ML20149D780
| ML20149D780 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 12/22/1993 |
| From: | Russell W Office of Nuclear Reactor Regulation |
| To: | Martin T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| Shared Package | |
| ML20147B843 | List: |
| References | |
| FOIA-96-351 IEIN-93-047, IEIN-93-47, NUDOCS 9312290260 | |
| Download: ML20149D780 (4) | |
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ft j 2 NUCLEAR REGULATORY COMMISSION WASHINGTON D.C. 206EEW)001 h bj < l Deceter 22,1993 l MEMORANDUM FOR: Thomas T. Martin, Regional Administrator Region I l FROM: William T. Russell, Associate Director ! for Inspection and Technical Assersment Office of Nuclear Reactor Regulation l
SUBJECT:
GENERIC IMPLICATIONS OF THE SALEM 2 LOSS OF OVERHEAD ANNUNCIATORS l l As requested, NRR has considered the concerns raised in your memorandum to l Thomas E. Murley, dated May 28, 1993, regarding generic implications of the ' i Salem 2 loss of overhead annunciators. Subsequent to your memorandum, on June 18, 1993, the staff issued Information Notice (IN) 93-47, " Unrecognized Loss of Control Room Annunciators," alerting licensees of the potential problems associated with inadvertent loss of overhead annunciators. The l l notice, to a large extent, identified similar concerns to those raised in your l l memorandum. In addition, AE00 is conducting a study on the significance of-loss of annunciators and computer systems. To date, they have identified 110 ' events of loss of annunciators or computers between January 1985 and March 4 1993 and have conducted a PRA review indicating the worst case increase in ! core damage risk from annunciator failures to be about 2.5 percent. This l confirms the AIT finding that there were no significant safety consequences , due to the loss of the Salem overhead annunciators. ! Additional considerations for each of your recommendations are presented below. 1
- 1. Failure to Properly Specify the System Functional Requirements l
You recommended that the NRC provide guidance for digital electronic and software modifications to annunciator systeins and issue information to the industry on this subject. The Electric Power Research Institute (EPRI) is conducting a study on the functional requirements of power plant annunciators and is in the process of j issuing a specification, TR-102872-L, " Functional Specification Requirements l for a Microprocessor-Based Replacement Annunciator System." This l specification covers aspects of annunciator functional requirements similar to those identified in your memorandum. Specifically, it includes criteria on hardware, software, verification and validation, testing, training, installation, simulation, power supplies, alarm circuit checks, electromagnetic interference, and single failure criterion. This document provides the appropriate additional detail for proper design of computer-based annunciator systems. I T 5/ \ w&
T. T. Martin l In addition, IN 93-47 describes the 1992 losses of annunciators at Callaway and Salem and emphasizes the importance of the annunciators to the safe operation of nuclear plants including the need for clear procedures, appropriate training, and effective communications between operators and plant personnel on loss of annunciators.
- 2. Human-Machine Interface (HMI) Problem You recommended issuance of an information notice describing existing weaknesses in the HMI that may delay the operators awareness of a loss of annunciators.
l IN 93-47 addressed and alerted licensees to HMI weaknesses that contributed to l the unrecognized loss of the overhead annunciators at Salem 2. !
- 3. LACK OF GUIDANCE IN THE EMERGENCY CLASSIFICA" A GUIDE (ECG) FOR A LAPSED i EMERGENCY CONDITION l You recommended that 10 CFR 50.72 be changed to require licensees to report l undeclared or lapsed emergency conditions to the NRC if they are not already
! required to be reported via the emergency notification system. The staff was aware of the issue of lapsed emergency conditions reporting and determined that such conditions should be reported. NRC expectations for the I reporting of lapsed emergency conditions are contained in NUREG-1022, " Event i Reporting Systems - 10 CFR 50.72 and 50.73: Clarification of NRC Systems and I Guidelines for Reporting." This NUREG has been revised and was recently re-issued for public comment. This revision incorporates additional guidance on reporting lapsed emergency conditions to the NRC.
