ML20202B329

Requests to Consult W/Commission Re Proposed Imposition of Civil Penalties in Amount of $600,000 for Violations Cited During 4 Insp Between 941205 & 950623

ML20202B329
Person / Time
Site:	Salem
Issue date:	08/17/1995
From:	Taylor J NRC OFFICE OF THE EXECUTIVE DIRECTOR FOR OPERATIONS (EDO)
To:	NRC COMMISSION (OCM)
Shared Package
ML20202B028	List: ML20202B025 ML20202B290 ML20202B329 ML20202B653
References
FOIA-97-325 NUDOCS 9712030097
Download: ML20202B329 (3)

Text

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1-EM: ...e Comissioners

. ERE: James M. Taylor Executive Director for Operations

SUBJECT:

PROPOSED CUMULATIVE CIVIL PENALTIES IN THE AMOUNT OF 5600,000 TO PUBLIC SERVICE ELECTRIC & GAS (PSE&G) COMPANY CONCERN VIOLATIONS AT SALEM UNITS 112 PURPOSE -

To consult with the Comission regarding a proposed ' Notice of Violation and Proposed Imposition of Civil Penalties" in the cumulative amount of $600,000 for numerous violations primarily identified by the NRC during four inspe-tions at the Salem facilities between December 5,1994, and June 23, 1995. Consultation with the Commission is required, in accordance with Section 111(2) of the enforcement policy, since the proposed penalties are in excess of three times the Severity level 1 values shown in Table 1A of the policy.

BACKGROUND:

During four inspections at the Salem facilities between December 5,1994, and June 23, 1995, the staff identified numerous violations of NRC requirements, including multiple failures to promptly identify and correct conditions adverse to quality at the facilities. Such failures have been the source of continuing performance problems at Salem, and have formed, in part, the basis for prior escalated enforcement actions issued by the NRC in the recent past, the most notable of which was a 3500,000 civil penalty issued to the licensee on October 5,1994 for violations identified as a result of an Augmented Inspection Team (AIT) inspection at the facility in April 1994. That AIT was chartered to follow-up on an automatic reactor shuto~uwn and two automatic actuations of the safety injection system in April 1994. That AIT was the fourth Ali sent to the Salem facilities since 1991.

DISCUSSION:

The violations that are the subject of the enclosed proposal are symptomatic of the continuing poor performance at Salem as a result of inadequate approaches to problem resolution, and include additional examples of licensee staff failing to promptly and effectively correct adverse conditions affecting the operability of safety-related equipment. Rather, the licensee frequently has worked around apparent problems, and attempted to defer decision-making or Justify operability of degraded equipment with insufficient basis. The proposed enforcement action is aimed at directing the licensee's attention toward the need to accomplish critical review and evaluation of degraded conditions, identify root causes, and establish. effective corrective actions, including prompt and rational operability decisions. The specific violations are described in the enclosed proposal, and were discussed with the licensee during a predecisional enforcement conference on July 28, 1995.

CONTACT: J. Lieberman, OE-4 15-2741 PROPOSED ENFORCEMENT ACTIM NOT FOR PUBLIC RELEASE WITHOUT APPROVAL OF THE DIRECTOR. OE c ,

0FFICIAL RECORD COPY a: PROP-SAL.MUL 9712030097 971126 KEENAN9 325 PDR L

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For The Connjssioners 2 The staff notes that as a result of conclusions reached relative to safety-related equipment operability, the licensee shutdown Unit 1 on Mzy 17,1995, and Unit 2 on June 7,1995. Afterwards, the NRC issued a Confirmatory Action Letter to the licensee on June 9,1995, which confirmed certain commitments made by the licensee, including the commitment to obtain NRC agreement prior to restarting either of the Salem units, and to perform a review of long-standing equipment reliability and operability issues, as well as the effectiveness and quality of management review ad oversight of activities at the f acility. Subsequently, the licensee has initiated action to comprehensively review, evaluate, identify, and correct equipment reliability issues; improve processes, such as work control, root cause assessment, and corrective action determination; and establish a personnel performance standard based on the recognition of accountability and responsibility for problem resolution and performance improvement. In order to accompitsh and manage the change necessary to ef fect performance improvement, a new senior management team has been established, including the Senior Vice President-Nuclear Operations, the Senior Vice President-Nuclear Engineering, the General Manager-Salem Operations, and Director-Quality Assurance and Nuclear Safety Review.

While the staff recognize that the licensee has taken significant steps in changing the management team at Salem, and shutting down both Salem units, the staff nonetheless proposes the cumulative penalties of $600,000 to further emphasize to the licensee the significance of these violations, as well as the continuing concern that the NRC maintains with regard tn the lack of substantial improvement in performance.

RECOMMENDATION:

If the Commission does not direct otherwise, within two weeks from the date of this paper, the staff intends to issue the proposed civil penalties to PSE&G.

COORDINATION:

The Office of General Counsel has no legal objection to this action. Also, while an 01 evaluation of this matter has been opened, Oi does not object to the issuance of this action.

RQII:

This paper and its issues should not be disclosed publicly because the matter involves predecisional enforcement issues.

James M. Taylor Executive Director for Operations

Enclosure:

Proposed Notice of Violation and Proposed imposition of Civil Penalties OFFICIAL RECORD COPY a: PROP-SAL.MUL i

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ATTACHMENT 1 EAs 95-62; 95-65;95-117 Mr. E. James Ferland Chairman and Chief Executive Officer Public Service Electric and Gas Company 80 Park Place Newark, New Jersey 07101

SUBJECT:

NOTICE OF VIOLATION AND PROPOSED IMP 051 TION Of CIVIL PENALTIES

- $600,000 (Inspection Reports Nos. 50-272/94-32; 50-311/94-32; 50-272/95-02; 50-311/95-02; 50-272/95-07; 50-311/95-07; 50-272/95-10; 50-311/95-14)

Between December 5, 1994 and June 23, 1995, Region I staff conducted the four subject inspections at the Salem Nuclear Generating Station, Hancocks Bridge, New Jersey and identified numerous violations of NRC requirements. The inspection reports were sent to you previously on March 30, April 7, May 24, and July 14, 1995, respectively. Several of the violations involved the failure to promptly identify snd correct conditions adverse to quality at the Salem facilities. On July 28, 1995, Mr. T. Martin, Regional Adtrinistrator, Region I conducted a predecisional enforcement conference with Mr. B. Simpson and other members of your sti.ff to discuss the violations, their causes, and your correctiva actions.

The violations are described in detail in the enclosed Notice of Violation and Proposed Imposition of Civil Penalties.

I have considered carefully these violations, several of which involve the failure to promptly respor' to, and correct, conditions adverse to quality at Salem. I am dismayed at the number and nature of the violations, and am disappointed with the overall response by your staff and management relative to decision-making and approach to resolution of these issues.

I have sent four Augmented Inspection Teams (AIT) to Salem in the past four years. AIT iispection; are rare and reserved for significant occurrences. Four AIT inspect 4ns in four years is extremely rare. As a result of the last of those fou" AIT inspections in April 1994, I issued a 5500,000 civil penalty on October f., 1994, for numerous violations associated with an event at the facility, including similar violations involving failure to recognire and effectively correct conditions that challenged the safe and uneventful operation of the Salem facilities. In my letter transmitting that civil penalty, I expressed my concerns about nonconservative operational decision-making at the facility, I raised questions regarding the manner in which management's expectations are established and comunicated to the Salem staff regarding their 0FFICIAL RECORD COPY a: PROP-!AL.MUL

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Company performance at the station. I noted that while I found your immediate corrective actions acceMable for that event, the NRC was unwilling to predict or assume success for your long-term actions because historically, the implementation of l such actions for past problems has proven to be ineffective. I further noted j that it-appeared that you have tolerated an atmosphere that accepts degraded l conditions rather than establishing an atmosphere of a high quality operating j environment.

I Now, approximately one year later, my concerns remain. For example, although Westinghouse informed you in March 1993 of nonconservatism in the setpoint methodology for low temperature overpressure transient conditions, the problem remained unresolved for more than a year and half. Two other exemples involved degraded equipment affecting switchgear ventilation equipment in Unit 1. and residual heat removal (RHR) minimum flow recirculation valves . in Unit 2. In these cases, your staff failed to respond promptly when component failures affecting these systems were first identified in December 1994 and January / February 1995, respectively. Even after it became more imperative to address these component issues, your staff delayed cperablidty decision-making until it was apparent that a basis could not be established to justify continued operation. Subsequently, the units were shut down in accordance with license '

requirements on May 16 and June 7,1995, respectively. Numerous other examples are described in the Notice. These example' indicate a management and staff attitude that is not conducive to the safe operation of a nuclear power plant.

This attitude and inclination to delay decision-making at Salem must change.

Problems must be addressed promptly t.nd directly rather than werked around. Root causes must be identified and effective corrective actions established. -

Operability of safety-related equipment must be ensured. It is-imperative that management assure that these changes occur before operation of the units is resumed.

I recognize that you have shut down both of the Salem units and have agreed, as noted in the NRC Confirmatory Action Letter sent to you on June 9,1995, to not restart the units without first obtaining NRC agreement. I also recognize that you recently have brought an entirely new management team to oversee the Sales and Hope Creek facilities. I further recognize the commitments by your management team, at the predecisional enforcement conference, to effect demonstrable performance improvement. Nonetheless, in order to reinforce to

-you, your management team, ind your staff, the seriousness with which we regard your deficient conduct of oiterations, cumulative civil panalties in the amount of $600,000 - are proposed for these violations which are classified either individually, or in the aggrer, ate, at Severity Lovel III in accordance with the

" General Statement of Policy and Procedures for NRC Enforcement Actions,'

.(Enforcement -Policy) (60 FR 34381, June 30,1995).

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0FFICIAL RECORD COPY a: PROP-5AL.MUL i

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Public Service Electric and Gas 3 Company The base civil ,enalty amount for each Severity Level 111 violation or problem is $50,000. In each case, I have decided to exercise enforcement discretion, after consultation with the Commission, and issue $100,000 penalties in each case so as to. appropriately reflect the NRC concern regarding the violations and causes, and to convey an appropriate message, given that (1) the Salem enforcemert history has not been good, (2) the majority of the violations were identified by the NRC, and (3) your prior actions to ensure problems are identified and corrected in a timely manner have net been effective.

You are required to respond to this letter and should follow the instructions specified in the enclosed Notice when preparing your response. In your response, you should document the specific actions taken and any additional actions you plan to prevent recurrence. After reviewing your response to this Notice, including your proposed corrective actions and the results of future inspections, the NRC will determine whether further NRC enforcement action is necessary to ensure compliance with NRC regulatory requirements.

in accordance with 10 CFR 2.790 of the NRC's " Rules of Practice," a copy of this letter, its enclosure (s), and your response will be placed in the NRC Public Document Room (POR). To the extent possible, your response should not include any personal privacy, proprietary, or. safeguards information so that it can be placed in the POR without redaction.

The responses directed by th's letter and the enclosed Notice are not subject to the clearance procedures of the Office of Management and Budget es required by the Paperwork Reduction Act of 1980, Pub. L. No. 96.511.

