.

10. Minutes of the Public Meetings on Generic Letter 89-04, October 25,1989.

I1. Supplement to the Minutes of the Public Meetings on Gr.neric Letter 89-04, September 26, 1991.

12. NUREG-1482," Guidelines for Inservice Testing at Nuclear Power Plants," April 1995.

13. NUREG/CR-6396," Examples, Clarifications, and Guidance on Preparing Requests for Relief from Pump and Valve Inservice Testing Requirements," February 1996.

14. Memo to File," Summary of Public Workshops held in NRC Regions on Inspection Procedure 73756, ' Inservice Testing of Pumps and Valves,' and Answers to Panel Questions on Inservice -

Testing issues," from J. Calaccino, NRC, July 18,1997

15. Federal Register, Volume 62, Number 232, Page 63892," Proposed Rule on Industry Codes and Standards," December 3,1997.

16. NRC Generic Letter 91-18,"Information to Licensees Regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability,"

November 7,1991.

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