- 4. NO OPERATOR TRAINING ON LOSS OF ANNUNCIATORS
. You recommended that the NRC inform licensees via an information notice of the need for training plant operating personnel on handling loss of annunciator i events, and employ loss of annunciator scenarios in NRC-administered licensed operator examinations. IN 93-47 addressed the training weakness associated with the loss of annunciators at Salem, Unit 2, and specifically discussed the iuportance of training operators to recognize and respond to loss of annunciator events. Furthermore, training requirements have also been specified in EPRI l i Specification TR-102872-L mentioned in Item 1 above. i i We believe that increased emphasis on loss of annunciator events in NRC-
- administered licensed operator examinations, beyond current NRC examiner l
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i ! T. T. Martin : . practice, is not justified based upon the safety significance of such events. j Nevertheless, NRC license examination guidance provided in NUREG-1021, Rev. 7, t
" Operating Licensing Examiner Standards," does not prohibit inclusion of loss of annunciator events within examination scenarios. Loss of annunciators, or i other operator aids, can and have been appropriately incorporated in past NRC-1 administered examinations. The use of such events is appropriate when it 4
supports a valid assessment of operator competencies and is not inconsistent ! with other applicable guidelines for scenario construction (e.g., plant indications are available to cue operator action and the event is a logical i occurrence in an event sequence). In addition, the incorporation of specific } scenarios and tasks in examinations base <i on facility and industry events, l such as loss of annunciators, should be part of the facility's systems approach to training process. I Test content-is expected to focus on the i ! criteria of 10 CFR 55.41, 43, and 45, and on the facility specific training j program. l l 5. NO PROCEDURE FOR LOSS OF ANNUNCIATORS 4 i You recommended that an information notice be issued describing the need for j licensees to assure that their current actions during a loss of annunciators j be consistent with the new emergency action level (EAL) of NUMARC/NESP-007. j In addition to describing inadequacies or lack of procedures for loss of i annunciators, IN 93-47 alerts licensees to the need for operating procedures ! to assist plant personnel in taking the necessary response actions including j making the required notifications. When establishing plant specific emergency i response and reporting actions, IN 93-47 also points out that licensees can i either follow the guidelines of NUREG-0654/ FEMA-REP-1, " Criteria for i Preparation and Evaluation of Radiological Emergency Plans and Preparedness I for Nuclear Power Plants," dated November 1980 or the criteria of Revision 3 { of Regulatory Guide 1.101, " Emergency Planning and Preparedness for Nuclear l Power Reactors," dated August 1992. Revision 3 of Regulatory Guide 1.101 i endorses the NUMARC/NESP-007, Revision 2, " Methodology for Development of } Emergency Action Levels," dated January 1992. IN 93-47 noted that "With respect to loss of annunciators, the NUMARC/NESP-007 guidance provides an alternative delineation of thresholds for declaring an Unusual Event, Alert or i Site Area Emergency." i In summary, we believe the IN, the ongoing studies being conductec by AE00 and ; EPRI, and existing requirements and regulatory guidance are adequate to l address your concerns. Of course, the results of the AE0D and EPR1 studies, l 2 and other new information could cause us to reassess the need for further i action on this issue. i l 1 , i : i i < i
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, I T. T. Martin ] l l J If there are any questions regarding the above, please contact : Bruce A. Boger at (301) 504-1004, or Subinoy Mazumdar at (301) 504-2904. l I ! William T. Russell, Associate Director for Inspection and Technical Assessment , ! Office of Nuclear Reactor Regulation !
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- J. Milhoan, RIV F. Congel i R. Faulkenberry, RV L.J. Callan i
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- May 6, 1994 CHAIRMAN I
- The Honorable Joseph Biden United States Senate Washington, D.C. 20510
Dear Senator Biden:
The recent alert at the Salem Nuclear Power Plant led the staff to dispatch an Augmented Inspection Team (AIT) to that site so ! j that the events leading up to, during, and after the reactor trip of April 7, 1994, would be thoroughly understood. Our staff has briefod your staff concerning that inspection.
- I want yen to know that the Commission and the staff are con- l
, cerned about recent operations and performance at Salem. The staff is holding a public meeting today, on site, with the licensee in order to thoroughly discuss their activities subsequent to the April 7 event and to address deficiencies as part of an overall improvement effort. The Commission has ,
scheduled a meeting with the licensee and the NRC staff on j Monday, May 9, 1994, so that we can fully understand the actions I that the lice.'see has taken to prepare for restart of Salem j Unit 1. 4 We will keep you informed of our ongoing activities at Salem. Our activities will be geared to ensuring that licensee efforts to improve performance are effective and sustained. Sincerely, 4 Ivan Selin l
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! May 14, 1994 l The Honorable Joseph R. Biden j United States Senate Washington, D.C. 20510 '
Dear Senator Biden,
5 I am responding to issues you raised in your letter of May 11, { 1994, to Chairman Salin regarding restart of the Salen Unit 1 j l nuclear facility. The Commission has followed very closely the i NRC staff's assessment of'the event that occurred at Salen Unit 1 l on April 7, 1994, and has paid close attention to subsequent l actions and corrective measures being taken by Public Service Gas j and Electric Company (PSEEG) following the event. The decision j on authorization of restart rests with the staff and, therefore, i I am responding to your letter. However, because of your l interest the chairman has been briefed personally, although informally, on the restart decision and he has told me that he is comfortable with the staff's action. j . On May 9, 1994, the Commission held a meeting which was open to public observation during which PSE&G discussed their assessment of the event and corrective actions that they were taking. The NRC staff also summarized the activities and preliminary conclusions of the Augatated Inspection Team (AIT) during this meeting. Following the Commission meeting, on May 11, the NRC staff submitted a more detailed summary of the AIT findings to the commission, and a copy of this assessment was also placed in the Public Document Room. The staff is now in receipt of the licensee's most recent submittal (enclosed) that responds to the remaining AIT restart issues, and PSE&G has requested NRC permission to return Salem Unit 1 to power operation. The NRC staff has completed its review and is satisfied that all restart issues have been adequately addressed. Therefore, the NRC has no basis for delaying the restart of Salen Unit 1. The NRC analysis is enclosed which addresses both the technical and management issues involved.