Sincerely, James M. Taylor Executive Director for Operations Docket Nos. 50-272; 50-311 License Nos. OPR-70; DPR-75

Enclosure:

Notice of Violation and Proposed imposition of Civil Penalties 0FFICIAL RECORD COPY a: PROP-SAL.MUL 4

Public Service Electric and Gas 4 i

Company cc w/ encl; L. Eliason, Chief Nuclear Officer and President J. Storz, Senior Vice President - Nuclear Operations E. Simpson, Senior Vice President - Nuclear Engineering J. Hagan, Vice President - Business Support C. Schaefer, External Operations - Nuclear, Delmarva Power & Light Company R. Burricelli, Director - External Af fairs C. Warren General Manager - Salem Operations J. Benjamin, General Manager - Quality Assurance and Nuclear Safety Review F. Thomson, Manager - Licensing and Regulation R. Kankus, Joint Owner Affairs A. Tapert, Program Administrator R. Fryling, Jr., Esquire M. Wetterhahn, Esquire P. MacFarland Goelz, Manager, Joint Generation Department, Atlantic Electric Company Consumer Advocate, Office of Consumer Advocate W. Conklin, Public Safety Consultant, Lower Alloways Creek Township State of New Jersey State of Delaware OFFICIAL RECORD COPY a: PROP-SAL.MUL

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LNCLOSURE NOTICE OF VICLATION AND PROPOSED IMPOSITION OF civil PENALTIES Public Service Electric and Gas Company Docket Nos.: 50-272; 50-311 ,

' Salem Nuclear Generatig Station License Nos.: OPR-70; DPR-75 Units 1 & 2 EAs95-062; 95-065;95-117 During four NRC 'nspections conducted between December 5,1994 and June 23, 1995, violations of NRC requirement: were identified. In accordance with the " General Statement of Policy and Procedure for NRC Enforcement Actions," (60 FR 34381; June 30,1995), the Nuclear Regulatory Commission proposes to impose civil penal-ties pursuant to Section 234 of the Atomic Energy Act of 1954, as amended (Act),

42 U.S.C. 228I, and 10 CFR 2.205. The particular violation: and associated civil

, penalties are set forth below:

1. 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, _ requires, in part, that conditions adverse to quality are promptly identified and corrected; and in the case of significant conditions adverse to quality, the cause of the condition shall be documented, appropriately reported to levels of management, and corrective action taken to preclude repetition.

A. Contrary to the above, a condition adverse to quality existed at the Salem Unit 2 facility from January 26, 1915, until June 7, 1995, in that the No. 22 Residual Heal Removal (RHR) pump minimum recirculation flow valve weuld not open on low RHR flow as required to prevent pump failure. Similarly, the same condition adverse to quality existed at the facility froa Feorury 9,1995, until June 7, 1995, for the No. 21 RHR pump minimum recirculation flow valve.

However, plant staff did not determine the cause of the failure or initiate corrective measures. As a risult, both trains of RHR for Salem Unit 2 were inoperable from February 9,1995 until June 7, 1995, when the plant was shut down due to this condition.

l This is a Severity Level lil Violation (Supplement 1)

Civil Penalty - $100,000 B. Contrary to the above, a condition adverse to quality existed at the 5alem Unit I facility from December 12, 1994, until May 16,1995, in that a failure of the No.12 safety related switchgear venulation supply fan was not recognized as a condition that failed to meet the design basis relative to ventilation of safety-related switch gear, and the plant staff did not initiate resolution of the condition or effect any corrective measures to resolve the condition promptly.

As a result from December 12, 1994, the licensee operated Unit 1 outside the design basis described -in the Updated Final Safety l

Analysis Report Section 9.4.6, failed to consider the matter as an 0FFICIAL RECORD COPY a: PROP-SAL.MUL l

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Enclosure 2 unreviewed safety question; and did not initiate any corrective action until a second fan motor failed on May 12, 1995. After a ,

delay in determining the operability of the system, the L; nit was -

shut down on May 16, 1995, due to the condition.

This is a Severity level !!! Violation (Supplement 1).

Civil Penalty - $100,000 C. Contrary to the above, the licensee was informed by Westinghouse on March 15, 1993, of a significant condition adverse to quality involving nonconservatisms in the setpoint methodology for the Pressurizer Overpressure Protection System (POPS) for low temperature overpressure transient conditions; however, the matter was not corrected adequately or promptly in that:

1. The licensee took nine months of analysis, from March 1993 to December 1993, to conclude that the corrected peak transient pressure would exceed pressure / temperature (P/T) limits as described in each unit's technical specifications limits.

2. The licensee initially dispositioned the matter, after its analysis, by administrative 1y limiting operation to two reactor coolant pumps when less than 200*f and increasing each unit's P/T limit by 10%, based on ASME code case N-514 that was not approved by the NRC for use at the Salem facilities;

3. In January 1994, at the latest, the licensee recognized the inappropriateness of using an unapproved code case and subsequently elected to take credit for the capacity provided by residual heat removal (RHR) system suction relief valve RH3 to augment Pressurizer Overpressure Protection System (POPS) rel ie f. The licensee's analysis indicated that with RH3 ,

available, the transient peak pressure would remain below the specified pressure / temperature limits, and the licensee too':

credit for the RH3 valve until April 1994; however, this corrective action was. deficient in that the licensee neither sought a license amendment, nor performed an analysis, pursuant to 10 CFR 50.59, to ensure that the change did not involve an unreviewed safety question.

This is a Severity Level III Violation (Supplement 1)

Civil Penalty - $100,000 D. Contrary to the above, on several occasions, conditions adverse to quality existed, but were not identified and promptly corrected, as evidenced by the following examples:

0FFEIAL RECORD COPY a: PROP-SAL.MUL

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1. On June 7, 1994, the licensee identified that material management documentation for limit switches related to the reactor head vent valves, improperly classified the components as non-safety related. A nuclear design discrepancy evaluation form (DEF) identified that a switch short circuit could render two head vent valves inoperable since the components were powered from the same comon circuit.

Notwithstanding, the DEF did not identify any concern relative to operability or safety, in February 1995, the licensee determined that non-safety related limit switches were actually installed in reactor head vent valves IRC41 and IRC43 at Salem Unit 1. Subsequently, the licensee failed to perform and document an engineering evaluation to demonstrate the acceptability of continued Salem Unit 1 operation with non-safety-related parts installed in a safety-related application.

2. On February 24, 1995, Unit No. I operators placed control of a Power Operated Relief Valve (PORV) in the manual mode, rendering it inoperable, and failed to adhere to the Technical Specification 3.4.3 action statement which required operators to close the block valve within one hour. A shift supervisor discovered the error and corrected it on February 25, 1995, about 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> later. This performance error is similar to a violation of the same technical specification requeement involving Salem Unit No. 2 on March 24, 1994.

3. On July 6,1994, safety-related reactor head vent valve 2RC40 failed to operate (stroke open) during testing while Unit No.

2 was in cold shutdown. Subsequently, the valve was returned to normal service on July 10, 1994, without any review or assessment in accordance with establishet' procedures; that is, the licensee failed to process this occurrence in accordance with the applicable " Work Control Process" procedure.

Consequently, this f ailure of a safety-related component was never documented and formally assessed relative to preventive maintenance, operability, actions to prevent recurrence, or generic implications.

4. An oil sample laboratory report, dated August 4, 1994, recomended resampling and changing the oil on the No. 21 high-head safety injection pump based upon a ten-7old increase in wear particle concentration. An oil analysis, dated November 28, 1994, identified high wear particle concentration in the No. 22 high-head safety injection pump speed increaser oil. In both these cases, the system _ engineer, though aware of the findings of the lab reports, did not initiate any follow-up evaluation or corrective measure, nor establish a 0FFICIAL RECORD COPY a: PROP-SAL.MUL

. Enclosure 4 bases for operability or reliability in view of the apparent degraded condition of the equipment. The degraded nature of the equipment was not entered into the Equipment Halfunction identification System (EMIS) until March 20, 1995.

5. A lab report, dated October 6. -1994, recommended resnling the Nu. 23 Auxiliary Feedwater (AFW) turbine lube oil cue to a detectable amount of rater contamination and an increase in wear particle concentration. However, the degraded nature of the equipment was not entered into the EMIS until March 27, 1995, and the system engineer did not initiate review, evaluation, or establish any basis for equipment operability or reliability.

6. LER 95-05 identified seven instances, between May 8,1990 and January 14, 1995, of pressurizer safety valves (PSVs) being beyond the 1% tolerance required by TS 4.0.5 for Unit 1. Four instances were identified between November 14, 1994, and January 14, 1995, which involved 2 of the 3 installed PSVs. In all instances, the vendor notified the appropriate system engineer by telephone and written follow-up reports. However, the responsible system engineer never initiated an Incident Report. Consequentlyt root cause, operability, and reportability actions were not accomplished.

7 On March 6,1995, May 3,1995, and May 8,1995, the Sales Unit I staff failed to determine the cause, correct, or prevent recurrence of failure of the Containment 100 foot elevation personnel airlock to pass its local leak rate test. As a result, from March 6,1995 until May 8,1995, the containment boundary was incapable of withstanding a single failure and continue to perform its intended function.

8. From February 29, 1992 until June 7,1995, Salem Unit I staff failed to correctly determine the cause or take action to I

preclude recurrence of failures of instrument lines connected to the jacket water cooling system for the No IB and No.1C emergency diesel generators.

9. From July ll,1992 until June 10, 1995, Salem staff failed tn determine the cause, evaluate the potential safety

[ consequences, and establish corrective action for an abnormal j condition affecting the No. 21 Residual Heat Removal discharge i

manual isolation valve (21RH10) which resulted in impact noise from the interior of the valve.

Collectively, these violations represent a Severity Level ill problem. (Supplement I)

Civil Penalty - $100,000 '

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. , Enclosure- 5 11.-

10 CFR Part 50,-Appendix 8. Criterion V, ' Instructions, Procedures, and

-Orawings", requt_res that activities affecting quality shall be prescribed by documented instructions,-procedures, or drawings of a type-appropriate to the circumstances,- and shall be accomplished in accordance with these instructions, procedures and drawings. Instructions, procedures, or '

' drawings shall _ include appropriate quantitative or qualitative acceptance criteria for determining _ that -important activities have been satisfactorily accomplished.  ;

Contrary to the above, during _a modification in May 1993, to install a drain system for the Salem Unit 2 pressuriter code safety loop seals - the licensee did not. ensure that an activity affecting quality was satisfactorily accomplished in that it did not adequately ensure that the drain valves were properly positioned prior to plant- startup .after the modification. Specifically, valve 2PR66, a valve'in a common drain line for the 2PR3, 2PR4, c.-d 2PR5, pressurizer safety valves, was left closed throughout the operating cycle between May 1993 and October 1994. As a result, the licensee operated Salen Unit 2 in that period with the loop ,

seals filled with water.

This is a Severity Level til Violation. (Supplement I)

Civil Penalty - $100,000 4

III.

10 CFR 50.59 allows licensees to make changes in the facility as described in the Final Safety Analysis Report FSAR without prior NRC approval, unless the proposed change involves (an un) reviewed safety question, or involves a change to the technical specification incorporated in the

. license. 10 CFR 50.59 (b)(2) requires licensees to establish a written safety evaluation which provides the basis for determining that the change does not involve an unreviewed safety question.

Contrary to the abcVe, on or about April 19, 1994, the licensee changed >

the pressurizer overpressure protection systems (POPS)-design basis by revising the limiting transient upon which the setpoint was based as described in Technical Specifications (TS) (TS 3.4.9.3 for Unit 1; and TS 3.4.10.3 'or Unit 2), FSAR Section 7.6.3.3, and the NRC Fafety Evaluation Report upon which the POPS technical specification was t ased, without p evaluating the change pursuant to 10 CFR 50.59 to ensure that the change did not involve an unreviewed safety question. The specific change in the limiting transient involved limiting the magnitude of mass addition. by procedural control of possible injection sources.

