ML18102B421

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LER 97-009-01:on 970418,determined That Past Operation of ECCS Was Outside of Plant Design Basis.Caused by Failure to Address All Accident Scenarios Affecting Assumptions Made. Issued New NPSH Calculation Re RHR pumps.W/970627 Ltr
ML18102B421
Person / Time
Site: Salem PSEG icon.png
Issue date: 06/27/1997
From: GARCHOW D F, THOMAS B J
Public Service Enterprise Group
To:
NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
LER-97-009, LER-97-9, LR-N970412, NUDOCS 9707090070
Download: ML18102B421 (19)
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Text

  • Pt>blic Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, New Jersey 08038-0236 Nuclear Business Unit JUN 2 7 1997 LR-N970412 US Nuclear Regulatory Commission Document Control Desk Washington, DC 20555 LER 272/97-009-01 SALEM GENERATING STATION -UNIT 1 FACILITY OPERATING LICENSE NO. DPR-70 DOCKET NO. 50-272 Gentlemen:

This Supplemental Licensee Event Report entitled "Past Operation of the Emergency Core Cooling System Outside of Plant Design Basis" is being submitted pursuant to the requirements of the Code of Federal Regulations 10CFR50. 73 (a) (2) (ii) (B) and 10CFR50. 73 (a) (ii) (v). Attachment BJT c Distribution LER File 3.7 9707090070 970627 PDR ADOCK 05000272 S PDR ....,...., ' . l ttc: r*L ts :n \"11t;r hJn,b. r"i :: .'") f, ') s* . .. U \_, Li.-.

1 l/ot,J; -

David F. Garchow General Manager Salem Operations I l!lf II f llll f llll f llll j/lllJllll llll If II i if ' ! i I' 95-2168 REV. 6<94

  • NRC FORM 366 U.S. NUCLEAR REGULATORY COMMISSION APPROVED BY OMB NO. 3150-0104 (4-95) EXPIRES 04/30/98 ESTIMATED BURDEN PER RESPONSE TO COMPLY WITH THIS MANDATORY INFORMATION COLLECTION REQUEST: 50.0 HRS. LICENSEE EVENT REPORT (LER) REPORTED LESSONS LEARNED ARE INCORPORATED INTO THE LICENSING PROCESS AND FED BACK TO INDUSTRY.

FORWARD COMMENTS REGARDING BURDEN ESTIMATE TO THE INFORMATION (See reverse for required number of AND RECORDS MANAGEMENT BRANCH F33), U.S. NUCLEAR REGULATORY COMMISSION, WASHINGTON, DC 20555-0001, AND TO digits/characters for each block) THE PAPERWORK REDUCTION PROJECT (3150-0104), OFFICE OF MANAGEMENT AND BUDGET, WASHINGTON, DC 20503. FACILITY NAllE (1) DOCKET NUlllBER (2) PAGE (3) SALEM GENERATING STATION UNIT 1 05000272 1OF17 TITLE (4) Past Operation of the Emergency Core Cooling System Outside of Plant Design Basis EVENT DATE (5) LER NUMBER (6) REPORT DATE (7) OTHER FACILITIES INVOLVED (8) YEAR I FACILITY NAME DOCKET NUMBER MONTH DAY YEAR SEQUENTIAL I REVISION MONTH DAY YEAR NUMBER NUMBER Salem, Unit 2 05000311 04 18 97 97 009 01 06 27 97 FACILITY NAME DOCKET NUMBER ----05000 OPERATING 5 THIS REPORT IS SUBMITTED PURSUANT TO THE REQUIREMENTS OF 10 CFR §: (Check one or more) (11) MODE (9) 20.2201(b) 20.2203(a)(2)(v) 50.73(a)(2)(i)

50. 73(a)(2)(viii)

POWER 000 20.2203(a)(1) 20.2203(a)(3)(i) x 50. 73(a)(2)(ii)

50. 73(a)(2)(x)

LEVEL (10) 20.2203(a)(2)(i) 20.2203(a)(3)(ii)

50. 73(a)(2)(iii) 73.71 lml 20.2203(a)(2)(ii) 20.2203(a)(4)
50. 73(a)(2)(iv)

OTHER 20.2203(a)(2)(iii) 50.36(c)(1) x 50. 73(a)(2)(v)

Abstract below or in C Form 366A 20.2203(a)(2)(iv) 50.36(c)(2)

50. 73(a)(2)(vii)

LICENSEE CONTACT FOR THIS LER (12) NAME TELEPHONE NUMBER (Include Area Code) Brian J. Thomas, Licensing Engineer 609-339-2022 COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT (13) CAUSE SYSTEM COMPONENT MANUFACTURER REPORTABLE TO NPRDS CAUSE SYSTEM COMPONENT MANUFACTURER REPORTABLE TO NPRDS SUPPLEMENTAL REPORT EXPECTED (14) EXPECTED MONTH DAY YEAR 'YES INO SUBMISSION (If yes, complete EXPECTED SUBMISSION DATE). DATE (15) ABSTRACT (Limit to 1400 spaces, i.e., approximately 15 single-spaced typewritten lines) (16) As a result of an NRC Special Inspection 311/97-11, several issues concerning past operation of the Salem Emergency Core Cooling System were identified.

On April 18, 1997, a determination was made that prior to March 1996, Salem Generating Station was operated in the past in a condition that was outside the design basis of the plant due to the following reasons: 1) excessive Residual Heat Removal (RHR) system flows during the recirculation mode of Loss of Coolant Accident (LOCA) mitigation, and 2) the inability to ensure the successful completion of the switchover from the injection mode of LOCA mitigation to the recirculation mode without the possibility of interrupting ECCS pump flow to the core since the installation of the semiautomatic switchover modification in 1989. The root cause evaluation for the introduction of the USQs into the design and licensing basis identified the following causes: 1) failure to address all accident scenarios that could affect the assumptions made, and 2) failure to adequately review the licensing and design bases for the semi-automatic swapover.