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I want to assure you that the NRC staff will closely monitor plant start-up and operations and we wi,ll not hesitate to take any necessary regulatory actions to protect public health and safety. Regarding enforcement action, the staff is assessing any violations of the regulations and will apply the NRC enforcement policy including consideration of escalating and mitigating factors, as sppropriate. h, 9
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l l We would be happy to keep you or your staff informed of our ongoing oversight of the Salem I restart and operation. We appreciate your recognition of the NRC staff's responsiveness to your inquiries on this matter. I sine rely, J e M. Taylor Exe tive Director for Operations
Enclosure:
As stated . 1 0 eM en e e e
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- ENCLOSURE Licensee Submittals Dated April 25, 1994 April 29, 1994 May 10, 1994 May 13, 1994 i
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Steven E. M5tenberger Public Senace Electric and Gas Company P.O. Box 236. Hancocks Bridge, NJ 08038 609-339-4199 f ! i *. - ~ ~ APR 2 51994
- NLR-N94078 4
- Mr. T. Timothy Martin -
l Regional Administrator i U.S. Nuclear Regulatory Commission j Region I l 475 Allendale Road i King of Prussia, PA 19406-1415 t i
Dear Mr. Martin:
i f l i CIASEOUT OF CONFIRMA'50RY ACTION LETTER 1-94-005 ! SALEN GENERATING STATION l i UNIT NO. 1 l DOCKET No. 50-272 l i Confirmatory Action Letter (CAL) 1-94-005, dated April 8, 1994, documented a discussion regarding the decision to dispatch an i l Augmented Inspection Team (AIT) to review and evaluate the l circumstances related to the Unit i reactor trip and safety { injection that occurred on April 7, 1994. l Prior to this discussion PSEEG decided to place Salen 1 in a cold shutdown condition. During the discussion, PGEEG agreed to maintain the cold shutdown condition until the AIT acquired all
- the information needed for their assessment and was satisfied j that any necessary corrective measures had been or would be j taken. Subsequently, the AIT completed its on-site efforts, and PSE&G completed its root cause determination into the 1
l circumstances surrounding the reactor trip. Actions that have been taken and are currently underway are included on Attachment i 1. This attachment discusses which of the Unit 1 actions are ! also applicable to Unit 2. Attachment 2 discusses how each of j the requirements in the CAL have been met. i I i , Sincerely, ,.
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APR 2 5 % Mr. T. Timothy Martin 2 ( NLR-N94078 i i C
- Mr. J. C. Stone, Licensing Project Manager - Salen U. S. Nuclear Regulatory Commission One White Flint North
, 11555 Rockville Pike Rockville, MD 20852 ! Mr. C. Marschall (809) USNRC Senior Resident Inspector j Mr. E. Tosch, Manager, IV .
- NJ Department of Environmental Protection i
Division of Environmental Quality 4 Bureau of Nuclear Engineering . CN 415 i Trenton, NJ 08625 ' i l i ] I i
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ATTACHMENT 1 STARTUP ACTIONS The following actions have been taken or will be completed prior to the indicated mode. . Prior to entering mode 4 (Hot Shutdown): replace the Pressuriser Relief Tank Rupture Disk, perform an evaluation of the actuation of the Solid State Protection System, replace the High Steam Flow Input Relays, perform an inspection and evaluation of the PORVs and tailpipe, evaluate / inspect the Pressuriser Safety Valve Tailpipes, send the Pressuriser Code Safety Valves offsite for verification testing, perform an analysis pertaining to IEEE 279 (circuit to complete Function), determine root causes for the
- reactor trip and safety injections, and assess the safety
. significance of the incident.
Prior to entering mode 3 (Hot Standby): verify Pressuriser Pressure Bistable Setpoints, verify closed limit on PS-1 and 1 PS-3, and repair / replace High Steam Flow Summator. i Prior to entering mode 2 (Startup): perform Rod control Speed troubleshooting and Bank 'C' Step Counter troubleshooting, l perform lift testing on some Main Steam Safety Valves, verify the j! Condenser Vacuum Alarm Satpoints, install the MS10 Roset Windup
- {- design change, and install the Steam Flow Transmitter Dampening i design change. ,
The Control Roon log requirements for modes 5 and 6 have been enhanced to monitor RVLIS level and to provide corrective actions when established limits are exceeded. This has been completed
- for both Unit 1 and Unit 2.
j Several operating procedures have been enhanced for both Unit 1 and Unit 2. Each shift will be provided with refresher training and training that is specific to this incident prior to assuming the Unit 1 ' watch. Some of the topics include reactivity manipulations at l low power, actions to be taken for single train safety Injection ' i actuations, and resource management (assignment of personnel). Additionally, management expectations concerning command and control are being reinforced. This training /re:.nforcement has ] also been conducted for Unit 2. ? I i i l ( 1 OF 2 . i -
. ATTACHMENT 1
( POST-STARTUP ACTIONS l . The following are post-startup actions. They are all applicable to both Unit 1 and Unit 2. The current target completion date is included in parentheses following each action.
- Evaluate (along with Westinghouse Owners Group) the need to
, revise BOP-CFST procedures to allow establishing steam l bubble at normal operating pressure / temperature within EOP Network. (1/95)
- Proceduralize existing Night Order Book guidance for use of RVLIS during shutdown conditions. (6/94)
- Incorporate procedural changes into the licensed operator training programs. (11/94).
l Evaluate methods to mitigate the impact of r,arsh grass on the Circ Water Intake Structure. (12/94) 1 The following Unit 2 modifications will be installed at the next ( outage of sufficient duration:
- MS10 Roset Windup
- Steam Flow Transmitter Dampening An evaluation will be performed to determine if the Unit 2 High Steam Flow Input Relays need to be replaced.
The Unit 1 procedure enhancements applicable to Unit 2 have been completed. The refresher and specific incident training provided for Unit 1 is considered applicable to Unit 2 and will be i incorporated into the licensed operator training programs.