This is a Severity Level III Violation. (Supplement I)

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0 Enclosure 6 Pursuant to the provisions of 10 CFR 2.201, Public Service Electric and Gas Company (Licensee) is hereby required to submit a written statement or explanation to the Director Office of Enforcement, U.S. Nuclear Regulatory Commission, within 30 days of the date of this Notice of Violation and Proposed imposition of Civil Penalties (Notice). This reply should be clearly marked as a " Reply to a Notice of Violation" and should include for each alleged violation:

(1) admission or denial of the alleged violation, (2) the reasons for the violation if admitted, and if denied, the reasons why, (3) the corrective steps ,

that have been taken ani the results achieved, (4) the corrective steps that will be taken to avoid further violations, and (5) the date when full compliance will be achieved.

if an adequate reply is not received within the time specified in this Notice, an order or a Demand for information may be issued as why the license should not be modified, suspended, or revoked or why such other action as may be proper should not be taken. Consideration may be given to extending the response time for good cause shown. Under the authority of Section 182 of the Act, 42 U.S.C.

2232, this response shall be submitted under oath or affirmation.

Within the san time as provided for the response required above under 10 CFR 2.201, the Licensee may pay the civil penalties by letter addressed to the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, with a check, draft, money order, er electronic transfer payable to the Treasurer of the United $3tes in the amount of the civil penalty proposed above, or the cumulative amount of the civil penalties if more than one civil penalty is proposed, or may protest imposition of the civil penalties in whole or in part, by a written answer addressed to the Director, Office of inforcement, U.S.

Nuclear Regulatory Commission. Should the Licensee fail to answer witnin the time specified, an order imposing the civil penalties will be issued. Should the Licensee elect to file an answer in accordance with 10 CFR 2.205 protesting the civil penalties, in whole or in part, such answer should be clearly marked as an

" Answer to r. Notice of Violation" and may: (1) deny the violations listed in this Notice, in whole or in part, (2) demonstrate extenuating circumstances, (3) show error in this Notice, or (4) show other reasons why the penalties should not be imposed. In addition to protesting the civil penalties in whole or in part, such answer may request remission or mitigation of the penalties.

In requesting mitigation- of the proposed penalties, the factors addressed in Section VI.B.2 of the Enforcement Policy should be addressed. Any written answer in accordance with 10 CFR 2.205 should be set forth separately from the statement or explanation in reply pursuant to 10 CFR 2.201, but may incorporate parts of the 10 CFR 2.201 reply by specific reference (e.g., citing page and paragraph numbers) to avoid repetition. The attention of the Licensee is directed to the other provisions of 10 CFR 2.205, regarding the procedure fcr imposing civil penalties.

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Enclosure 7

Upon failure to pay any civil penalties due - which subsequently have been determined in accordance with the applicable provisions of 10 CFR 2.205, this matter may be referred to the Attorney General, and the penalties, unless compromised, remitted, or mitigated, may be collected by civil action pursuant to Section 234c of the Act, 42 U.S.C. 2282c.

The response noted above (Reply to Notice of Violation, letter with payment of civil penalties, and Answer to a Notice of Violation) should be addressed to:

Mr. James Lieberman, Of rector, Office of Enforcement, U.S.

Commission, 2738 One White Flint Nortn,11555 Rockville Pike, Rockville, MD 20852-N

- with a copy to. the Regional Administrator, Commission, that is the subjectRegion of this1,Notice.

and a copy to the NRC Resident inspector at the the extent possible, it should not include any persona safcguards information so that it can be placed in the POR without redaction.

However, if you find it necessary to include such information, you should clea

< indicate the specific information that you desire not to be placed in the PDR, and providefrom information thethe legal basis to tupport your request for withholding the public.

' Dated at Rockville, Maryland this day of 1995 l

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SUBJECT:

NOTICE OF VIOLATION AND PROPOSED IMPOSITION OF CIVIL PENALTIES

$600,000 Inspection Re > orts Nos. 50-272/94-32; 50-311/94-32; 50-272/95-02; 0-311/95-02; 30-272/95-07; $3-311/95-07; 50-272/95-10; 50-311/95-10)

Dear Mr. Ferland:

Between December 5, 1994 and June 23, 1995, Region I staff conducted the four subject inspections at the $ ales Nuclear Generating Station, Hancocks Bridge, New Jersey, and identified numerous violations of NRC requirements. The inspection reports were sent to you previously on March 30, April 7, May 24, and July 14, 1995, respectively. Several of the violations involved the failure to promptly identify and correct conditions adverse to quality at the Salem facility. On July 28, 1995, Mr. T. Martin, Regional Administrator, Region I, conducted a predecisional enforcement conference with Mr. B. Simpson and other members of your staff to discuss the violations, their causes, and your corrective actions. The vic'ations are described in detail in the enclosed Notice of Violation and Proposed imposition of Civil Penalties.

We have carefully considered these violations, several of which involve the failure to promstly respond to, and correct, conditions adverse to quality at Salem. The numaer and nature of the violations demonstrate inadequate performance by a licensee of the Commission. The past overall response by your staff and management relative to decision-making on operability issues and the approach to resolution of these issues has not been acceptable.

As you are aware, the NRC has sent four Augmented Ins 1ction Teams (AIT) to Sales in the past four years. AIT inspections are relatively rare and reserved for significant occurrences. Four Ali inspections' dispatched to one facility in four years is extremely rare. As a result of the last of those AIT inspections in April 1994, NRC issued a $500,000 civil penalty on October 5,1994, for numerous violations associated with an event at the facility, including similar violations involving failure to recognize and effectively correct conditions that challenged the safe operation of the Salem facility.

Jn our letter transmitting that civil penalty, we expressed concerns about nonconservative operational decision-making at the facility. We raised questions regarding the manner in which management's expectations are established and connunicated to the Sales staff regarding their pe<tformance at the station. We noted that while NRC found your imediate corrective actions O

l i

Public Service Electric 2 and Gas Company acceptable for that avent, the NRC was unwilling to predict or assume success for your long-term actions because historically, the implementation of such actions for past problems has proven to be ineffective. We further noted that it appeared that you have tolerated an atmosphere that accepts degraded conditions rather than establishing an atmosphere of a high quality operating environment.

Now, approximately one year later, our concerns remain. For example, although Westinggouse informed you in March 1993 of nonconservatism in the setpoint methodology for lor temperature overpressure transient conditions, the problem remained unresolved for more than 18 months. Two other examples involved:

l' degraded equipment affecting switchgear ventilation equipment in Unit 1, and 2) residual heat removal (RHR) minimum flow recirculation valves in Unit 2. In these cases, your staff failed to respond promptly when component failures affecting these systems were first identified in December 1994 and January / February 1995, respectively. Even after it became more imperative to address these component issues, your staff delayed operability decision-making untti it was apparent that a basis could not be established to justify continued operation. Subsequently, the two units were shut down in accordance with license requirements on May 16 and June 7,1995. Numerous other examples are described in the Notice, including f ailures to perform adequate testing of modifications and evaluation of changes. These examples indicate a management and staff attitude that was not conducive to the safe operation of a nuclear power plant.

This attitude and inclination to delay decision-making regarding licensed activities at Salem must change. Problemt must be addressed promptly and directly rather than worked around. Root causes must be identified and effective corrective actions established and implemented. Cperability of safety-related equipment must be ensured. It is imperative that ranagement assure that these changes occur before operation of the Caits is resumed.

We recognize that you have shut down both of the Salem units and have agreed, as noted in the NRC Confirmatory Action Letter sent to yuu on June 9,1995, not to restart either unit without first gaining NRC agreement. We also recognize that you recently have introduced an entirely new management team to oversee the Salem and Hope Creek f acilities. We further recognize the comitments by your new manage.nent team, at the predecisional enforcement conference, to effect demonstrable performance improvement. Nonetheless, in light of your past failures to achieve lasting corrective actions and in order to reinforce to you, your management team, and your staff, the seriousness with which we regard the deficient conduct of operations at Salem, cumulative civil penalties in the amount of $600,000 are propc:ed for six violations, each of which is classified at Severity Level 111 in accordance with the

' General Statement of Policy and Procedures for NRC Enforcement Actions,'

(Enforcement Policy) (NUREG 1600; 60 FR 34381. June 30,1995).

The base civil penalty amount for each Severity Level !!! violation is

$50,000. In each case, we have decided to exercise discretion, after consultation with the Comission, and propose a $100,000 civil penalty for I

hblic Servito tiectric 3 and Gas Company each vloistion, violations so asand and causes, to appropriately reflect themssage, to convey an appropriate NRC's given cuncern that rogarding)the (1

the selos enforcem<nt history has not been good. (t) the sijority'of the violations were identified by the NRC, and (3) your organtrations s prior actions to ensure problems are identified end corrected in a tiMly manner have not been effective. Were it not for your voluntary action in maintaining both units at the facility in a shutdown condition for an extended period to implement broad-scope and long term corrective actions, the enforcemert action utght. have been more severe.

You are required to respond to this letter and should follow the instructions specified in the enclosed Notice when preparing your response, in your response, you should document the specific actions taken and any additional actions you plan to prevent recurrence. After reviewing your response to this Notice, including your proposed corrective actions and the results of future inspections, the NRC will determine whether further NRC enforceu nt action is necessary to ensure compliance with NRC regulatory requirements.

In accordance with 10 CFR 2.790 of the NRC's ' Rules of Practice,' a copy of this letter, its enclosure (s)', and your response will be placed in the NRC Public Docuw nt Room (POR). To the extent possible, your response should not include any personal >rivacy, proprietary, or safeguards inforsation so that it can be placed in tie PDR without redaction.

1he responses directed by this letter and the enclosed Notice are not subject to the clearance procedures of the Office of Management and Budget as required by the Paperwerk Reduction Act of 1980 Pub. L. No. 96.511.

Sincerely, MuL.Yl bL. Milhoan hputy Executive Director for Nuclear Reactor Regulation Regional Operations and Research Docket Nos. 50-272; 50-311 License Nos. DPR-70; DPR-75

Enclosure:

Notice of Violation and Proposed Imposition of Civil Penalties cc w/ent):

L. Elinson, Chief Nuclear Officer and ' President J. Stort, Senior Vice President - Nuclear Operations E. Simpson, Senior Vice President - Nuclear Engineering J. Hagan, Vice President - Business Support C. Schaefer, External Operations - Nuclear, Delmarva Power & Light Company cc w/ enc 1: (SeeNextPage) l

f Public Service Electric 4 and Gas Company cc w/encil (Con't)

R. Burricellt, Otrector - External Affairs C. Warren, General Manager - Sales Operationt J. Benjamin, General Manager - Quality Assurance and Nuclear Safety Review F. Thomson, Manager - Licensing and Regulation R. Kankus, Joint Owner Affairs A. Tapert, Program Adelnistrator R. Fryling, Jr., Esquire M. Wetterhahn, Esquire P. MacFarland Goelz, Manager, Joint Generation Department, Atlantic Electric Company ,

Consumer Advocate, Office of Consumer Advocate W. Conklin, Public Safety Consultant, Lower Alloways Creek Township State of New Jersey State of Delaware t

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NOTICE OF V10LAil0N AND PROPOSED INPOSITION OF civil PEKALTIES Public Service Electric and Gas Company Docket Nos: 50-272; 50-311 Salem Nuclear Generating Station License Nos. OPR-70; DPR-75 Units 1 & 2 EAs95-062; 95-065;95-117 During four NRC inspections conducted between December 5,1994 and June 23, 1995, at the Salem Nuclear Generating Station of the Public Services Electric end Gas Company (Licensee), violations of NRC requirements were identified.

in accordance with the ' General Statement of Policy and Procedures for NRC Enforcement Actions,' (NUREG-1600; 60 FR 34381, June 30,1995), the Nuclear Regulatory Comission proposes to impose civil penalties pursuant to Section 234 of the Atoelc Energy Act of 1954, as amended (Act), 42 U.S.C. 2282, and 10 CFR 2.205. The particular violations and associated civil penalties are set forth below:

1. 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that conditions adverse to quality are promptly identified and corrected; and in the case of significant conditions adverse to quality, the cause of the condition shall be documented, appropriately reported to levels of management, and corrective action taken to preclude repetition.