These issues are reportable under 10CFR50.73(a)

(2) (ii) (B) and lOCFRSO. 73 (a) (2) (v). NRC FORM 366 (4-95)

  • NRC FORM 366A (4-95) U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER) TEXT CONTINUATION FACILITY NAME (1) DOCKET NUMBER (2) LER NUMBER (6) PAGE (3) 05000272 YEAR I SEQUENTIAL I REVISION NUMBER NUMBER 2 SALEM GENERATING STATION UNIT 1 97 --009 01 TEXT (If more space is required, use additional copies of NRC Form 366A) (17) Plant and System Identification Westinghouse

-Pressurized Water Reactor High Pressure Safety Injection System {BQ/-}* Residual Heat Removal/Low Pressure Safety Injection

{BP/-}

  • Energy Industry Identification System (EIIS) codes and component function identifier codes appear in the text as {SS/CC}. Conditions Prior to Occurrence OF 17 At the time of identification, Unit 1 was defueled and Unit 2 was in Mode 5. Description During Special Inspection 311/97-11, the NRC identified concerns associated with two 10CFR50.59 Safety Evaluations performed in July 1994, and March 1996 for the Emergency Core Cooling System (ECCS) at Salem. The NRC raised the following concerns associated with the July 1994 Safety Evaluation (UFSAR Change 94-37):
  • Changes were made to the Emergency Operating Procedures (EOPs) to eliminate the steps associated with opening the hot leg injection flow path through valve RH26. This EOP change was to reduce the flow of the Residual Heat Removal (RHR) pumps during the hot leg recirculation mode of operation following an accident.

The NRC stated, during the inspection, that Technical Specification (TS) 3.5.2.c.2 requires the use of the RH26 flow path and that a technical specification change should have been submitted to the NRC for review and approval prior to implementing the EOP changes.

  • Prior to the EOP changes to eliminate the RH26 hot leg injection flow path to reduce RHR pump flow, the RHR pumps would have been operated in a run-out condition that placed the system outside of its design basis.
  • To address reduced Net Positive Suction Head (NPSH) margin for the RHR pumps due to increased RHR pump flows during the cold leg recirculation mode of operation, credit was taken for the amount of air pressure inside containment following a loss of coolant accident (LOCA) to provide sufficient NPSH for the RHR pumps. Taking credit for containment air pressure to support NPSH requirements when the RHR pumps are taking suction from the containment sump was not included in the original design basis reviewed and approved by the NRC. As such, the use of containment air pressure is considered an Unreviewed Safety Question (USQ). The NRC also stated during the inspection that the required NPSH for the RHR pump flows used in this evaluation was based on extrapolation of the pump curve and was not validated and approved by the original pump manufacturer.

NRC FORM 366A (4-95)

  • NRC FORM 366A (4-95) U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER) TEXT CONTINUATION YEAR I SEQUENTIAL I REVISION 05000272 NUMBER NUMBER 3 OF 17 SALEM GENERATING STATION UNIT 1 97 --009 01 TEXT (If more space is required, use additional copies of NRC Form 366A) (17) Description (Cont'd) The concerns raised by the NRC associated with the March 1996 Safety Evaluation (UFSAR Change 96-04) are as follows:
  • The NRC approved the installation of the Salem Unit 2 semi-automatic switchover of the ECCS from the Refueling Water Storage Tank (RWST) to the containment sump based on: 1) successful completion of the switchover, 2) ECCS pump flow would be uninterrupted, and 3) 18 minutes existed to perform operator actions to complete the switchover.

The RWST drain down evaluation performed under this safety evaluation reduced the switchover time from the RWST to the containment sump from 18 minutes to 7.8 minutes and is considered a USQ.

  • The RWST drain down evaluation also determined that for Unit 2, in the case of a small break LOCA (SBLOCA) or Accumulator line break LOCA, the High Head Safety Injection (HHSI) and the Intermediate Head Safety Injection (IHSI) pumps may need to be shutoff before transfer to RHR suction is complete.

The overall limiting case for Salem Unit 2 was determined to be the SBLOCA for completion of switchover.

For the SBLOCA, the time available from the receipt of the RWST low level alarm to reaching the low-low level alarm was calculated to be 10 minutes. A SBLOCA analysis was performed by Westinghouse that stated that the amount of available water contained in the Reactor Coolant System (RCS) downcomer region would provide an additional 1.8 minutes of gravity feed water to meet the core cooling requirements of lOCFRS0.46 and 10CFR50 Appendix K. The 1.8 minutes and the 10 minutes to reach the RWST low-low level setpoint provided the operators 11.8 minutes to complete the switchover actions. Based on this calculation, the operators were being trained to complete the switchover within 11.8 minutes. Since the 11.8 minute acceptance criteria for completion of the switchover from the RWST to the containment sump credits the interruption of ECCS pump flow to the core during the switchover, the NRC considers this change to the drain down analysis to be a USQ. The NRC also questioned if the re-evaluation of the drain down analysis took into account an operator failing to perform a step in the EOPs or performing a step out of sequence.

  • The NRC also stated that due to the concerns identified by Westinghouse that led to the re-evaluation of the drain down analysis, the successful completion of the switchover from the RWST to the containment sump could not be demonstrated prior to March 1996. This condition is outside the design basis for Salem Unit 2. NRC FORM 366A (4*95)
  • NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION
  • (4-95) FACILITY NAME (1) LICENSEE EVENT REPORT (LER) TEXT CONTINUATION DOCKET NUMBER (2) LER NUMBER (6) 05000272 YEAR I SEQUENTIAL I REVISION NUMBER NUMBER SALEM GENERATING STATION UNIT 1 97 --009 01 TEXT (If more space is required, use additional copies of NRC Form 366A) (17) DESCRIPTION (Cont'd) PAGE (3) 4 OF 17 On April 18, 1997, a was made by PSE&G that prior to March 1996, Salem Generating Station was operated in the past in a condition that was outside the design basis of the plant because of the following reasons:
  • Excessive RHR system flows during specific ECCS recirculation mode alignments of LOCA mitigation could exist.
  • The successful completion of the switchover from the injection mode of LOCA mitigation to the recirculation mode, without the possibility of interrupting the ECCS pump flow to the core under certain break locations and single failure scenarios, was not demonstrated.