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! ( ATTACIDENT 2
\ RESPONSE TO CAL
- 1. Assure that the AIT Leader is cognizant of, and agrees to, any resumption of activities that involve the operation, testing, maintenance, repair, and surveillance of any 1 equipment, including protection logic or associated
! components, which failed to properly actuate in response to I he reactor trip and safety injection (s) of April 7,1994. i l The AIT leader was kept cognizant of, and agreed to, the l operation, testing, maintenance, repair, and surveillance of the equipment, including protection logic or associated i components, related to the reactor trip and safety
- injection (s) of April 7,1994. This ites is closed.
i l 2. Assemble, or otherwise make available for review by the AIT, j all documentation (including analyses, assessments, reports,
- procedures, drawings, personnel training and qualification
! records, and correspondence) that have pertinence to the 4 equipment problems leading up to the reactor trip and safety injection (s), and subsequent operator response and recovery . actions. , All documentation (including analyses, assessments, reports, i procedures, drawings, personnel training and qualification l l records, and correspondence) required by the Lnspection team l was provided satisfactorily. This item is closed. ! 3. Assemble, or otherwise Take available for review by the AIT, all equipment, assemblies, and components that were associated with the problems encountered during the events
- leading up to, and subsequent to the reactor trip and safety j injection (s).
All equipment, assemblies, and components were available for l
- inspection by the AIT. This item is closed.
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- 4. Make available for interview by the AIT, all personnel that l
were associated with, or have information or knowledge that l pertains to the problems encountered during the events l leading up to, and subsequent to the reactor trip and safety injection (s). l Access to all requested interviewees was provided. This - item is closed. I 5. Gain agreement from the Regional Administrator prior to commencing plant startup. 4l l Agreement to commence startup will be requested by a letter j at a later date. l
PutWie serv 6ce Sectric and Gas ( company Steven E. M0lenberger PutWie Sorwce Electric and Gas Company P.O. Box 236 Hancocks Bndge, NJ 08038 609-3391100
* - - - = = APR 2 91994 NIJt-N94084 Mr. T. Timothy Martin Regional Administrator U.S. Nuclear Regulatory Commission Region I 1 475 Allendale Road l King of Prussia, PA 19405-1415
Dear Mr. Martin:
REQUEST FOR SUPPLEMENTAL INFORMATION SALEM GENERATING STATION UNIT NO. 1 DOCKET No. 50-272 on April,20, 1994, PSE&G issued a letter outlining actions to be j taken as a result of the investigation into the April 7 Unit 1 reactor trip and safety injections. This letter supplements the ( information contained in that letter. Subsequent correspondence will address Power Operated Relief Valve' issues, Pressuriser I Safety Valve issues, and a request for agreement to restart. Attachment 1 to this letter addresses the hardware issues, I corrective actions, and the status of thosta items. Attachment 2 provides a summary of our root cause analysis. Attachment 3 addresses some of the items that PSE&G is planning to consider as part of our investigation into methods to mitigata the impact of i marsh grass on the Circulating Water Intake Str , .re. Attachment 4 includes a summary of the enhancements to operating procedures and licensed operator training that have been made as well as those that have not yet been incorporated. Attachment 5 includes a justification to delay the installation of design modifications for Unit 2 unti.1 the next refueling outage. Sincerely, fA > > l EWSM4=%8 Ilf)) _ -
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s j . APR 2 91994 I Mr. T. Timothy Martin 2 4 { NLR-N94084 i C Mr. J. C. Stone, Licensing Project Manager - Salsa U. 8. Nuclear Regulatory Commission . i One White Flint North i 11555 Rockville Pike 4 Rockville, MD 20852 Mr. C. Marschall (809) USNRC Senior Resident Inspector i Mr. K. Tosch,, Manager, IV NJ Department of Environmental Protection i Division of Environmental Quality l i Bureau of Nuclear Engineering I CN 415 Trenton, NJ 08625 d i I ( 1 I i l 4 i Se i i 1 i 1 i i ,
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, - - . . - - . _ - _ - . - - _ _ . - . . . . _ - . - - - - . - - - - - - . - _ ~ - - . _ _ . - - 4 4 l ATTACHNENT 1 j BARDNARE REIATED ISSUES 1 SOLID STATE PROTECTION SYSTEN (SSPS) ACTUATION d l The SSPS train 'A' and train 'B' responded differently due to High Steam Flow Input Relays having slightly different 4 actuation time characteristics to an in:,tiating pulse of short
- duration. The pulse troubleshooting detected variances in the l
input relay actuation times. Extensive troubleshooting has i determined the actual actuation times for both trains when These times ! subjected to short duration initiation signals. ! varied from 16 to 35 milliseconds. These variances are j expected for pulsed signals and are well within design limits. Because of the short duration of the signal, only train 'A' responded to the signal. As a result, only those components associated with tra,n 'A' operated. No component failures 4 1 were identified and equipment time response tests were found j satisfactory and did not indicate any degradation. Operators were trained on being nansitive to the potential for l the trains to actuate at slightly different times. They were l also given guidance to manually initiate the second train in i , similar future situations. l BIGH STEAM FIDW INPUT REIAYS 3 The High Steam Flow Input Relays were replaced as a conservative measure. During visual inspection, discoloration Although the relays had I was noted in soms of the relays. i different actuation time characteristics to an initiating pulse, both channels were within overall time response technical specifications and showed no indication of degradation. The relays were satisfactorily replaced. Subsequent pulse testing showed reduced time response i differences between the train 'A' and 'B' input relays. ]