A. Contrary to the above, a significant condition adverse to quality existed at the Salem Unit 2 factitty from January 26, 1995, until June 7,1995, in that the Licensee was aware that the No. 22 Residual Heal Removal (RHR) pump minimum recirculation flow valve would not open on low RHR flow as required to prevent pump failure. Similarly. the Licensee was aware that the same significa);t condition adverse to quality existed at the facility from February 9,1995, until June 7,1995, for the No. 21 RHR pump minimum recirculation flow valve. However, prior to June 7,1995, the Licensee failed to determine the cause of the valve failures or initiate corrective measures. (01013)

I This is a Severity Level III Violation (Supplement I)

Civil Penalty - $100,000 B. Contrary to the above, a significant condition adverse to quality existed at the Salem Unit I facility from December 12, 1994, until Nay 16, 1995, in that the No.12 safety related switchgear ventilation supply fan failed on December 12, 1994, and the Licensee did not initiate resolution of the condition or effect any corrective measures to resolve the condition promptly.

(02013)

This is a Severity Level Ill Violation (Supplement I).

Civil Penalty - $100,000 C. The Licensee was informed by Westinghouse on March 15, 1993, of a significant condition adverse to quality involving

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Notice of Violation 2 nonconservatisms in the setpoint methodology for the Prossurizer Overpressure Protection System (POPS) for low temperature overpressure transient conditions.

1. Contrary to Criterion XVI, the Licensee took nine months of analysis, from March 1993 to December 1993, to conclude that the corrected peak transient pressure would exceed pressure / temperature (P/T) limits as described in each unit's technical specifications limits. Af ter completing the analysis, from December 30, 1993, and continuing for approximately one month, the Licensee dispositioned the matter of the nonconservativism in the setpoint methodology for the POPS by 1) administrative 1y limiting RCS operation to two reactor coolant pumps when the RCS was less than 200*f and 2) increasing each unit's P/T limit by 105; the latter corrective actior, was inadequate because it utilized as a basis an unauthorized ASME Code Case (N-514), which the Licensee was aware was not acceptable pursuant to 10 CFR 50.55(a). (03013)

This is a Severity Level III Violation (Supplement 1)

Civil Penalty - $100,000

2. Contrary to Criterion XVI, in January 1994, following the Licensee recognizing the unacceptability of using unauthorized Code Case N-514 as a corrective action to disposition the POPS setpoint methodology, the Licensee elected to implement corrective action by taking credit for the relief capacity provided by RHR system suction relief valve RH3 to augment POPS relief capacity. However, as the Salem FSAR (Section 7.6.3.2) describes the POPS system to include two Power Operated Relief Valves (PORVs) and does not describe Valve RH3, this corrective action was inadequate because an evaluation was not performed to determine the acceptability of the use of Valve RH3 as part of 1he 00PS system. In addition, the Licensee failed to iden'.ify that on the receipt of a safety injection (SI) signa! a previously operating positive displacement charging nump's discharge, combined with the discharge from thehighht:dsafetyinjectionpumpthatstartsonreceipt of the SI signal, could have injected water mass into the RCS at a rate that could have prevented POPS from performing its function. (04013)

This is a Severity Level Ill Violation (Supplement !)

Civil Penalty - $100,000

0. Contrary to the above, on several occasions, conditions adverse to quality existed, but were not identified and promptly corrected, as evidenced by the following examples:

i Notice of Violation 3

1. On June 7, 1994, the Licensee identified that material  !

management documentation for limit switches related to the l

reactor head vent valves -improperly classified the  !

components as non-safety related. A nuclear design {

! identified that a switch discrepancy short circuit could evaluation render two femhea (DEF) d vent valves inoperable  ;

since the components were powered from the same cosmon  ;

circuit. Notwithstanding, the DEF did not identify any  ;

concern relative to operability or-safety. In February 1995, the Licensee determined that non-safety related limit  ;

switches were actually installed in reactor head vent valves a 3RC41 and lRC43 at Salem Unit 1. Subsequently, the Licensee failed to perfom and document an engineering evaluation to demonstrate the acceptability of continued Salem Unit 1 '

operation with non-safety-related parts installed in a safety-related application.

1 2. On February 24, 1995, Unit No.1 operators placed control of a PORV in the manual mode, rendering it inoperable, and failed to adhere to the Technical Specification 3.4.3 action  ;

statement which required operators to close the block valve  :

within one hour. A shift supervisor discovered that the -

PORY had been erroneously placed in the manual mode and ,

corrected it on Febratary 25, 1995, about 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br /> later.

3. On July 6,1994, safety-related reactor head vent valve  ;

2RC40 failed _ to operate (stroke open) during testing while

~

- Unit No. 2 was in cold shutdown. Subsequently, the valve .

was returned to normal service on July 10, 1994, without any review or assessment in accordance with established ,

_ procedures; that is, the Licensee failed to process this occurrence in accordance with the applicable ' Work Control-Process' procedure. Consequently, tits failure of a safety-related component was never documented and formally assessed relative _ to preventive maintenance, operability, actions to prevent recurrence, or generic implications.

4. An oil sample laboratory report, dated August 4, 1994, recommended resampling and changing the oil on the No. 21 high-head safety injection pump based upon a ten-fold increase in wear particle concentration. An oil analysis, ,

-dated November 28, 1994, identified high wear particle concentration in-the No. 22 high-head safety injection pump speed increaser oil. In both these cases, the system -;

engineer,. though aware of the findings of the lab reports, did not initiate any follow-up evaluation or corrective-  ?

- measure, nor-establish a. bases for operability or reliability in view of the apparent degraded condition of- '

the equipment. The degraded nature of the equipment was not entered into the Equipment Malfunction Identification System i (EMIS) untti: March 20 -1995.

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Notice of Violation 4

5. A lab repor', dated October 6,1994, recomended resampling the No. 23 Auxiliary Feedwater (AFW) turbine lube oil due to a detectable amount of water contamination and an increase in wear particle ;oncentration. However, the degraded nature of the equipment was not entered into the EMIS until March 2/,1995, and the system engineer did not initiate review, and evaluation or establish any basis for equipment operability or reliability.

6. LER 95-05 identified seven instances, between Nay 9,1990 and January 14, 1995, of pressurirer safety valves (PSVs) being beyond the 15 tolerance required by TS 4.0.5 for Unit

1. Four instances were identified between November 14, 1994, and January 14, 1995, which involved 2 of the 3 installed PSVs. In all instances, the vendor notified the appropriate system engineer by telephone and written '

follow-up reports. However, the responsible system engineer never initiated an Incident Report. Consequently, root cause, operability, and reportability actions were not accomplished.

7. On March 6,1995, May 3,1995, and May 8,1995, the Salem Unit I staff failed to determine the cause, correct, or prevent recurrence of failure of the Containment 100 foot elevation personnel airlock t. pass its local leak rate test.

8. From February 29, 1992 until June 7, 1995, Salem Unit I staff failed to correctly deter 61ne the cause or take action to preclude recurrence of failures of instrument lines connected to the jacket water coolir.g system for the No.18 and No.1C emergency diesel generators.

9. From July ll, 1992 until June 10, 1995, Salem staff failed to determine the cause, evaluate the potential safety consequences, 6,id establish corrective action for an abnormal condition affecting the No. 21 Residual Heat Removal discharge manual isolation valve (21RH10) associated with impact noise from the interior of the valve. (05013)

This is a Severity Level til violation. (Supplement I)

Civil Penalty - $100,000

11. 10 CFR Part 50, Appendix B, Criterion V, ' Instructions, Procedures, and Drawings", requires that activities affecting quality shall be prescribed by documented instructions, )rocedures, or drawings of a type appropriate to the circumstances, and s1all be accomplished in accordance with these instructions, procedures and drawings.

Instructions, procedures, or drawings shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished.

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

4 Notice of Violation 5 Contrary to the above, following a modification in May 1993, that installed a drain system for the Salen Unit 2 pressurizer code safety loop seals, the Licensee did not ensure that an activity affecting quality was satisfactorily accomplished in that the procedure that directed the installation of the modification to the pressurizer code safety loop seals drains did not adequately ensure that the drsin valves were properly positioned prior to plant startup after the modification.

Specifically, valve 2PR66, a valve in a common drain line for the 2PR3, 2PR4, and 2 PRS, pressurizer safety valves, was left closed throughout ,

the operating cycle between May 1993 and October 1994.(06013) r This is a Severity Level !!! Violation. (Supplement 1)

{

Civil finalty - $100,000 Pursunt to the provisions of 10 CFR 2.201, Public Service Electric and Gas Comptny (Licensee) is hereby required to submit a written statement or explanation to the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, within 30 days of the date of this Notice of Violation and Prososed Imposition of Civil Penalties (Notice). This reply should be clearly mar (ed as a ' Reply to a Notice of Violation' and should include for each alleged violation: (1) admission or denial of the alleged viulation, (2) the reasons for the violation if admitted, and if denied, the reasons why, (3) the

. corrective steps that have been taken and the results achieved, (4) the corrective stops that will be taken to avoid further violations, and (5) the date when full compliance will be achieved.

If an adequate reply is not received within the time specified in this Notice, an order or a Demand for Information may be issued as why the license should not be modified, suspended, or revoked or why such other action as may be proper should not be taken. Consideration may be given to extending the respense time for good cause shown. Under the authority of Section 182 of the Act 42 U.S.C. 2232, this response shall be submitted under oath cr a f fliwat t on.

Within the same time as provided for the response required above under 10 CFR 2.201, the Licensee may pay the civil penalties by letter addressed to the Director, Office of Enforcement, U.S. Wuclear Regulatory Commission, with a check, draft, money order, or electronic transfer payable to the Treasurer of the United States in the amount of the civil penalty proposed above, or the cumulative amount of the civil penalties if more than one civil penalty is proposed, or may protest imposition of the civil penalties in whole or in part, by a written answer addressed to the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission. Should the Licensee fail to answer within the time specified, an order imposing the civil penalties will be issued.

Should the Licensee elect to file an answer in accordance with 10 CFR 2.205 protesting the civil penalties, in whole or in part, such answer should be clearly marked as an ' Answer to a Notice of Violation' and say: (1) deny the violations listed in this Notice, in whole or in part, (2) demonstrate

-- , .- ,_ e _m._, e- m - -

Notice of Violdtion 6 extenuating circumstances. (3) show error in this Notice, or (4) show other reasons why the penalties should not be imposed. In addition to protesting the civil penalties in whole or in part, such answer may request remission or mitigation of the penalties.

In requesting mitigation of the proposed penalties, the factors addressed in Section VI.B.2 of the Enforcement Policy should be addressed. Any written

, answer in accordance with 10 CFR 2.205 should be set forth separately from the statement or explanation in reply pursuant to 10 CFR 2.201, but may incorporate parts of the 10 CFR 2.201 reply by specific reference (e.g.,

citing page and paragraph numbers) to avoid repetition. The attention of the Licensee is directed to the other provisions of 10 CFR 2.205, regarding the procedure for imposing civil penalties.

Upon failure to pay any civil penalties due which subsequently have been determined in accordance with the applicable provisions of 10 CFR 2.205, this matter may be referred to the Attorney General, and the penalties, unless compromised, remitted, or mitigated, may be collected by civil action pursuant to Secticn 234c of the Act 42 U.S.C. 2282c.