This condition has existed since the installation of the semiautomatic switchover modification in 1989. Use of Containment Air Pressure to meet RHR NPSH Margin and Elimination of RHR Hot Leg Injection In December 1987, the NRC issued Information Notice (IN) 87-63 concerning, "Inadequate Net Positive Suction Head in Low Pressure Safety Systems." The NPSH issues identified in IN 87-63 were the result of increased flow from the low head ECCS pumps. In late 1988, Westinghouse issued letter PSE-88-695 to PSE&G to document the potential for inadequate NPSH of low head ECCS pumps following realignment from the injection mode of operation to cold leg recirculation, assuming a single failure of one low head ECCS pump (i.e., RHR pump). In early 1989, Westinghouse issued another letter (PSE-89-507) to PSE&G that described several unintended (loop-around) flow paths that also had the potential to result in excessive low-head ECCS pump flows and also reduce NPSH margin. To address the issues identified in IN 87-63, Westinghouse performed an evaluation of ECCS pump flows. Westinghouse used a simple flow model of the Salem RHR system that was supported by existing piping/component resistances.

The flow model also used representative data from a similar 4-loop plant where Salem specific data was unavailable for loop-around piping resistances.

The results of this evaluation were transmitted to PSE&G by Westinghouse letter PSE-90-598 dated May 17, 1990. The most limiting RHR pump run-out flow was calculated to be 4830 gpm in the cold leg recirculation mode of operation (prior to the May 17, 1990, evaluation, the design run-out flow was 4500 gpm). Westinghouse concluded that adequate NPSH margin was available for the low head safety injection (LHSI) pumps during cold leg recirculation at a flow of 4830 gpm. Westinghouse suggested at the conclusion of this evaluation that an actual Salem loop-around piping resistance tabulation be performed to confirm the conclusion of this evaluation.

NRC FORM 366A (4-95)

  • NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION
  • (4-95) FACILITY NAME (1) LICENSEE EVENT REPORT (LER) TEXT CONTINUATION DOCKET NUMBER (2) LER NUMBER (6) 05000272 YEAR I SEQUENTIAL I REVISION -NUMBER NUMBER SALEM GENERATING STATION UNIT 1 97 --009 01 TEXT (If more space is required, use additional copies of NRC Form 366A) (17) DESCRIPTION (Cont'd) PAGE (3) 5 OF 17 In 1991, PSE&G asked Westinghouse to develop a thermal/hydraulic model of the Salem Unit 1 & 2 ECCS using the Westinghouse PEGISYS computer code. The models were developed based on Salem as-built piping drawings and associated component data. After initial development of the PEGISYS model for Salem Unit 2, the model was refined using preoperational system flow data from tests performed on the Salem Unit 2 ECCS. This was done to ensure that the model accurately calculated flows when compared to the preoperational test conditions.

Since Unit 1 specific preoperational flow tests were not performed, the defined conservatism (system resistances calculated based on Unit 2 flow test data) in the Unit 2 PEGISYS model was used to evaluate the Unit' 1 maximum flow via the Unit 1 PEGISYS model. This was considered reasonable based on similarities in component and system overall design and layout for both units. The results of the re-evaluation of cold leg recirculation flow were forwarded to PSE&G on October 19, 1992 via letter PSE-92-186.

The Unit 2 maximum calculated RHR pump flow was determined to be 4904 gpm and the available NPSH was determined to be greater than the required NPSH for the analyzed alignment.

The Unit 1 RHR pump maximum flow was calculated to be 5066 gpm and additional actions were determined to be necessary to demonstrate that acceptable NPSH would be available for the RHR pumps (i.e., verification of sump screen blockage assumptions).

Changes to the Emergency Operating Procedures (EOPs) or plant modifications were suggested by Westinghouse to reduce RHR pump maximum flow potential.

Changes to the EOPs were determined to be the primary solution path to address IN 87-63 concerns and other related issues. On August 24, 1993, Westinghouse transmitted to PSE&G via letter PSE-93-676, the "Salem RHRS EOP Evaluation Summary Report." This report provided the proposed EOP changes to eliminate the excessive RHR flows during the recirculation mode of operation following a LOCA. Westinghouse also stated that additional technical reviews and a 10CFR50.59 safety evaluation were required to implement the proposed changes to the EOPs. Use of Containment Air Pressure to meet RHR NPSH On May 12, 1994, Westinghouse transmitted a safety evaluation (SECL-93-291) to PSE&G to support the proposed changes to EOPs suggested in the August 24, 1993 letter. This safety evaluation took credit for containment air pressure to meet RHR pump NPSH requirements for both Unit 1 and 2. PSE&G generated a 10CFR50.59 safety evaluation on July 10, 1994, using Westinghouse SECL-93-291 as the basis to implement the EOP changes suggested by Westinghouse.

The safety evaluation addressed:

  • Unintended flow paths (i.e., loop around flows) and their consequences (NRC IN 87-63)
  • Excessive RHR pump flows during Hot Leg Recirculation, and
  • Excessive suction boost to the HHSI pumps and IHSI pumps NRG FORM 366A (4-95)
  • NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION
  • (4-95) FACILITY NAME (1) LICENSEE EVENT REPORT (LER) TEXT CONTINUATION DOCKET NUMBER (2) LER NUMBER (6) 05000272 YEARl SEQUENTIAL I REVISION NUMBER NUMBER SALEM GENERATING STATION UNIT 1 97 --009 01 TEXT (If more space is required, use additional copies of NRC Form 366A) (17) DESCRIPTION (Cont'd) PAGE (3) 6 OF 17 The Westinghouse evaluation calculated a new maximum RHR flow of 5110 gpm for Unit 1 and 4910 gpm for Unit 2 based on the alignment of the ECCS for cold leg recirculation as directed by the EOPs and assuming the failure of one RHR pump. To address the limiting (Salem Unit 1) high RHR pump flow (and reduced NPSH margin) during cold leg recirculation, the RHR pump NPSH available was recalculated to explicitly take credit for the equivalent water head associated with the air pressure inside containment to provide additional NPSH margin. The containment air pressure used in this evaluation.was the minimum Technical Specification containment pressure which was determined to be consistent with Regulatory Guide 1.1. Regulatory Guide 1.1 states that, "emergency core cooling and containment heat removal systems should be designed so that adequate NPSH is provided to system pumps assuming maximum expected temperatures of pumped fluids and no increase in containment pressure from that present prior to postulated loss of coolant accidents." However, after receipt of NRC IN 96-55 in October 1996 and responding to NRC questions concerning the Margin Recovery Project (MRP) license change request submitted on May 10, .1996, PSE&G questioned the methodology Westinghouse used for determining the amount of containment air pressure that could be credited for ECCS performance.