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ATTACIDGMT 1 [ RARDWARE RELkTED ISSUES l ( i l PRESSURISER BISTABLE PERFORMANCE When the Pressuriser Relief Tank (PRT) rupture disk l functioned, as designed, pressure went from approximately 91 l psi to 0.5 psi in the PRT, affecting the backpressure as j sensed by the Pressure Relief Valves (PRVs), which resulted in j a short duration pressuriser pressure pulse. Two of the four ' pressuriser pressure channels did not trip. I j All four pressuriser pressure channels contain lead lag j derivative amplifiers for pressure rate compensation. Because of the short duration of the pulse and the tolerances of the installed equipment, it is not unexpected that only two of the l four channels would provide an output. This is consistent ! with the design. Channel functional tests were performed to ensure equipment functioned as designed. All equipment was found to be within specification. operability of the amplifiers was verified via field calibration. i - ROD SPEED PERFORMANCE ( The Rod Speed control Circuit was originally thought to have l nalfunctioned during the power reduction on April 7, 1994. l The operator thought that the Rod Control System did not . l respond appropriately and switched back to manual. Sl.IC-CC.RCS-0001(Q), Rod Control System Automatic Speed l Verification, was performed to verify proper operation of the ' Rod Control System. During the load reduction, the operator was monitoring the T error recorder on the panel to make a determination of what j actual Rod Speed should be while in Auto. With only a 5 degree temperature error (between Tave and Tref), Rod Speed
- should be 72 steps / minute. However, the overall temperature error that Rod Speed Control will react to is determined by a ;
summation of Nuclear power and Turbine power mismatch, i combined with Trot and Tave. This power mismatch value is i unknown for the exact time of the incident, although during testing it was shown that a power mismatch can cancel out the - l Tave and Tref error. " Based on the testing performed on the Rod Speed circuitry, the system worked as designed. The T error recorder should not be j i read as an indicator of required Rod Speed during power j changes. This has been communicated to the licensed operators i and will be reinforced in operator training. I ) - t i
i i 1 ATTACHMENT 1 BARDWARE RELATED ISSUES l . 1 4 PS-1 AND PS-3 LIMIT SWITCH OPERATION . j After the incident, an operator reported that he thought that one of the pressuriser spray valves (PS-1 and/or PS-3) may not j have indicated closed, even though the control air system had
- been isolated to the containment (the valves fall closed).
! The limit switch operation was verified to be satisfactory. i MAIM STEAM SAFETY VALVE OPERATION ! During the incident, several main steam safety valves operated due to the increase of secondary pressure. This pressure l j increase was the' result of the increase in RCS temperature. i The safety valves operated.as per design. L l As a conservative measure, during the upcoming start-up and
- while in Mode 3, the valves that lifted will be tested to i
r verify that they remain within the proper settings. . \ A l l MS-10 CONTROLLER PERFORMANCE I k ' The Atmospheric Relief Valves (MS-los) have a delay in opening ! due to the valve controller being below its setpoint for an extended period of time. The design of the controller allows i the controller output to saturate low when the process is below the control setpoint (reset wind-up). This results in a l need for manual action, which is procedurally controlled. l l DCP 1EC-3325 was issued to address the slow operation of the i MS-10 cont: aller. The DCP installed a clamping circuit, changed the gain of the controller, and decreased the reset time. These changes will improve the controller's time l j i response to a rapidly increasing steam pressure signal and are ! expected to prevent MSSVs from opening. I CONDENSER VACUUM ALARM SETPOINT During the incident the control room operators noticed that the Condenser vacuum low alarm did not come in. Work orders e were initiated to re-calibrate the pressure switches and to verify that the alarm was operable. One switch required recalibration, the other switch and the alarm were found to be satisfactory. . 1
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[ ATTACHMENT 1
- ( BARDWARE RELATED ISSUES i i
( STEAM FIDW TRANSMITTER PERFORMANCE . l The s' hutting of the Turbine Stop Valves causes a pressure wave { of a sufficient magnitude and duration to initiate a High l Steam Flow Signal'. This High steam Flow signal, together with i ignal met the coincidence for a Safety a Low Imv (SI) Injection Tave ss.ignal. Due to the short duration of the High l Steam Flow Pulse (milliseconds), the SI signal cleared before ! some plant equipment could latch and operate, allowing i completion of all component actions. Train 'B' did not j respond due to the short duration of the spiker but operated { within design specifications. No equipment failures were j noted. A design modification has been installed to filter the i pressure wave pulse. i l RVLIS a i Reactor Vessel Level Indication rystem (RVLIS) is required by Tech Specs to be operable in Nedes 1, 2, and 3. Although l RVLIS indication was available to the operators, it was not' l initially included in the Mode 4, 5, and 6 Control Roon log. j Therefore, the control Room operators were not conditioned to ( monitor this indication since it is not considered an operable
- instrument in modes 4, 5, and 6. The logs are being revised to require RVLIS indication to be logged in Modes 4, 5, and 6
- and to provide procedural guidance to be taken if the level is below the specified limit. In addition, control Room operators have been instructed to monitor,all control Room instrumentation, regardless of Tech spec Mode applicability.