The response noted above (Reply to Notice of Violation, letter with payment of '

civil penalties, and Answer to a Notice of Violation) should be addressed to:

Nr. James Lieberman, Director, Office of Enforcement, U.S. Nuclear Regulatory Comission, One White Flint North,11555 Rockville Pike, Rockville, MD 20852-2738, with a copy to the Regional Administrator, U.S. Nuclear RegJiatory Commission, Region I, and a copy to the NRC Resident inspector at the facility that is the subject of this Notice.

i Because your response will be placed in the NRC Public Document Room (PDR), to the extent possible, it should not include any personal privacy, proprietary, or safeguards information so that it can be placed in the POR wittout redaction. However, if you find it necessary to include such information, you

should clearly indicate the specific information that you desire not to be ,

placed in the POR, and provide the legal basis to support your request for withholding the information from the public.

Dated at Rockville, Maryland this K,gday of 6cW 1995 3

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'4tachment 2 Chronology Of POPS Evaluation By PSE4G March 15, 1993 Westinghouse issues NSA-93-0058 on cold overpressure mitigation system nonconservatisms July 26, 1993 NRC Information Notice 93-58, 'Nonconservatism in low-Temperature Overpressure Protection for Pressurized-Water ,

Reactors,' is issued.

December 30, 1993 PSE&G memo MEC-93-917 recomends restricting the number of RCPs in operation, while in Mode 5, to no more than two RCPs. The memo takes credit for ASME Code Case N514 and closes the A13 item on NSAL-93-005B.

April 19, 1994 Discrepancy Evaluation 94-0060 was initiated after it was recognized that NRC approval is necesskry for use of the Code Case. Memo pointr out that even with 1 RCP operating in Mode 5, the existing POPS analysis shows a calculated peak pressure in excess of the Technical .

Specification limit. Memo also points out that the plant

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, design basis relies on one PORY set at 375 psig, and that ith the current plant configuration the RHR relief valve L

.f* w(RH3) would be available to mitigate LTOP transients.

PSE&G did not consider the DEF an operability concern, taking credit for the Code Case. DEF recommends either getting the Code. Case approved for use at Salem by the NRC or, completing the calculations for LTOP using the RH3 valve and revising the plant design basis.

May 26, 1994 PSE&G memo MEC-94-630 was issue'd, superseding HEC-93-917, and dispositions the issue based on an assessment that did not account for the setpoint er~ror introduced by RCPs running during the mass addition transient. Interviews with licensee personnel indicate that because operation of a RCP when RCS is water solid is precluded procedurally, the mass addition transient analysis did i

not account for the setpoint error associated with running RCPs. On this basis, the memo recloses the ATS item for the NSAL.

! June 29, 1994 During the evaluation of an unrelated DEF by a different department, the licensee detemines that the Configuration Baseline Document for CVCS contains an dp-

- error concerning control of the positive displacement l

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\* g charging pump. The document incorrectly states that the PDP is tripped by an SI signal. If the PDP is running l -/ . when the Si signal is initiated, and offsite power is available, the punip will not trip. In addition, engineering review had detemined that trip signais to the PDP will be blocked until the SI signal is reset.

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September 27, 1994 Problem Report No. 940927126 was initiated when a new worst case scenario was identified, during efforts to take credit for RH3. The scenario is: RCS in Mode 5 with a pressurizer bubble and one RCP running; then an inadvertent SI signal starts the centrifugal charging pump, collapses the bubble, and the RCP continues to run. pn, g The PR recognizes that the current design basis transient is not plausible and provides analysis showing the new y4 worst case scenario results in acceptable peak )ressures. X y-The PR states that P5E&G will pursue revising tie current b plant design basis and also seek a license change to take credit for RH3 (to add margin for future revisions of the PTcurvelimits). The PR requests that the Code Case approval be sought, to alleviate infringement on the current design basis without reanalysis, <

September 28, 1994 PSE&G memo NLR-194900 requests engineering provide additional analysis. The licensing engineers recognize that analyses have relied on the use of two PORVs And RH3 to mitigate the transient (two out of three valves would provide sufficient relief and meeting single failure criterion). Memo also questions new worst case not starting with a water solid RCS. Issue left open pending .

further engineering analysis and plans are made to apply for a license change (add RH3 to TS) and approval of the Code Case for both Salem units.

November 17, 1994 PSE&G initiates Incident Report No.94-419 and makes a 10CFR50.72 notification for Unit 1 being in an unanalyzed condition. The licensee recognizes that the PDP design discrepancy effects their analysis for PCPS. The additional mass input from the runtfing PDP causes a peak pressure for the mass addition transient of 474 psig.

This analysis was for a single PORV (due to single failure considerations) since no licensing action iiad been taken to have RH3 included in the design basis.

From a safety perspective: the licensee has three valves available, any two of which will mitigate the effects of an LTOP transient.

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Allegat. n e.: Rt.j fIf 9 Brench Chief (AOC) d'? I h"'

Site: 54' l e re-Acknowledged:, YEss - .lo lITA N 4 ) 54f.( Q) 3 Panel Date: 8/P!//0  % Confidentiality Grantedi Ye s e R' AL1,EGATION PANEL DEc!S!0NS ' freviousAllegationPanelsonissuIhs' o)

Attendees: Chair . [.fi/f' Branch Chief (AOC) - N'Wd S AC - /MA'I 5' - -

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Safety Significa7ce Assessment:

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Date and Time of Ibard: _ 2/16/95 3:30nm Lacadon of Board: DR we Room j

. i Licenter Name: PSE&O Salem Docket / License Naular(s): 50-272.273 DP .75 i Types M II,-aad Actisitees: Power Ranctor Last Day of lampaction: _ February 17. 1995 l

ATIE@EES Board Chainaam: L Winnins Emfortmaneet Representative: D. Holody .

Cognisant Secdon Chief: E. Kelly Respo.uible DRP Maanger (Rx Lir=maama): J. White 1And Insportor: D.Mov Others: B. McDeramt -

i My Fmlatad Violatsoem (include specifle requiriaments flotated) ,L[cenaat.fallad to notify NR C for 11 -ths &

sgttiguag[Jo onarais clant oas ida danien haain for 1 OPS.(50.72) In March L994 PSE&O revised the POPS daaien basis listed '

in FSAR without an USO evaluation. (50.591 See oronamed NOV attrehed.

Sa'aty Signific==/ Apparent Seserity levels: .Reammable --sace of anfetv nrovided by RHR auction relief valve (not gredited as natt of l' OPS in FS AR). Possibility of insaati=1 wrons doine.

Root causes: The issue was not entered into any diser-acy orocram until I vr after information from Waa'lashouse. lasue was manaaed crimanly by memorar.dum.

Method of Identification (NRC, Lkmee, Other State or Federal Inspector, Allegation, etc.): Alleration Conective Ardons Taken or Planned to Date: A 50.39 evaluation was does after airnificant discussion with NRC. the licensee maintains thar no NRC soproval for this tvoc of chaaae is necessary. N corrective actions for the less than adeaustg IDanpecteent of the issue have t.as I;rmated by PSE&O.

Prior Licemea Perfonnance (cps, Orders, No. of Viols, Similar Viols, SALPs): The licensee is a SALP 2 in enaineerior and a lack of attention to notential safety isanaa has been previously docmaanted.

Prior Notice of Previous Problems (i.e., Audits, ins, NJedas, NMSS Newsletters, etc.): The issue was first fomilv I;; mated to industry in a Westinchouse NSAL. March 1993. Thec manic in NRC IN93 58. dated July 1993. Information from allecer r, hows clant maamaa,est was aware of the menerie concem in February 1993.

Multiple Examples: Several occortunities to idaatify the lasue as a condition outside desien basis ttrouch the incident Report sutem and via 50 *12 were either missed or intentionally irnored. _

Duration: I voar and 8 months after balne notified of the problem (via Wearinehouse NSAL). the licensee made a 50.72 Ha, cit baaad on beine outside their NEW DES!ON BASIS.

Delegadon of Authority Detennination (Materials Licensee Only):

Board Recommendatiom: ,

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Attachment 2

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Chronology Of POPS Evaluation By PSE&G March 15, 1993 Westinghouse issues NSA-93-005B on cold overpressure mitigation system nonconservatisms July 26, 1993 NRC Information Notice 93-58, 'Nonconservatism In Low- i Temperature Overpressure Protection for Pressurized-Water Reactors," is issued.

December 30, 1993 PSE&G memo MEC-93-917 recommends restricting the number of RCPs in operation, while in Mode 5, to no more than two RCPs. The memo takes credit for ASME Code Case N514 and closes the ATS item on NSAL-93-005B.

April 19, 1994 Discrepancy Fvaluation 94-0060 was initiats after it was recognized that NRC approval is necessary for use of the Code Case. Memo points out that even with 1 RCP operating in Mode 5, the existing POPS analysis shows a calculated peak pressure in excess of the Technical Specification limit. Memo also points out that the plant design basis relies on one PORV set at 375 psig, and that with the current plant configuration the RHR relief valva (RH3) would be available to mitigate LTOP transients.

PSE&G did not consider the DEF an operability concern, taking credit for tk9 Code Casn. DEF recommends either getting the Code Case approved for use at Salem L/ the NRC or, completing the calculations for LTOP using the RH3 valve and revising the plant design basis.

May 26, 1994 PSE&G memo MEC-94-630 was issued, superseding MLC-93-917, and dispositions the issue bashd on an assessment that did not account for the setpoint er~or r introduced by RCPs running during the mass addition transient. Interviews with licensee personnel indicate that because operation of a RCP when RCS is water solid is precluded procedurally, the mass addition transient analysis did not account for ?.he setpoint error associated with running RCPs. On this basis, the memo recloses the ATS item for the NSAL.

i June 29, 1994 During the evaluation of an unrelated DEF by a different department, the licensee determines that the Configuration Baseline Document for CVCS contains an error concerning control of the positive displacement charging pump. The document incorrectl.v states that the ,

PDP is tripped by an SI signal. If the PDP is running when the SI signal is initiated, and offsite power is available, the pump will not trip. In* addition, engineering review had determined that trip signals to the PDP will be blocked until the SI signal is reset.

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September 27, 1994 Problem Report No. 940927126 was initiated when a new i worst case scenario was identified, during efforts to

• take credit for RH3. The scenario is: RCS in Mode 5 with a pressurizer bubble and one RCP running; then an

• inadvertent SI signal starts tne centrifugal charging

~

pump, collapses the bubble, and the RCP continues to run.

The PR recognizes that the current design basis transient is not plausible and provides analysis showing the new worst case scenario results in acceptable peak pressures.

The PR states that PSE&G will pursue revising t1e current '

plant design basis and also seek a license change to take credit for RH3 (to add margin for future revisions of the ,

PT curve limits). The PR requests that the Code Case approval be sought, to alleviate infringement on the current design basis without reanalysis.

. September 28, 1994 PSE&G memo NLR-194900 requests engineering provide -

additional analysis. The licensing engineers recognize that analyses have relied on the use of two PORVs and RH3 to mitigate the transient (two out of three valves would provide sufficient relief and meeting single failure criterion). Memo also questions new worst case not starting with a water solid RCS. Issue left open pending further engineering analysis and plans are made to apply for a license change (add RH3 to TS) and approval of the Code Case for both Salem units.

November 17, 1994 PSE&G initiates Incident Report No.94-419 and makes a .

10CFR50.72 notification for Unit I being in an unanalyzed condition. The licensee recognizes that the PDP design diserapancy effects their analysis for POPS. The additional mass input from the runn'ing PDP causes a peak pressure for the mass addition transient of 474 psig.