NRC IN 96-55 stated the containment air pressure to be used for ECCS performance needs to be calculated in accordance with Branch Technical Position (BTP) Containment Systems Branch (CSB) 6-1. BTP CSB 6-1 provides an acceptable method to meet paragraph I.D.2 of Appendix K to 10 CFR Part 50. Paragraph I.D.2 of Appendix K requires that the containment pressure used to evaluate the performance capability of a pressurized water reactor (PWR) ECCS not exceed a pressure calculated conservatively for that purpose. In responding to the NRC's questions associated with the MRP license change request, PSE&G requested that Westinghouse recalculate the amount of containment air pressure in accordance with BTP CSB 6-1. This calculation was completed by Westinghouse in February of 1997, with the conclusion that only 2.5 psia of containment air pressure could be used for NPSH considerations compared to the value of approximately 13 psia calculated in 1994. Since only 2 psia of containment air pressure was necessary to meet the NPSH requirements of the RHR pumps for Unit 1, adequate NPSH was concluded to be available.

Credit for containment air pressure for Unit 2 was not required since the flowrate for Unit 2 (4900 gpm) is less than the flowrate for Unit 1 (5110 gpm). The difference in flowrate between Unit 1 and 2 translates to a 2 psi lower required NPSH for the Unit 2 RHR pumps. NRC FORM 366A (4-95)

  • NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION
  • (4-95) ' FACILITY NAME (1) LICENSEE EVENT REPORT (LER) TEXT CONTINUATION DOCKET NUMBER (2) LER NUMBER (6) 05000272 YEAR I SEQUENTIAL I REVISION NUMBER NUMBER PAGE (3) 7 OF 17 SALEM GENERATING STATION UNIT 1 97 --009 01 TEXT (If more space is required, use additional copies of NRC Form 366A) (17) DESCRIPTION (Cont'd) Although the correct calculation method for determining containment air pressure for ECCS performance was performed in February 1997, the use of containment air pressure in the 1994 safety evaluation was not in accordance with the Salem design basis. During the licensing of the Salem Units, PSE&G provided the calculation of RHR NPSH to the NRC in a submittal dated March 13, 1980. This calculation demonstrated that sufficient RHR pump NPSH was available to support the operation of the RHR pumps during the recirculation mode of operation without the use of containment air pressure.

As stated in the Salem UFSAR, the method for calculating NPSH met the intent of Regulatory Guide 1.1. The use of containment air pressure in July 1994 introduced an Unreviewed Safety Question (USQ) into the design basis of Salem since the NRC approval as stated in the Safety Evaluation Report was based on the use of only the containment sump water level to provide adequate NPSH for the RHR pumps. The evaluation performed by Westinghouse in SECL-93-291, determined that the NPSH required for the RHR pumps at 5110 gpm is 25 ft. This NPSH value was determined by extrapolation of the pump curve by Westinghouse pump experts based on discussion with the pump vendor. To verify the accuracy of the NPSH value, PSE&G has obtained a revised pump curve from the vendor which confirms that the extrapolation performed by Westinghouse was accurate.

Elimination of RHR Hot Leg Injection The July 1994 safety evaluation also supported EOP revisions to reduce RHR hot leg recirculation flow following a LOCA. In SECL-93-291, Westinghouse informed PSE&G that a high RHR pump flow condition can occur during hot leg recirculation due to: 1. "loop around" flow should a RHR pump failure occur at the point when both SJ45 valves (supply valves to HHSI and IHSI pumps) are open, 2. higher IHSI pump flow due to operation of both hot leg discharge headers, 3. a higher flow in the RHR hot leg header (compared to either RHR cold leg header), and 4. ECCS high head and intermediate head suction boost (which increases the flows through these pumps). Prior to the EOP changes performed in 1994, the ECCS system would be aligned for hot leg recirculation as follows (see attached simplified figure of the ECCS):

  • One RHR train would be realigned to deliver flow to only the suction of the high-head ECCS pumps (low head flow to the cold leg was isolated but both RH19 valves were open so flow also went to the hot leg).
  • The other RHR train was realigned from supplying containment spray and cold leg injection to low-head hot leg injection through the RH26 valve while maintaining continuous flow to the high-head ECCS pumps. NRG FORM 366A (4-95)
  • NRC FORM 366A (4-95) U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER) TEXT CONTINUATION FACILITY NAME (1) DOCKET NUMBER (2) LER NUMBER (6) 05000272 YEAR I SEQUENTIAL I REVISION NUMBER NUMBER SALEM GENERATING STATION UNIT 1 97 --009 01 TEXT (If more space is required, use additional copies of NRC Form 366A) (17) DESCRIPTION (Cont'd) PAGE (3) 8 OF 17
  • Both intermediate head Safety Injection pumps would be realigned to deliver flow to the RCS hot legs via separate discharge headers (each header supplies two different RCS hot legs). To eliminate the potential for a high RHR pump flow condition during hot leg recirculation, the EOPs were revised in 1994 to eliminate the procedure steps associated with opening of the RHR hot leg injection path via the RH26 valve. The elimination of this flow path reduces the amount of flow delivered by the RHR pumps during hot leg recirculation so that a high RHR pump flow condition would not occur. The safety evaluation determined that the changes to the EOPs (which are used to mitigate a LOCA in Modes 1-3) did not impact the technical specifications.

TS 3.5.2.c.2 requires that the RHR system be capable of taking suction from the containment sump and discharging into two RCS hot legs. Compliance with the TS is maintained by demonstrating that the RHR pumps provide suction to the Safety Injection (SI) pumps and then through the SI pumps the RHR system discharges into two RCS hot legs. Although PSE&G believes that compliance with the TS was maintained for Modes 1-3, a License Change Request (LCR) was submitted to the NRC on April 25, 1997, to clarify the hot leg injection flow paths required for Modes 1-3. Mitigation of a Mode 4 LOCA is performed under abnormal operating procedure Sl/S2.0P-AB.LOCA-0001 and was not affected by this safety evaluation.