When anomalies are discovered by the control operator, they will be reported to the Shift Supervisor. The RVLIS indicated less than full scale due to the formation The source of the nitrogen, which I l of a nitrogen bubble. accumulated on the reactor vessel head, was from the Volume Control Tank (VCT). Nitrogen is used in the VCT as a cover : gas. The VCT was being sa:,ntained at 34 psi, with the Reactor l Coolant System open to the atmosphere. At this pressure, the nitrogen went into solution and migrated into the reactor vessel, which is expected in this mode prior to fill and vent .,.. operations. Since the Reactor Coolant System pressure is very close to atmospheric pressure, the nitrogen came out of solution upon entry into the reactor vessel and accumulated in the reactor head. The operators have been provided guidance to maintain nitrogen cover gas in the VCT between 15 and 20 psi in order to a:,nimize the effect of nitrogen going into solution. e
i i i a i e ATTACIORNT 2 ' / SUSOEARY OF ROOT CAUSE ANALYSIS AND SAFETY SIGNIFICANCE
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( i ROOT CAUSE A nueber of root causes can be categorised within the three phases of this ev.ent. The first phase includes the rapid } l i power reduction to low power operations up to the reactor l l trip. The root cause of thie phase was poor crew performance
- and inadequate communication between the crew asabers.
l The second phase involves the reactor trip to the first safety injection. The root causes of this phase are operator error l in withdrawing the rods and a design problem with the steaa l l flow transmitters. The third phase includes the period of the high steam flow on l 11 Steam Generator until the recovery from the entire event. The root cause of this phase is a design problem (MSlos) with l a contribution from the control operator (did not take manual i l control in time). A contributing factor is the lack of i operator action to mitigate the Another primary contributing temperature factor and to secondary. pressure increase. j this ' phase of the event was poor communications. I { See the other Attachments for the Corrective Actions related to these root causes. I 1 i e l l > SAFETY SIGNIFICANCE This incident was reviewed with respect to Condition II safety analysis limits as well as the impact on the plant component fatigue analysis, fuel integrity, and minimum average temperature. All condition II safety limits were met and the plant component fatigue. analyses conclusions continue to be valid. The reduction in the minimum. average temperature below the Tech Specs was not significant M Th to have had safety implications. No event-induced fuel fahlures resulted. Therefore, this event was not a significant safety issue and the conclusions of the UFSAR remain valid. During the incident, both block valvas and both Thus, PORVsthewere water .s-available and operable for prassure relief. filled pressuriser did not cause the event to degrade to a more serious condition.
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ATTACHMENT 3 { , MARSH GRASS MITIGATION PIAN The following are some examples of actions that are being considered to improve the ability of the circulating Water System to mitigate marsh grass .
- 1. Increase in travelling screen speed
- 2. Reorientation / addition of screen spray nossles
- 3. Addition of scrnen spray capacity / pressure l
- 4. Physical barriers in the river
- 5. Other engineered solutions l .
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i, I ATTACIDENT 4 i / PROCEDURAI/ TRAINING EBRIANCEMENTS 1 t
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i i The following procedural enhancements have been issued and j approved for both unit 1 and unit 2 i SC.0P-DD.EE-0D22(3), Control Room Reading Sheet Node 5 - 6 l This revision added a place to log RVLIS level and steps to take if the level goes below the miniana n ?.ua identified in j the log. 51(2).0P-AB.COND-0001(Q), Loss'of Condenser vacuum ) i i This revision added Reactor / Turbine Trip and load redoction , I
- requirements.
i 3 81(2) .0P-AB.CW-0001(Q), Circulating Water System Malfunction J i ! This revision incorporated changes to support the new 1 administrative requirement for Entry Condition 1.3, two or ! more circulating Water Pumps out of service and to identify actions required when condenser pressure is abnormal. ' a ' j S1(2).0P-AB.TRB-0001(Q), Turbine Trip Below P-9 l ( This revision incorporated guidance found in another operating i procedure to respond to an madvertent cool down. 31(2) .0P-IO.EE-0004 (Q) , Power Operation . This revision added direction for maintaining RCS temperature greater than or equal to the minimum temperature for criticality. 81(2) .0P-80.CW-0001(E), Circulating Water Pump Operation This revision incorporated changes for when two or more Circulating water Pumps are out of service. 1 Zanger term procedure changes affecting the Emergency Operating )i Procedures (EOPs) and Critical Punction Status Trees (CFST).are being discussed with the Westinghouse owners Group. i 4 *
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s . AffACEDENT 4 f(, PROCEDURAI/ TRAINING 2NNMICEMENTS The following topics have been enhar.ced and have been discussed with all operating shifts during training sessions:
- 1. Temperature Control during a rapid load reduction
- 2. Communications
- 3. Resource Management (including pricritisation and the use of the third NCO)
- 4. Minimum Temperature for Criticality l
- 5. Single Train Safety Injection
- 6. Scope of SN88 Involvsment in E0P Operations
- 7. N510 Roset Windup ,
- 8. Pressuriser Steam Bubble Formation within the EOP Network .
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1 ] ., , i ATTACIDENT 5 i } (. UNIT 2 DESIGN MODIFICATIONS ! The following modifications are planned to be installed at j Unit 2 at an outage of sufficient duration (but not later than j the next refueling outage, currently scheduled for October 15, l 1994). The MS10. reset wind-up and steam flow dampening modifications are considered enhancements to the systems and i
- are not required for system opsrability. From an historical
! perspective, a safety injection signal is not "normally" l generated following a reactor trip. Since Tave is above the ] 543 degree RCS temperature setpoint, personnel performance contributed to the second safety injection signal. Operators l
- are trained, and as result of this event were re-trained, in j the proper response to possible delays associated with the
- MS10 controllers. There is adequate time for the operators to i respond appropriately. -
J Although these DCPs could be performed at power, PSE&G would j not realise a not safety gain by doing so because they are { enhancements that are not required for safety or unit j reliability. Therefore, delaying the implementation to an
- outage of sufficient duration (but not later than the ne w j scheduled refueling outage, currently scheduled for 10/15/94) j .
is justified. ( l 4 i i I i i l i k l i I l { , i i i f 1 i j i
men wa ~.m -- . e osagony * ( soeves E. utsenteeper Pwame sendes eenerie was een ampany P,0. som ans. Homesis eridge. NJ 00005 000 3 i J MAY 161994 4
- su Hrssose .