This analysis was for a single PORY (due to single failure considerations) since no licensing action had been taken to have RH3 included in the design basis.

From a safety perspective: the licensee has three valves available, any two of which will mitigate the effects of an LTOP transient.

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• BACKGROUNO- Draft Inspection Report 2.1 Pressurizer Overpressure Protection System (POPS)

Backaround The POPS uses two pressurizer power-operated relief valves (PORVs) to mitigate low temperature (<312'f) over)ressure transients, keeping the peak pressure below 10 CFR 50 Appendix G limits for arittle fracture protection. The Appendix G limits are incorporated in Technical Specifications (TS) as pressure-temperature (P/T) curves specific to each unit's reactor vessel. The original design-basis mass addition transient for the P0pS was based on the start of a safety injection pump (780 gpm) and its injection into a water solid reactor coolant system (RCS). An NRC Safety Evaluation i Report, dated February 21, 1980, associated with Amend.nent No. 24 to the TS, approved the Salem POPS setpoint of 375 pounds per square inch gage (psig), based on the calculated peak transient pressure of 446 psig and a 14 psi margin (at thet time) below the Unit 1 Ap >endix G limit. The system was designed to meet the single failure criterion, wit 1 either PORY having sufficient relie' capacity to limit the peak pressure to less than the P/T curve limit.

The inspector noted that the P/T limits for each unit will decrease with successive operating cycles due to irradiation effects. Therefore, margin between the peak transient pressure and the P/T limit could change as subsequent revision of the Salem TS P/T curves are reviewed and approved by the NRC. The Unit 1 P/T curves were revised after the original POPS safety evaluation by TS Amendment No.108, which established a more restrictive limit of 450 psig at low temperatures. These curves are valid for up to 15 effective full power years of operation.

Setooint Nonconservatism 4 On March 15, 1993, Westinghouse issued a Nuclear Safety Advisory Letter (NSAL-93-0050),

informing PSE&G about nonconservatism in the setpoint methodology for POPS. The dynamic head, resulting from running reactor coolant pumps (RCPs) and the static head due to elevation of sensors relative to the reactor vessel midplane, were found not to have been considered in the original setpoint methodology. For each operating RCP, the difference between actual pressure and that sensed by the POPS instrumentation could differ by approximately 25 psi. Consequently, for a four-loop plant such as Salem, the sensed pressure (with all four RCPs running) could be as ciuch as 100 psi less than the actual pressure at the reactor vessel midplane (the area of concern fur P/T curves).

NRC Information Hotice (IN) 93-58, "Nonconservatism in Low-Temperature Overpressure Protection for Pressurized-Water Reactors," was is:ued on July 26, 1994. The IN noted that administrative restrictions, recommended by the Westinghouse NSAL, were intended to provide interim actions until either setpoints were verified to be accurate, or appropriately revised in TS.

After reevaluating the existing POPS analysis to address the NSAL concerns, PSE&G determined that the peak transient pressure would exceed the P/T limits of 450 psig for Unit I and 475 psig for Unit 2. With two RCPs running, the corrected peak pressure became 477 psig (for either unit since the analyzed transient is the same). At that point, the licensee dispositioned the issue by memorandum dated December 30, 1993, administrative 1y limiting to two the number of reactor coolant pumps in service below 200'F the most limiting area of the P/T curve) and increasing each unit's P/T limit by 10% us ng ASME Code Case N514.

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The inspector considered that, at the point PSEAG became aware that the margins to TS P/T limits for Appendix G brittle fracture considerations were not only reduced, but in fact lost (and could be potentially exceeded), both Salem Units were being operated in an unanalyzed condition outside the plants' design bases. Therefore, the condition was reportable and is an apparent violation of 10 CFR 50.72 and 73.

Operability Ou_estioned was initiated when the On PSE&GApril licensing 19, 1994, staff a Discrepancy discoveredEvaluation FormCode that the AME (DEFCase 94-0060)d ha been relied upon for closure of the issue without prios P approval. The DEF resolved the immediate o)erability concerns by taking credit for the capacity of the residual heat removal (lHR) suction relief valve (RH3) to augment the analyzed POPS relief capacity. Yalve RH3 has the same relief setpoint as POPa, but has a greater effective flow area and will actuatt faster than a PORV once its setpoint is reached. A subsequent analysis confirmed the licensee's initial judgement that the peak pressure would remain well below the Appendix G limit, if valve RH3 was credited. However, RHR relief RH3 was not initially credited in Amendment No. 24 to the Salem Unit 1 TS. Procedure changes also were initiated limiting RCP operation to one putp, thus further minimizing the dynamic head error when the plant was below 200'F. At this time, April 1994, the licensee concluded that there was no operability concern based on the additional margin 3rovided by th^ ASME Code Case and their compensatory measures. The inspector noted t1at ASME Code Case N514 was not (and is still not) ap) roved for use by the NRC, either generically via Regulatory Guide 1.85 or specifically for Salem by exemption from 10 CFR Appendix G.

Payised Desian Basit On May 26, 1994, the issue was once again thought to be closed based on a procedural requirement to achieve a pressurizer bubble before starting a RCP. Because of this requirement, it was casoned that only a correction for static head was necessary (relatively a small e.fect) and, therefore, the original analysis was still valid.

Af ter further consideration, the licensee determined that they should consider the effects of a running RCP on the POPS analysis. Since the existing POPS analysis did not provide acceptable results with a running RCP, engineering aersonnel established what they considered a " realistic" event as tfie basis for the P0)S setpoint analysis. The new transient begins with the reactor in HoJe 5 (<200'F), the positive displacement (PD) charging pump in service and one RCP running, whereafter an inadvertent SI signal would cause the centrifugal charging pump to start, the PD charging puup to trip, and the isolation of letdown to the chemical and volume control system. Evaluation of this scenario using the GOTHIC computer code (and the POPS setnoint of 375 psig) resulted in a peak pressure of 438 psig, below the P/T limits of each unit.

By September 1994, the licen;.ee believeu they had reached a final resolution of this issue because the new transient could be raitigated by the original POPS hardware using the existing 37E psig TS setpoint. Although the licensee had not changed the TS setpoint, they had changec' the justification for it by revising the limiting transi nt upon which the Unit 1 POPS TS 3.4.9.3a is based, as described in TS bases (Page B3/4 4-11). Further, the new transient that changed the design basis for POPS (and reduced the cargin of ?rotection to Appendix 0 P/T limits) based., The which Amenc ment No. 24 - and TS 3.4.9.3.a - was also description invalidated of thethe NRC's SER upon limiting transient and the design-bases for POPS in Salem FSAR Section 7.6.3.3 were, therefore, no longer relevant.

2

The inspector noted that, since March 1993, there was no formal quality record or corrective action " vehicle" that addressed this issue, and that only a memorandum (MEC-93-917) in effert " carried" the problem through the licensee's engineering processes.

Another opportunity tc evaluate thoroughly all relevant nuclear safety considerations of this issue was missed because, even as of the conclusion of this inspection, no formal written safety evaluation had been performed as required by 10 CFR 50.59. The o redur inspector was of the opinion that, since the margins to safety for overpressure a si protection (viz. peak pressure versus Appendix 6 P/T limits) had either been sho*

significantly reduced or ' ost altogether (depending upon which transient and assumptions are adopted as limiting), the new " limiting" transient represents a potential unreviewed safety question. OVhded g Res.ent Development ty"w'I By November IW4, the licensee recognized that an error, ret.ently identified in their configuration bat.eline document, would adversely effect their new POPS analysis. The configuration document stated that the PD charging pump trips off on a SI signal; he IS, however, if off-site )ower is available when the SI signal occurs, the pump continuer the V ".

to run and trip signa's are blocked (until the SI signal is reset). After discovering nange this error, the " realistic" analysis was revised to include the PD charging pump flow pe sQ and resulted in a peak pressure of 474 psig. ie VEDt -

Incident Report and concluded th(atIP)94-419, the Unit datedno 1 POPS November longer met 17,its1994, documented design-basis thisfailure single new information criterion becauN a single PORV could no longer mitigste the transient. PSE&G reported actio"{

this to the NRC under 10 CFR 50.72 as an unanalyzed condition for Salem Unit 1. IR 94-419 provided justification for the continued operation of Unit 1 based on RHR relief $ on uy[-

valve RH3 being available to augment POPS. With the three valves (2 PORVs and RH3) gty det available below 312'F, sufficient relief capacity would be provided. The licensee considered Unit 2 to be not reportable because it was still 1.0 psi below its P/T curve 'heset[;

limit. ye madt The inspector reviewed the licensee's documentation and interviewed personnel involved with the POPS issue during the 20 months between the NSAl. issuance in March 1993 and at des $'

PSE&G's 50.72 notification in November 1994. The inspector concluded that there is 3 ctR currently an adequate assurance of safety, based on the additional relief capacity of ompTet valve RH3 and the margin which can be gained with use of ASME Code Case N514. The relief capacity of any two of the three valves will be sufficient, since the relief area .ge 90 is, at minimum, double the original design. Based on the inspector's discussions with "of 14 representatives from the NRC Office of Nuclear Reactor Regulation (NRR), while not yet 'argin -

formally approved, ASME Code Case N514 is apparently acceptable.

On December 16, 1994, a conference call between PSE&G and NRC management ,sas held to o conc discuss the licensee's actions to resolve the POPS issue. During this call, the desi licensee committed to limit the number of RCPs in service when the RCS tem)erature is i ue d

below 200*F and to maintain procedural controls preventing an Intermediate Head Safety Injection Pump from injecting into the RCS. These commitments were restated in a letter from PSE&G issued later that same day. On December 22, 1994, PSE&G submitted an 33g3g application for NRC approval of ASME Code Case N514. Included in the submittal wers the ' gpne.

calculations supporting the new design-basis transient for POPS. PSE&G must credit RH3 inpon on Unit I to meet the design-basis single failure criterion for. POPS. However, for Unit 2, the licensee does not need to credit Valve RH3 because the peak pressure, based on 699fo a single PORV, is 1.0 psi below its P/T limit. 8[,an 3op 6th in s 3 ,32-0 0 A

1

The ins)ector noted that, since March 1993, there was no formal quality record or ,

i correct < ve action " vehicle" that addressed this issue, and that only a memorandum (MEC-  !93-917) in effect "estried" the problem through the licensee's engineering processes. l i Another opportunity to evaluate thoroughly all relevant nuclear safety considerations 1 of this issue was missed because, even as of the conclusion of this inspection, no '

formal written safety evaluation had been performed as required by 10 CFR 50.59. The inspector was of the opinion that, since the margins to safety for overpressure i protection peak pressure versus Appendix G P/T limits) had either been '

significantly(viz. reduced or lost altogether (depending upon which transient and assump are aduptad as limiting), the new " limiting" transient represents a potential unreviewed safety question.

Recent Develooment By November 1994, the lionsee recognized that an error, recently identified in their i configuration baseline document, would adversely effect their new POPS analysis. The configuration document stated that the PD charging pump trips off on a SI signal; however, if off-site power is available when the SI signal occurs, the pump continues 4 to run and trip signa's are blocked (until the SI signal is reset). After discovering this error, the " realistic" analysis was revised to include the PD charging pump flow and resulted in a peak pressure of 474 psig, incident Report (IR)94-419, d ted November 17, 1994, documented this new information and concluded that the Unit 1 POPS no longer met its design-basis single f ailure i criterion because a single PORV could no longer mitigate the transient. PSE&G reported  !