Although the mitigation of a Mode 4 LOCA was not affected by this change, the RH26 valve was removed from the IST program. Even though the RH26 valve was removed from the IST program (after the Units entered the extended shutdown), Operations Surveillance Test procedures continued to verify the operability of the RH26 flow path. A verification of the hot leg injection configuration required to mitigate a Mode 4 LOCA is being performed to ensure compliance with TS 3.5.3. Although the current procedures for mitigation of a Mode 4 LOCA are consistent with the Westinghouse Owners Group Abnormal Response Guidelines (ARGs), a review of the procedures has been initiated for possible enhancements related to initiation of hot leg injection.

Although corrective actions were taken to address the excessive RHR pump flow during hot leg recirculation, the impact on past operation was not evaluated in 1994. The hot leg recirculation configuration prior to the 1994 EOP changes may have resulted in the RHR pump operating beyond its actual run-out limit which could have challenged the operation of the pump. This condition is reportable in accordance with 10CFR50. 73 (a) (2) (ii) (B), any event or condition that resulted in the nuclear power plant, "being in condition that was outside the design basis of the plant", and 10CFR50.73(a)

(2) (v), any event or condition that alone could have prevented the fulfillment of the safety function of structures or systems that are needed to "mitigate the consequences of an accident." NRG FORM 366A (4-95)

  • NRC FORM 366A (4-95) U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER) TEXT CONTINUATION FACILITY NAME (1) DOCKET NUMBER (2) LER NUMBER (6) 05000272 YEAR I SEQUENTIAL I REVISION NUMBER NUMBER SALEM GENERATING STATION UNIT 1 97 --009 01 TEXT (If more space is required, use additional copies of NRC Form 366A) (17) DESCRIPTION (Cont'd) Switchover from Injection to Recirculation PAGE (3) 9 OF 17 On February 5, 1996, at the request of PSE&G, Westinghouse transmitted a report titled, "Salem Unit 1 and 2 RWST Drain down and Cold Leg Recirculation Engineering Report." The re-evaluation of the drain down evaluation was performed to address the following two issues; 1) Containment Spray (CS) pump flows greater than those used in the original drain down evaluation, and 2) specific operator action times may be longer than assumed in the original evaluation.

The current basis for the cold leg switchover assumes the operators can complete the switchover from injection mode to recirculation mode of operation within the time available based on the RWST drain down evaluation presented in Table 6.3-8 of the Salem UFSAR. In March 1996, a safety evaluation was developed to incorporate the new "RWST Drain down and Cold Leg Recirculation," evaluation into the Salem design basis and support the changes to the EOPs required by this new evaluation.

This safety evaluation identified inconsistencies between the assumptions used in the original UFSAR drain down evaluation and the plant performance characteristics.

Specifically the following items were identified:

  • Containment spray pump flows in the original UFSAR evaluation were based on design flows instead of maximum expected pump flows.
  • The Unit 2 semi-automatic switchover is not specifically addressed in the original UFSAR drain down evaluation.

The original UFSAR drain down evaluation is based on the manual Unit 1 switchover and does not address limiting single failures identified specifically for the Unit 2 automatic switchover, and

  • The original UFSAR drain down evaluation models intermediate steps in the switchover without clearly identifying required operator action times. Although a specific evaluation of the operator response times was not performed using the EOPs prior to March 1996, the review of the original RWST drain down evaluation under certain accjdent and single failure scenarios identified that the operators may not complete the switchover from injection to recirculation consistent with the assumptions (i.e., continuous HHSI or IHSI pump flow) used in the long term core cooling evaluation of record (Westinghouse NSAL-95-001)

This condition is reportable in accordance with 10CFR50.73(a)

(2) (ii) (B). The RWST drain down re-evaluation analyzed three specific scenarios for Salem Unit 1 and Unit 2. These scenarios were the Large Break LOCA (LBLOCA), Small Break LOCA (SBLOCA) and an Accumulator line break LOCA. The most limiting equipment failures were considered for each unit. NRC FORM 366A (4*95)

  • NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION
  • (4-95) FACILITY NAME (1) LICENSEE EVENT REPORT (LER) TEXT CONTINUATION DOCKET NUMBER (2) LER NUMBER (6) 05000272 YEAR I SEQUENTIAL I REVISION NUMBER NUMBER SALEM GENERATING STATION UNIT 1 97 --009 01 TEXT (If more space is required, use additional copies of NRC Form 366A) (17) DESCRIPTION (Cont'd) PAGE (3) 10 OF 17 The limiting single failure for Unit 1 switchover is one RHR pump failing to trip on demand. The switchover for Unit 1 is a complete manual switchover that requires the RHR pumps to be tripped in order to isolate the pumps from the RWST and transfer suction to the containment sump. The RHR pump that fails to trip will continue to drain down the RWST during the switchover.

The limiting single failure for Unit 2 switchover is the failure of one RWST isolation valve (RH4) to the RHR pump to close. PSE&G installed a semi-automatic switchover feature in Unit 2 to automatically realign the SJ44 valves, SJ113 valves and the CC16 valves upon receipt of the RWST low level alarm and arming of the SJ44 containment sump isolation valves. One of the features of the semi-automatic switchover is to ensure continuous operation of the RHR pump during the switchover.

This is performed by first opening the SJ44 containment sump isolation valves, then closing the RH4 RWST isolation valves to the RHR pumps. If the RH4 valve fails to close, the RWST will gravity drain to the containment sump since there are no check valves in the sump lines. The above single failures reduce the available time, from receipt of the RWST low level alarm until the low-low level setpoint for the RWST is reached, to complete the switchover from injection to recirculation.

Upon receipt of the low-low level alarm, any ECCS pump that is still taking suction from only the RWST is stopped and the suction valves from the RWST are closed. Upon closure of the suction valves, the realignment of the ECCS pump for recirculation mode of operation is completed (including restarting of any ECCS pump that was stopped).

Three operator actions were modeled in the RWST drain down re-evaluation.