Nr. T. Timothy llertin m.,sen.1 naministrator i Unitea stieteid annalear Reguletsey comunissian - Region 1 47s Allendale Boed - King et Prussia, ya 1s40s-1413 - J h o.ar sir, martina 4 i . i MsQUEsT FoR SUFFLENWTAL INTION SALEN GENERATIM STATI(5
- UNIT NO. 1 l DOCKET NO. 50-373 4 ny letter dated April as tiectric & ses company ( M arefs WrJt-Np4084), arabile servion 8 1994 a letter out1 the -
1 octions April 7, to be taken as a ress t of the investigation the lose solem Unit No. 1 seacter trip and lajestion. The referenced letter oeuunitted psass to ide addi 1 ( information relative te the opera relief valves, the pressuriser safety valves the asseeisted piping struotarel j integrity. 7 Attar *maritactions, corrective 1 to thisstatus, letter and addresses root onmosthe harthrere issues,if dotamination, { necessary, for the power eafet valves, sad esamete rated Relief valves, pressuriser 4 structural inteprity. The j atta at discusses the appl ty of these issoas to Sales I Unit No. 2, if appespriate. plasse mete that all training and procedure changes identified in Attesdiment 4 of the il 29, 1994 letter are appliamble to both amit 1 ans Unit 2 have l been completed with the aussertion of lenger tesa Owners Group 30p ,i issues. i Tn addition, Attachment i oseentas a discussion of the steem flow instrumentation drift less that have coeurred and the minimum shift composition ret hy smahnient speoistentions. During a . ,_ telaphone conversatica between 78248 and NBC Region ! =E 71-on May 2,1994, pasos agrosal to psovise information relative to steam flow orift. The shift eenposition discussion is provided as per your request of 30my s, Ess4. e ( . gy .
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aptes losa U. a N. M. 6 4.J M 6 Aof0 m ]. ., , l l
- Do'otonent centrol Desk 3
- NTJt-Neecee i
! PSE&G will subudt a separate letter te request your agreement for
- restart and lift you have any quest et the confiamatory estica letter. Should ,
l i hesitate to esotect us. regarding this submittal, please de not l / . l Simeeral , u'E _
" :: / w' # 8
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l c ] Mr. J. c. Stone Licensing Project stanager,- Salem i US Nuclear Regule comuniesion one White Flint 11553 moolarille Pike j nookville, MD 30483
. l l Mr. c. marschall -
l i senior Resident Zaspector ' ( Mr. Kent Teach, unnager 17 New Jersey Department of Env Protection Division of Revironmental ty . sureau of Nuelear Eng . CM 415 Trenton, 57 08635 in l
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j mp W21 u. 5 N.R.C. IE1CH 1 KIN .. , E _ , ,, y l I i : ) , NLR-M94089 - t ATPACEMMT 1 l (- ADDITZell4L INyeRMAvf006 I. sm
- me = man ime valtwas t=aave) --
Although 7, 1994 event, the ports functieced as designed during the April 4% -R -d . roll were subsequently diesesembles and identified with the 70RVs. disassembly three concerns were oresking en the inning beesEsth 13m1 and spas emedbites uhiek esataland the anti-retEtiemal n. 1753 had galling at the stem and both valves had sour in the am8, area. A detailed root cause analysis was lai to i with the 70kVs. "- e11 eanoorns I 4
- a. creek in the pinning Bees (19R1 sad 1723) -
i i en eraaks in theexamination metallegraphic piantag hess to were be 1::tdetermined through i ,..es-1ar stress 3 corrosion oracking (20300). The extent of ersaking was ' similar in LPR1 and 1333 esteading from the top of the pinning boss, above the a,nti-retation piabele and
- continuins dava to just below the top of the ples. The orank in 1PR2 was about 3/16 insk shortar than 1Mti, poetrustive ===i==tien of Epsts was by the I Westingbouse Electria coepeestaan sah. me resulte l of the metallographis summimetions of the areehad
- regions shosed that the erneklag feitswed intergranular norphology. The results of the examinations confirmed thee areek tai sogarred i at the top and battaa surfeos locations ed the plaholes '
The E-sture a appeared flat aaf was severed with anand - s z owide layer. b estee was hoewy at the areGR aseth
, region and une very 11 Wit et the eraset . the absenos of heech masks india *md that j to leads did not play any sole la the erecIr,progrees .