, this to the NRC under 10 CFR 50.72 as ai. unanalyzed condition for Salem Unit 1. IR 94-l 419 provided justification for the continued operation of Unit 1 based on RHR relief j valve RH3 being available to augment POPS. With the three valves (2 PORVs and RH3) available below 312*F, sufficient relief capacity would be provided. The licensee 4

considered Unit 2 to be not reportable because it was still 1.0 psi below its P/T curve limit.

The inspector reviewed the licensee's documentation and interviewed personnel involved with the POPS issue during the 20 months between the NSAL issuance in March 1993 and PSE&G's 50.72 notification in November 1994. The l'ispector concluded that there is currently an adequate ssurance of safety, bt, sed on the additional relief capacity of valve RH3 and the margin which can be gained with use of ASME Code Case N514. The relief capacity of any two of the three valves will be sufficient, since the relief area is, at minimum, double the nriginal design. Based on the inspector's discussions with representatives from the NRC Office of Nuclear Reactor Regulation (NRR), while not yet formally approved, ASME Code Case N5'4 is apparently ccceptable.

On December 16, 1994, a conference call between PSE&G and NRC management was held to discuss the licensee's actions to resolve the _ POPS issue. During this call, the licensee committed to limit the number of RCPs in service when the RCS temperature is below 200'F and to maintaia procedural controls preventing an Intermediate Head Safety Injectios, Pump from injecting into the RCS. These commitments were restated in a letter from PSE&G issued later that same day. On December 22, 1994, PSE&G tubmitted an apolication for NRC approval of ASME Ccdr Case Nbl4. lecluded in the submittal were the calculations supporting the new design. basis transient for P0FS. PSE&G must credit RH3 on Unit I to meet the design-basis single failure criterion for POPS. However, for Unit 2, the_ licensee does not need to credit Valve RH3 because the peak pressure, based on

_ a single PORV, is 1.0 psi below its P/T limit, s 3

. RCS Vent Path  ;

As discussed earlier, the POPS system.is designed to use two redundant PORVs, either of which can provide sufficient relief capability in case of a single failure. Both the  !

original analyses and the licensee's revised calculations shu, that the effective flow area of each PORV is sufficient to meet this requirement.

Salem TS requite cold (<312*F) overpressure protection, provided by either the redundant l PORVs (the POPS system) or a reactor coolant system vent of greater than or equal to  ;

3.14 square inches. The venting of the RCS is an alternative to having the POPS ,

operable. In the event a PORY fails and cannot be restored within 7 days, the reactor must be depressurized and the RCS must then be vented.

The inspector could find no specific justification for the TS-required vent area OF 3.14 square inches. However, the inspector concluded that the vent area in TS 3.4.9.3 was adequate based on: 1) the flow from a 2-inch pipe flange will encounter less flow a single PORY can be resistance shown to provido than flow throughrelief sufficient a PORY (2-inch capablity; and nominal 3) thepipe ventsize);

area 2)is passive protection -

and, therefore, does not need to be redundant.

i The inspector considered several aspects of PSE&G's actions to resolve the POPS issue  ;

over the past 20 months as less than adequate:

• The POPS issue was initially dispositioned based on using an unapproved ASME Code [

Case without prior NRC approval, and no operability determination was documented.  ;

• After the licensee identified that inclusion of the setpoint nonconservatism put them outside the plant's design basis, ne reports were made pursuant to 10 CFR 50472 and 73.

• Prior to revising the POPS design-basis transient described in the FSAR, the licensee failed to aerfora an evaluation pursuant to 10 CFR 50.59. At the time of the exit meeting, tiis evaluation had still not been completed.

• The NRC safety evaluation, that approved the POPS design and the 375 psig TS setpoint, was based, in part, on a margin of 14 psi between the peak transient pressure and the Appendir G limit. This margin has been reduced in the revised design-basis transient.

• The licensee has taken 1 year and 8 months to conclude that the NSAL nonconservatism would result in a condition outside the design-basis of Unit 1. The priority assigned to this issue was very low, and the due dates were extended twice, once more than allowed by administrative procedure.

The adequacy of the new design-basis for POPS is currer,tly under review by the NRC's Office of Nuclear Reactor Regulation. The inspector concluded that the licensee's failure to perform an adequate safety evaluation or otherwise resolve the POPS issue under a quality engineering process was not approariate. Further, during the fragmented process used to address the issue (memorancum superseding memorandum), several violations of NRC requirements occurred. The apparent violations are being considered for escalated enforcement in accordance with tie NRC Enforcement Policy set forth in Appendix C of 10-CFR 50.2. (EEI 50-272/94-32-01).

4

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Proposed NOV 1.10 CFR 50.72(b)l(ii)(B) requires licensees notify the NRC within one hour of any condition during operation that results in the nuclear power plant being outside its design basis.

The pressurizer overpressure protection system is designed to limit the seak reactor pressure during cold temperature transients to less than the limits esuablished by

• 10 CFR 50 Appendix G and hscribed in Technical Specification Figure 3.4-3.

Contrary to the above, on December 30, 1993 PSE&G concluded the pressurizer i overpressure protection system was not capable of limiting peak pressure to below the limits listed in Figure 3.4-3 and did not notify the NRC.

This is a Severity Level violation (Supplement 1).

2.10 CFR 50.59 allows licensees to make changes in the facility as described in the safety analysis report without prior NRC approval unless the proposed change involves an unreviewed safety question. 10 CFR 50.59, paragraph a(2 , requires licensees 'o evaluate proposed changes to determine whether an unreviewed) safety questi Contrary to the above, on or about April 19. 1994, PSE&G changed the pressurizer i overpressure protection systems (POPS) design basis transient for mass addition '. hat is described in the Salem ";&td "-9 Safety Analysis Report section 7.6.3.3, without evaluating the change pursuant to 50.59, paragraph a(2).

This'is a Severity Level violation (Supplement 1)  :

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This inspection evaluated the response of Public Service Electric and G. t (PSE&G) to information regarding the nonconservatisms identified in Tect'ical  :

Specification setpoint for the Pressurizer Ov3rpressure Protection Systems (POPS) at both Salem units. The nonconservatisms in the original Westinghouse-setpoint methodology were connunicatri to PSE&G in a letter from the vendor dated March 15, 1993. NRC Infonnation Notice 93-58, 'Nonconservatism in Low-Temperature Overpressure Protection for Pressurized-Water Reactors," dated July 26, 1993, reiterated the problems identified by Westinghouse.

2.0 FINDINGS Backaround The POPS uses two pressurizer power-operated relief valves (PORVs) to mitigate low temperature (<312*F) overpressure transients, keeping the peak pressure below 10 CFR 50 Appendix G limits for brittle fracture protection. The Appendix G. limits are incorporated in Technical 5)ecifications (TS) as pressure-temperature (P/T) curves specific to eac1 unit's reactor vessel. The original design-basis mass addition transient for the POPS was based on the start of a safety injection pump (780 gpm) and its injection into a water solid reactor coolant system (RCS). POPS was designed to meet the single failure criterion, with either PORV having sufficient relief capacity to 1;mit i

the peak pressure to loss than the P/T curve limit. An NRC Safety Evaluation '

Report, dated Fcoruary 21, 1980, associated with Amendment No. 24 to the TS, approved the Salem F0PS setooint of 375 pounds per square inch gage (psig),

based en the calculated peac transiant pressure of 446 psig and a 14 psi margin (at that time) below the Unit 1 Appendix G limit. Requirements for the Unit 2 POPS were incorporated into the unit's TS prior to initial startup and were approved based on the Unit 1 Safety Evaluation.

The P/T limits for all reactor vessels will decrease with successive operating cycles due to irradiation effects on the vessel materials. Therefore, margin between the reak transient pressure and the P/T limit will change as subsequent revisions of P/T curves for Salem are reviewed and approved by the NRC. The Unit 1 P/T curves were revised after the original POPS safety evaluation by TS Amer. ament No.108, which established a more restrictive limit of 450 psig at low temperatures. These curves are valid for up to 15 effective full power years of operation. The Unit 2 P/T curves were approved by .TS Amendment No. 86, which established a low temperature pressure limit of 475 psig. ,

Setooint Nonconservatism On March 15, 1993, Westinghouse issued a Nuclear Safety Advisory Letter (NSAL-93-0058) informing PSE&G about nonconservatism in the setpoint '

methodology for FOPS. The dynamic head, resulting from running reactor coolant pumps (RCPs) and the static head, due to elevation of sensors relative to the reactor vessel midplane, were found not to have been considered in the original setpoint methodology. Tne static head error for Salem is relatively l

l small, resulting in a 4.7 psi increasing the peak transient pressure.

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2 However, the dynamic head error is more significant. Each operating RCP will increase the difference between pressure at the reactor vessel midplane and that sensed by the POPS instrumentation by approximately 25 psi.

Consequently, for a four-loop plant such as Salem, the sensed pressure (with all four RCPs running) could be as much as 100 psi less than the actual pressure at the reactor vessel midplane (the area of concern for P/T curves).

These errors simply can be added to the original peak transient pressure since their effect is to offset (nonconservatively) the pressure at which POPS will actuate. NRC Information Notice (IN) 93-58, 'Nonconservatism in Low-Temperatu e Overpressure Protection For Pressurized-Water Reactors," was i issued on July 26, lo94. The IN noted that administrative restrictions, recomended by the Westinghouse NSAL, were intended to provide interim actions until either setpoints were verified to be accurate, or appropriately revised in TS.

In December 1993, after re-evaluating the original POPS analysis to address the NSAL concerns, PSE&G determined that the corrected peak transient pressure would exceed the P/T limits of both units. Even with limiting the number of running RCPs to two, the corrected peak pressure would be 485 psig (for either unit since the analyzed transient is the same). On December 30, 1993, the licensee dispositioned the issue by memorandum, administratively limiting the maximum number of RCPs in service to two, limiting the dynamic error in the mc,t restrictive area of the P/T curve (below 200*F), and ;ncreasing each unit's 7/T limit by 10% using American Society of Mechanical Engineers (ASME)

Code Case N-514.

The inspector considered that, at the point PSE&G became aware that the margins to TS P/T limits for Appendix G brittle fracture considerations were not only reduced, but in fact lost (and could be potentially exceeded), both Salem Units were being operated in an unanalyzed condition outside the plants' design bases. Therefore, the condition was reportable and is an apparent violation of 10 CFR 50.72 and 73.

Doerability Questioned An April 19, 1994, Discrepancy Evaluation Form (DEF 94-0060) identified that the ASME Code Case N-514 could not be been relied upon for closure of the issue without arior NRC approval. The DEF resolved the immediate operability concerns by ta(ing credit for the capacity of the residual heat removal (RHR)  ;

suction relief valve (RH3) to augment the analyzed POPS re'ief capacity. The spring operated relief valve, RH3, has the same setpoint as POPS, but has a greater effective flow area and will actuate faster than a PORV once its setpoint is reached. A subsequcnt nalysis confirmed the licensee's initial judgement that the peak pressure would remain well below the Appendix G limit, if valve RH3 was credited However, RH3 was not tiedited the original POPS analysis for Salem or the NRC Safety Evaluation for the system.

The April-DEF also initiated a-procedure revision request to limit the number of running RCPs in Mode 5 (below 200*F) to one pump, thus further minimizing the dynamic head error in the most restrictive region of the P/T curves. At this time, April 1994, the licensee concluded that there was no operability concern based on the additional margin provided by the ASME Code Case and

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3 their compensatory measures. The inspector noted that an exemption request for use of ASME Code Case N-514 had not been submitted by PSE&G at this time.

Use of the ASME Code Case would require pre-approval by the NRC, either generically to CFR 50.60.

via Regulatory Guide or specifically for Salem by exemp .

into the DEF process, the condition outside the design-basis was still not reported to the NRC.