The first action was closing the RHR cross-tie valves (RH19) . Once the operator reaches this step, one containment spray pump would be stopped, the Unit 1 RHR pumps would be stopped, and the Unit 2 semi-automatic switchover has changed the RHR pump suction from the RWST to the containment sump. The second significant time modeled was the restart of the RHR pumps for Unit 1. This is important to meet the long term cooling requirements for a LBLOCA. The third time modeled was the time at which the RWST low-low level alarm is reached for the SBLOCA and Accumulator line break LOCA. To maximize the time available to the operators to complete the switchover in the case of the SBLOCA and Accumulator line break LOCA, a lOCFRS0.46 analysis was performed to evaluate the long term cooling with a brief interruption of flow. For these breaks, the reactor vessel downcomer region and (for the Accumulator line break only) the reactor coolant system (RCS) cold leg water inventory provide sufficient core cooling should pumped flow be momentarily interrupted.

The allowable time with no pumped flow was calculated based on maintaining the core covered with water so there will be no core heatup. The allowable time for flow interruption for a SBLOCA was determined to be 1.8 minutes and for the Accumulator line break the time was determined to be 5.0 minutes. These brief interruptions allow for additional operator action time to align the charging pumps and IHSI pumps should the RWST low-low level alarm be reached prior to completion of switchover.

NRC FORM 366A (4-95)

  • NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION
  • (4-95) LICENSEE EVENT REPORT (LER) TEXT CONTINUATION FACILITY NAME (1) DOCKET NUMBER (2) LER NUMBER (6) 05000272 YEAR I SEQUENTIAL I REVISION NUMBER NUMBER SALEM GENERATING STATION UNIT 1 97 --009 01 TEXT (If more space is required, use additional copies of NRC Form 366A) (17) DESCRIPTION (Cont'd) PAGE (3) 11 OF The available times for operator actions to ensure that long term cooling would be maintained consistent with the 10CFR50.46 analysis were: Close RH19 Unit 1 4 minutes Unit 2 4 minutes Restart RHR Pump 8.9 minutes RHR pump is not stopped Complete Switchover 14 minutes 11.8 minutes 17 The above switchover time includes restarting any ECCS pump that is tripped on RWST low-low level. The Unit 1 worst case available time is associated with the Accumulator line break and the Unit 2 worst case available time is associated with the SBLOCA. Although the above evaluation determined that if the operators complete the switchover within these times the core will remain within 10CFR50.46 analysis limits, the interruption of pumped flow for Salem Unit 2 should have been identified as a USQ as discussed below. The approval for the implementation of the semi-automatic switchover feature in Salem Unit 2 was granted by the NRC under Amendment
69. As stated in the NRC's SER associated with Amendment 69, approval for installation of the semi-automatic switchover was based on having no interruption of flow of ECCS water to the core. (PSE&G submittals supporting Amendment 69 approval, informed the NRC that the semi-automatic switchover would provide uninterrupted flow from the ECCS pumps). Upon determination that the re-evaluation of the drain down analysis, in March 1996, would result in possible interruption of pumped flow, changes to the EOPs or plant hardware should have been developed to eliminate the interruption of pumped flow or the proposed changes to the Salem Unit 2 design basis should have been submitted to the NRC for review and approval The NRC stated that the reduction in the switchover times in the 1996 RWST drain-down analysis from the value of 18 minutes stated in NRC's SER for Amendment 69 was a USQ. A review of the references listed in the Amendment 69 SER and a search of other docketed correspondence revealed that the time stated in the NRC's SER was not consistent with documentation provided to the NRC. PSE&G only informed the NRC that a minimum time of approximately 8.5 minutes is available to the operator to perform the necessary switchover manual actions in the event of LBLOCA. PSE&G is submitting a letter to correct the switchover times specified in the Amendment 69 SER. NRG FORM 366A (4-95)
  • NRC FORM 366A (4-95) U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER) TEXT CONTINUATION FACILITY NAME (1) DOCKET NUMBER (2) LER NUMBER (6) 05000272 YEAR I SEQUENTIAL I REVISION NUMBER NUMBER SALEM GENERATING STATION UNIT 1 97 --009 01 TEXT (If more space is required, use additional copies of NRC Form 366A) (17) DESCRIPTION (Cont'd) PAGE (3) 12 OF 17 To support the changes performed under the March 1996 safety evaluation, operator training was performed to demonstrate that the operating crews could successfully complete the switchover from injection to recirculation within 11.8 minutes. Most operating crews completed the switchover within 8 to 9 minutes, however some crews took up to 11 minutes to complete the switchover.

Simulator scenarios developed to train the operators on the EOPs do not generally model specific component failures associated with worst case engineering analyses.

However, due to the time critical nature of performing the switchover evolution, the additional time to perform contingency actions may increase the time to complete the switchover alignment, possibly beyond the required time interval of 11.8 minutes. Although the Salem Units were not operated with the new revised EOPs and drain down analysis, the potential existed (since the EOPs were approved) that under certain accident and single failure scenarios, the operators may not have completed the switchover from injection to recirculation consistent with the assumptions (i.e., continuous HHSI or IHSI pump flow) used in the long term core cooling evaluation of record (Westinghouse NSAL-95-001)

This condition is reportable in accordance with 10CFR50. 73 (a) (2) (ii) (B), and 10CFR50. 73 (a) (2) (v). . To address the NRC's concerns on taking into account operator omission or commission (failing to perform a step or performing a step out of sequence) during the EOPs, a review of the development of the EOPs was performed.

The EOPs are developed based upon the guidance provided by the Westinghouse Owners Group Emergency Response Guidelines (ERG). The ERG program was developed based on the requirements of NUREG-0737, Item I.C.1, "Guidance for the Evaluation and Development of Procedures for Transients and Accidents.

NUREG-0737, Item I.C.1, defines operator errors of omission or commission as an example of a multiple failure event. Since the time calculated in the RWST drain down analysis is based upon the worst case single failure, consideration of operator omission and commission (multiple failure) in the operator training to meet this calculated time is not warranted In the unlikely event that an operator fails to perform (or improperly performs) a critical step in the EOP, which results in inadequate core cooling, the operator would be directed to a functional restoration procedure.

Functional restoration procedures are designed to address multiple failure events. However, failure of an operator to perform a step in the EOP is highly unlikely based on the following:

  • Operators receive frequent training on the performance of EOP-LOCA-3
  • EOP-LOCA-3 has been human factored to minimize the time required to reach critical steps (a critical step is a step with a time requirement provided in the RWST drain down analysis).
  • Three point communication by the operating crews minimizes the potential for mis-communication that would be experienced during implementation of the EOPs. Based on the above discussion, inclusion of operator omission and commission in the RWST drain down analysis and operator training to ensure switchover times stated in the drain down analysis is not considered to be required.

NRC FORM 366A (4-95)

  • NRC FORM 366A (4-95) U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER) TEXT CONTINUATION FACILITY NAME (1) DOCKET NUMBER (2) LER NUMBER (6) 05000272 YEAR I SEQUENTIAL I REVISION NUMBER NUMBER SALEM GENERATING STATION UNIT 1 97 --009 01 TEXT (If more space is required, use additional copies of NRC Form 366A) (17) Cause of Occurrence PAGE (3) 13 OF The root cause evaluation for the introduction of the QSQs into the design and licensing basis identified the following causes:
  • For the use of initial containment pressure for meeting RHR pump NPSH requirements, the cause is attributed to a failure to address all accident scenarios that could affect the assumptions made. 17
  • For taking credit for the period of time of interrupted flow to align the ECCS flow path after a small break LOCA, the cause is attributed to a failure to adequately review the licensing and design bases for the semi-automatic swapover.

The causes for the delay in recognizing these conditions as reportable are as follows:

  • The failure to report the RHR system deficiencies (potential run-out condition) in 1994 is attributed to programmatic deficiencies.

The procedures in place for reporting conditions adverse to quality (making prompt reportability determinations) in 1994 did not provide adequate guidance to ensure that these deficiencies would be documented in the corrective action process (Incident Report system) and evaluated for reportability.

  • The failure to report the deficiencies associated with RWST drain down analysis in 1996 is attributed to human error (misjudgment).

There was excess confidence in the adequacy of the safety evaluation prepared by Westinghouse in their support of resolution of these deficiencies.

By relying on the Westinghouse safety evaluation to resolve these deficiencies, PSE&G personnel did not properly evaluate or correctly assess the extent of the deficiencies on plant operation.

Since a condition report was not issued for these deficiencies in 1996, in accordance with NBU procedures, the issue was not reviewed for reportability at that time. Prior Similar Occurrences A review of LERs for the past two years identified three LERs (272/95-016, 272/96-020, and 272/96-030) associated with the inadequate review of plant design and licensing basis information when performing changes to the plant. The corrective actions associated with the previous LERs addressed the specific concerns identified in the previous LERs and would not have prevented the conditions identified in this LER from occurring.

NRC FORM 366A (4-95)

  • NRC FORM 366A (4-95) U.S. NUCLEAR REGULATORY COMMISSION FACILITY NAME (1) LICENSEE EVENT REPORT (LER) TEXT CONTINUATION DOCKET NUMBER (2) LER NUMBER (6) 05000272 YEAR I SEQUENTIAL I REVISION NUMBER NUMBER SALEM GENERATING STATION UNIT 1 97 --009 01 TEXT (If more space is required, use additional copies of NRC Form 366A) (17) Safety Consequences and Implications There were no safety consequences associated with either: PAGE (3) 14 OF 1) the excessive RHR flow during the recirculation mode of operation, or 2) the inability to ensure successful completion of the switchover from the injection mode to the recirculation mode of operation following an accident since Salem has not experienced a LOCA and therefore has not required the ECCS to be transferred to the recirculation mode of operation.

17 To characterize the implications of the possible loss of RHR during recirculation mode of operation prior to corrective actions performed in 1994, and the failure to complete the switchover from the injection mode to the recirculation mode of LOCA mitigation prior to stopping any ECCS pumps, a review of the Salem PSA was performed.

A review was performed to determine the impact to Core Damage Frequency (CDF) in the event of loss of one RHR pump during recirculation and on the decrease times provided in this LER for the completion of the switchover from injection to recirculation.

Based on the review of the Salem Unit 2 PSA, loss of an RHR pump during recirculation would result in an increased CDF of approximately 73% compared to the baseline CDF. In accordance with the EPRI TR-105396, "PSA Applications Guide", figure 4-1, this change would be categorized as significant risk increase.

However, the scenario discussed in this LER describes the assumption of the failure of one RHR pump and the possibility of the loss to the second RHR pump due to the increased flows. This would lead to the loss of both RHR pumps and loss of all cooling water flow to the core during recirculation.

The review of the PSA for the decrease in times for the operators to perform the switchover from injection to recirculation resulted in an increase of approximately 27% compared to the baseline CDF. In accordance with the EPRI TR-105396, "PSA Applications Guide", figure 4-1, this change would be categorized as significant risk increase.

The concern with the inability to ensure successful completion of the switchover from the injection mode to the recirculation mode of operation is only a concern for Salem Unit 2 in the event of a SBLOCA. For a SBLOCA, the pressure will remain above the shutoff head of the RHR pumps and prevent RHR injection into the core. For a large break LOCA (LBLOCA) the RHR pumps do not lose suction during the switchover and will continue to provide flow to the core. Corrective actions have been taken to address the excessive flow conditions during cold leg recirculation at Salem Units 1 and 2. To address the concerns of possible ECCS pump interruption during switchover from the injection mode of operation to recirculation mode of operation, corrective actions have been completed for Salem Unit 2 and will be completed for Salem Unit 1 prior to restart from the current extended shutdown.