The inspector independently assessed the availability and capability or rW for supr,lementing the POPS. Review of Salem integrated RHR system is aligned for shutdown cooling. procedures 10P-2, " Cold Shu operat' Standby To Cold Shutdown

• showed that RHR shutdown cooling will be in service when POPS is required to be operable (<312*F). One reason RH3 was not credited in the original POPS analysis was the automatic closure interlock that would shut the RHR suction valve on high RCS pressure, isolating RH3 from the RCS.

However, this interlock was removed from both Salem units in the late 1980's. This change was generically reviewod by the NRC as WCAP-ll736,

" Residual Heat Removal System Autoclosure Interlock Removal Report," and The conceptually approved in a Safety Evaluation dated August 8, and calibration schedule.

The inspector concluded that RH3 would be available to supplement POPS basw on the procedural requirements and wouH substantially reduce the peak transient pressure based on its design. However, crediting RH3 as part of POPS would require a change to Technical Specifications.

In a Nay 26, 1994, memorandun the issue was once again closed, this time based on a procedural requirement to achieve a pressurizer bubble before starting a RCP.

Because of tnis requirement, it was reasoned that only a correction for static head was necessary (relatively a small effe.t) and, therefore, the original analysis was still valid. The inspectoi noted that the procedural requirement to have a pressurizer bubble before starting any RCPs was in effect and reviewed in the 1980 NRC Safety Evaluation Report for POPS.

Although the issue was in effect " closed", analysis to support a license change for crediting RH3 as pcrt of POPS was pursued inItanticipation was duringofthis feture, more restrictive, revisions to the P/T curves.

analysis that the licensee determined that they should consher the effects of

-a running RCP on the POPS analysis.

Revised Desion Basis Transient Since it was known that the existing POPS analysis would not provide acceptable results with running RCPs, engineering personnel established what they considered a more " realistic" transient as the limiting event to justify the existing POPS TS setpoint. The original design-basis transient was simpiy the start of a safety injection pump (intermedi.te heaa Si at 780 gpm) and its injection into a water solid RCS. The licensee's new transient is mechanistic and relies upon procedural controls for limiting possible injection sources.

The new transient legins with the reactor in Mode S (<200*F), the positive displacement (PD) charging pump in service and one RCP. running, whereafter an

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inadvertent SI signal would cause the centrifugal charging pump (high head Si at 560 gpm) to start, the PD charging pump to trip, and the isolation of letdown to the chemical and volume control syste n. Evaluation of this transient (mitigated by a single PORV having a 315 psig setpoint) using the GOTHIC computer code resulted in a peak pressure of 438 psig, below the P/T limits of each nnit.

By September 1994, the licensee believed they had reached a final resolution and closed the issue a third tin.e because their new transient could be mitigated by the original POPS hardware using the existing 375 psig is setpoint. Although the licensee had not changed the TS setpoint, they had changed the justification for it by revising the litniting transient upon which the setpoint is based. The POPS TS and TS Basts for Salem Unit I and 2 are, TS 3.4.9.3, Bases 3/4.4.9.3 and TS 3.4.10.3, Bases 3/4.4.10.3, respectively.

Further, the new transient, which changed the design basis for POPS, also invalidated the NRC's SER upon which Amendment Ho. 24 - and both units' POPS TS - was based. The descripticn of the limiting transient and the desir:r.-

bases for POPS in Salem FSAR Section 7.6.3.3 were, therefore, no longen relevant.

The inspector noted that, since March 1993, no formal corrective action program addressed this issue and that only memorandums " carried" the problem through the licensee's engineering processes. The inspector was of the opinion that, another opportunity to cvaluate thoroughly all relevant nuclear safety considerations of this issue was missed becaure, even as of the conclusion of the exit meeting on December 19, 1994, no formal written safety evaluation had been performed as recuired by 10 CfR 50.59.

.'New" Transient Amended in November 1994, the licensee recognized that an error, recently identified in their configuration baseline document, would adversely effect their new POPS analysis. The configuration document stated that the PD charging pump trips off on a Si signal; however, if off-site power is available when the SI signal occurs, the pump continues to run and trip signals are blocked (until the SI signal is reset). After discovering this error, analysis for the new transient was revised to include the mass addition of the PD charging pump and resulted in a calculated peak pressure of 474 psig.

incident Report (IR)94-419, lated November 17, 1994, documented this latest discovery and concluded that the Unit 1 POPS no longer met its design-basis single failure criterion because a single P0'lY could no longer mitigatt the transient. PSE&G reported this to the NRC under 10 CFR 50.72 as an unanalyzed condition for Salem Unit 1. IR 94-419 provided justification for the continued operation of Unit 1 based on RHR relief valve RH3 being available to augment POPS. With the three valves (2 PORVs and RH3) available below 312*F, sufficient relief capacity would be provided. However, the licensee considared Unit 2 to be *not reportable" Sacause with a single PORV the peak transient was still 1.0 psi below its P/T curve limit.

The inspector was of the opinion that, since the margins to safety for overpressure protection (viz. peak pressure versus Appendix G P/T limits) had

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. transient and assumptions-are adopted as limiting), the new "liutting" l transient represents a potential unreviewed safety question. j RCS Vent Path l i

TS for both Salem units require cold overpressure protection be provided by either the :ddundant PORVs (the POPS system) or a reactor coolant system vent l of greater taan or equal to 3.14 square inches. Venting the RCS is an i alternative to having the POPS operabia and would be accomp1Md after i, depressurizing the RCS. The TS action statement for POPS re p ,,s that in the event a PORV fails and cannot be restored within 7 days, the reactor must be >

depressurized and vented through the 3.14 square inch vent witH n the next eight hours. .

The inspector could find no specific justification for the TS-required vent t area of 3.14 square inches. However, the inspector concluded that the vent .

area required in TS should be adequate based on: _1) the flow from a 2-inch pipe flange will encounter less flow resistance than flow through a PORV (2- .

inch nominal pipe size); 2) a single PORV (having lesser effective flow area) can be shown to provide sufficient relief capability even with its delay for actuation; and 3) the vent area is passive protection and, therefere, does not l

need to be redundant.

December NRC Insoection The inspector reviewed the licensee's documentation and interviewed personnel involved with the POPS issue during the 20 months betwasa the NSAL issuance in ,

March 1993 and PSE&G's 50.72 notification in November 1994. The inspector l concluded that there was an adequate assurance of safety, based on the additio..a1 relief capacity of valve RH3 and the margin which can be gained with use of ASME Code Case N-514. Based on the inspector's discussions with representatives from the NRC Office of Nuclear Reactor Regulation (NRR), while >

not. yet formally approved, ASME Code Case N-514 was apparently acceptable.

- On December 16,1994,' a conference call betwees PSE&G and NRC management was  :

held to discuss the licensee's actions to resolve the POPS issue. During this call, the licensee committed to limit the number of RCPs in service when the RCS temperature is below 200*f and to maintain procedural controls preventing an Intermediate Head Safety Injection r ap from injecting into the RCS. These commitments were formally submitted in a letter from PSE&G issued later that same day.

On December 22, 1994, PSE&G submitted an application for NRC approval of ASME Code Case N-514. - Included in the submittal were the caliulations supporting i the new design-basis transient for-POPS. PSE&G must credit RH3 on Unit 1 to L meet the desigr basis single failure criterion for POPS. However, for Unit 2, l

the Itcensee does.not believe they need to credit RH3 because the peak L pressure, based on a. single PORV is still 1.0 psi below the unit's P/T limit. ,

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L By letter dated February 13, 1995, the NRC issued an exemption from the requirements of 10 CFR 50.60 for Salem Units 1 and 2. This exemption permits

'fdng the safety margins recommended in ASME Code Case N-514 in lieu of the

.fety margins required by Appendix G to 10 CFR 50. Thereforo, each unit's bT curve limits for POPS can be increased by 10%; Unit l's limit becomer 195 4tg and the 'Jnit 2's becomes 522 psig.

k The inspector noted that the exemption resolves one licensing issue from the However, perspectivit that the plant can nu meet its original design basis.

this fact does not justify, or ameliorate the licensees actions bettman March 1993 and Wovember 1994. Several actions taken during that time appear to be violations of NRC requirements and were not acceptable means for addressing a potential safety issue. During the licensee's process they have however, brought into question whether the original POPS design-basis transient is L Pppropriate given todays knowledge. This licensing aspect of POPS is not yet resolved.

Conclusions The inspector considered several aspects of PSE&G's actions to resolve the POPS issue over the past 20 months as less than adequate:

• The POPS issue was initially dispositioned by taking exception to the requirements of 10 CFR 50.60 without prior NRC approval.

• When inclusion of the setpoint nonc;nservatism put the Salem Units outside the POPS design basis, the r9 ports to the NRC were not made pursuant to 10 CFR 50.72 and 73.

• No safety evaluation pursuant tu la CFR 50.59 was performed prior to revising the POPS design-basis transient described in the FSAR. As of the December 19, 1994 ed'. meeting, this evaluation had still not been completed.

• Several times during the Wwas approach to resolution, the margins of safety for POPS reviewed u. .ne tebruary 1980 NRC Safety Evaluation were reduced an not appropriately evaluated.

o It took almost 2 years (March 1993 to February 1995) for PSE&G to take some of the licensing r'tions necessary to resolve the NSAL nonconservatism and other issues still remain.

• The lowest priority possibir was assigned to this issue by the Operational Experience feedback prograr and the issue was not appropriately entered into a quality program for resolving engineering problems.

The adequacy of the new design-basis for POPS is currently under review by the NRL's Office of Nuclear Reactor Regulation. Pending their assessment of the

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licensee's proposed limiting design-basis tr6nsient for POPS, this issue is unresolved (URI 50-272,311/94-32-01).

The inspector concluded that the licensee's reliance on ASME Cde Cais N-514 without NRC approval, the failure to report a condition outsica the lisnts design basis, and the failure to perform an adequate safety evJuaUun of the revised POPS design basis transient are all apparent violations ei NRC requirements. Further, that the fragmented process used to address the issue (memorandum superseding memorandum) was not appropriate for potentially safety significant engineering issues. The apparent violations are being considered for escalated enforcement in accordance with the NRC Enforcement Policy set forth in Appendix C of 10 CFR 50.2. (EEI 50-272,311/94-32-02).

3.0 MANAGEMENT MEETINGS Licensee representatives were informed of the scope and purpose of this inspection at an entrance meeting conducted on December 5, 1994, Findings were periodically discussed with the licensee throughout the course of this inspection.

A telephone conference call was conducted between NRC and PSE&G management representatives ( December 16, 1994, to discuss the licensee's plans to resolve several aspects of the POPS issue. During this call PSE&G committed to taking several actions and subsequently documented these commitments in a letter to the NRC issued la+er that day.

The inspector met with the principals listed below to summarize preliminary findings on December 19, 1994. The licensee acknowledged the preliminary findiny a d conclusions, with no exceptions taken. Further, the bases for the p viiW Fy conclusions did not involve proprietary information, nor was any st.3 :nhemation expected to be included as part of the written inspection report.

Public Service Electric & Gas Comoany L. Catalfomo Operations Manager M. Danak Senior Staff, Mechanical Engineering J. Morrison Technical Department Manager M. Morroni Controls Maintenance Manager J. Ranalli Nuclear Mechanical Engineering Manager D. Smith Drincipal Engineer, Nuclear Licensing J. Summers Mechanical Maintenance Manager '

NRC C. Marschall Senior Resident inspector, DRP D. Moy Reactor Engineer, DRS J. White Section Chief, DRP

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