NRG FORM 366A (4-95)

  • NRC FORM 366A (4-95) U.S. NUCLEAR REGULATORY COMMISSION FACILITY NAME (1) LICENSEE EVENT REPORT (LER) TEXT CONTINUATION DOCKET NUMBER (2) LER NUMBER (6) PAGE (3) 05000272 YEAR I SEQUENTIAL I REVISION NUMBER NUMBER 15 OF 17 SALEM GENERATING STATION UNIT 1 97 --009 01 TEXT (If more space is required, use additional copies of NRC Form 366A) (17) Corrective Actions 1. A new NPSH calculation for Salem Units 1 and 2 was issued on June 12, 1997, eliminating the need to credit containment air pressure to meet NPSH requirements for the RHR pumps during cold leg recirculation alignment for both Salem Unit 1 and 2. 2. To eliminate the potential for exceeding RHR pump flow requirements during hot leg recirculation, the EOPs were revised in 1994 to eliminate the procedure steps associated with opening of the RHR hot leg injection path via the RH26 valve. The elimination of this flow path reduces the amount of flow delivered by the RHR pumps during hot leg recirculation to acceptable values. 3. The Unit 2 RWST drain down evaluation was revised May 20, 1997. This evaluation increased the amount of time available for the operators to complete the manual actions associated with the switchover from injection to recirculation without interruption of ECCS pump flow. 4. Unit 2 EOP-LOCA-3, "Transfer to Recirculation," was revised on May 30, 1997, to support the RWST drain down re-evaluation.
5. Operating crews have been trained on the new Unit 2 EOP changes. training was completed prior to Unit 2 entering Mode 3. This 6. The root cause investigation for the 10CFR50.59 Safety Evaluation deficiencies has been completed.

In the interim while the following corrective actions are being implemented, a Salem Engineering Independent Review Team (SEIRT) consisting of experienced individuals from different disciplines has been established to provide an additional multi-disciplinary review of 10CFR50.59 Safety Evaluations prepared by the Salem Nuclear Engineering groups. The following corrective actions were identified to address deficiencies in the 10CFR50.59 Safety Evaluation program implementation:

  • Establish performance standards and communicate expectations for performing Safety Evaluations
  • Periodically publish lessons learned from the critical review of Safety Evaluations
  • Formalize a feedback process to the preparer of 10CFR50.59 Safety Evaluations
  • Establish a grading criteria and performance indicators for 10CFR50.59 Safety Evaluations
  • Establish an interdisciplinary engineering review team
  • Perform periodic self-assessments of the 10CFR50.59 Safety Evaluation process These corrective actions are currently scheduled to be implemented by October 31, 1997. NRC FORM 366A (4-95)
  • NRC FORM 366A (4-95) U.S. NUCLEAR REGULATORY COMMISSION FACILITY NAME (1) LICENSEE EVENT REPORT (LER) TEXT CONTINUATION DOCKET NUMBER (2) LER NUMBER (6) 05000272 YEAR I SEQUENTIAL I REVISION NUMBER NUMBER SALEM GENERATING STATION UNIT 1 97 --009 01 TEXT (If more space is required, use additional copies of NRC Form 366A) (17) PAGE (3) 16 OF 17 7. In July 1995, an improved corrective action process for identifying conditions adverse to quality at Salem Generating Station was established.

This change to the corrective action process also provides better guidance on when an event should be considered a condition adverse to quality (lowering the threshold for identification of events). The Corrective Action Program implemented in July 1995 and the current procedures also include a more rigorous initial operability and reportability assessment than the previous Incident Report process that was in place prior to July 1995. The changes implemented in the Corrective Action Program address the root cause for the programmatic deficiency identified for failure to report the potential RHR run-out condition in 1994. 8. The individuals involved in the review of the RWST drain down evaluation have been counseled.

The engineering group responsible for the review of the RWST drain down evaluation has also conducted lessons learned training on the issues discussed in this LER. 9. The failure to initiate a Condition Report(CR) by the Engineering staff was previously cited by the NRC as Notice of Violation 50-272 & 311/96-08-04 on August 26, 1996. The issues cited in the violation were identified as a result of the Salem Integrated Readiness Assessment (SIRA) and were not entered into the Corrective Action Program until questioned by the NRC. The responsibility and importance of documenting conditions adverse to quality was rolled out to Engineering personnel in a letter issued by Engineering Management to all engineering personnel on September 18, 1996. Also, a Station Key Message was issued during the week of September 30, 1996, stressing the importance of generating CRs. These corrective actions also address the failure to initiate a CR associated with the deficiencies concerning the RWST drain down analysis.

10.A verification of the hot leg injection configuration required to mitigate a Mode 4 LOCA was completed for Salem Unit 2 on June 7, 1997 (prior to entry into Mode 4). A similar verification of the hot leg injection configuration will be completed prior to Mode 4 for Salem Unit 1. 11.Although the current procedures for mitigation of a Mode 4 LOCA are consistent with the Westinghouse Owners Group Abnormal Response Guidelines (ARGs), a review of the procedures was initiated for possible enhancements related to initiation of hot leg injection for Salem Unit 2. As a result, further guidance was incorporated into the Salem Unit 2 abnormal operations procedure on June 7, 1997 (prior to entry into mode 4 for Unit 2) for aligning the ECCS to hot leg recirculation during a mode 4 LOCA. Similar procedure enhancements will be performed to the Salem Unit 1 abnormal operation procedure for a mode 4 LOCA prior to Salem Unit 1 entering Mode 4. NRC FORM 366A (4-95)

  • NRC FORM 366A (4-95) U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER) TEXT CONTINUATION FACILITY NAME (1) DOCKET NUMBER (2) LER NUMBER (6) 05000272 YEAR I SEQUENTIAL I REVISION NUMBER NUMBER SALEM GENERATING STATION UNIT 1 97 --009 01 TEXT (If more space is required, use additional copies of NRC Form 366A) (17) Corrective Actions (Cont'd) PAGE (3) 17 OF 17 12.The Unit 1 RWST drain down analysis will be revised to provide sufficient time for the operators to complete the manual switchover from injection to recirculation without interruption of ECCS pump flow. This re-analysis will be completed prior to Salem Unit 1 entry into Mode 3. 13.The RH26 valves have been placed back in the Inservice Test Program (IST) for use during a Mode 4 LOCA. 14.A letter was submitted on May 27, 1997, to correct the switchover times stated in the SER for Amendment 69 to the Unit 2 TS and to correct other inconsistencies identified in the SER. 15.A License Change Request (LCR) was submitted to the NRC on April 25, 1997, to clarify TS 3.5.2 regarding the hot leg injection flow paths required for Modes 1-3. 16.A revised pump curve for the RHR pumps has been obtained from the vendor which confirms that the extrapolation performed by Westinghouse was accurate.

NRC FORM 366A (4-95)

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