strees ana fracture m andam ans3ymes were performee to evaluate the streme esadition la the valve plug and to assans the potential fee additional creet geguth. j The stem war modeled am 31s stataless steel and i the plug as Type 430 ese steel. Stresses in the ' l i
- plug were nalculates for e amiessa temperature in the --
stem and plug of $50*F. ghe results of theon analyses l show that the differential thessal espansion of the staa and plug cause significant stresses in t$te pinnine
, boss. In saattien, stem imeta11ation torgne and i pinhole stress conometration result in total hoop 1
t stresses of about too.Es* in the violaity of the ; anti-rotation hele. ! 1
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i l 1 { NIA-N940S$ j 3 Attaakaastt 1 . k k j i two-dimensiemal pFreature mechamies'omaanistions naamt of the plug near m were 4 pamming toes, une stress eslanlated for a ty factor uns j sapaneten temas and ofstem ereek aimes see the thessai protond. 4 stress intensity fastees were calostated S edisastly salostated in i the di finite steenat analysis based on caloalated j Al legament restits meer the aimmiated steek tip,
- the stresses in the plus.hady eaaresses intensity rester tally moving _ away team the stem, m nerees i sIF)omlealeted's2F'sh does not doorense and j fairly eenstant. (Se at remains er above i
possible,itleftinserviso.the therefees osotimmedthreshaleeencet growth is 1 ,. i We have constased that the ami osofigures 43e { stainless steal trian assenh11es he removed from 1PR1 mae 13R3. 95 4 eve initiated a design change pankage to re-install tria assemblies sin 9m? to the t anterials utilised prior to 430 statalems steel (sts j stainless steel ange).steel ste111ted plug with a 17=4 stainloos i 1 j b. . seaffing in the plug one cage (,13R1 and 1733) Tbs DORen are an air aparated ( 1 1 seat, unbalenose plag, songe tagretarshsingle globe valve. 1 As the is east . i the souff condi as e eside for velve stroking, ! uns het totally enexpected due , to the intentionally tight telagemens hetgeen the valve body and all internal parts. The t olearansa ana toleranos en the gelde tiemeters tasa with stem ! flouthility a11swa onge even ensee low side Imade. for sliding contact between plog and' l, 1 I nimensional messunemente et both velve tria assemblies
! were erewings. taken and the as compared assinat the valve maangsetarins i a===f este were ly within ; all naamfacturing toleramoes amoset tue inside l diameter (ro) 1eestians ter a,paa enge. En the area of souffing the ID use between 1.s to 1.
sine esap,ared vi ammerestaring telemenos.8 mils under and ongs were not destrustively examined. We17R3 plog i 4 believe the condities is eatiner a roomit me est of toleramos me (antarial h ina er increasederthielmens deposition esurtion).due to the montfins
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{, Attachment 1 i the weer en arms was as espected. { greater than normal and was saat likal the wear en 17R2 was l variation in riele assembly, tas see te tal eut er 2 i tolerance ID at the material. poses nas the presanon'ee foreign i I proceempos to its lasta11stien er movement ide greater assuranos of ensethn veri tapeeved the adequacy of these stem assembly centering. ess To f ten times diamammahi ed and , 19ma was streared
- er , top s,, .ea , .a. f. n..
. We galling
{ 1 ! During salen unit 1 eleventh resueltag amonge (Fall, 1993) were the a1721 via desian81F83 change.valve The tria asseelies t shames wee to ime og the ! resistanos of troer ame tag i 1 wear parts. the materials installed 420 harden.for internal wear parts (cage and at were ! ed martens & tic stainless steel. a was i 316 stainless steel. Who imoorporated the valve i ' annufacterer's prefereed 1 for severe servies I applientions ame commercial applications. nas been used for mer 30 years in i
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1
- c. Galliny at the stas (1723)
- l i The stem galling was ens to the tight clearamos between \
i { the stem ans the bonnet sten guide along with variation ! in field eseeably and alignment og wa3va internals. l 78384 has modified its installation prooseures to
%ce the possibility' for misali . 3854s has i
i r us aced the internals of a with new internals the improved installat pseeedares and methods. In ition ! Pearscontaintagnewinternals.3834e performee the FORV was stroke taats se one es the! dian mmawam ger lampestica fellowing the etsehe test. i Ne ga111ap was notes. The 30R7 was r====amhlet using the revised procedures. =
- d. Unit 3 30RTB '
i j 78360 has determined that 17=4 stainless staat valve ! tria assentlies stainless stest are tria installed in Unit 3. The 17-4 - t shie vers tastallet. qssemblies ese similar to theos 1a both Whit 1 and 2 et tima of -- l initial operation. Talve inopacties ans poesihte upurede are planned for the Unit 3 eighth refueling outage scheduled for Fall 1994. e i l 4 3 l l
- - - - - - - . - ~ . . . - . _ . - - . . . - _ . . - - _ , . . - . . . _ . _ . . . - - . - ~ . - . -
may w.a = -d **'5.* ' w 4 1'. * ^.L'. . . .
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l l 1 ! I . I 1 h j ELR-N94089
- i '
4 Attachment 1 i / i \
- 22. eraamuriser.==**** wm1was ri m , imma, and 1mn k Tailpipe i
rinnered fur tures for 1354 intioated that the valve had th i metatein pressure.e time period the sosyn tsare eye 11ag to , l a verdor for a set pressure SEB&O ans removed seat Isakage 1354 and want it to a tests. The resulte er the testing indicated laskege at the 904 lift setting und the set pressure s1 M ely above the seguired setpoint.
- ,rollowing refurbishment b a ' performed birth' tests satistaatseity.y the vender, the valve- -
i 1 Assad 17R5 for en tetting. tfae test results et spas, peste memoved tras and 4 j Isakage and set pressure 19R3 performed tests, trassatisfooterily for both seat } i 2eakage test satisfactor11 passed the meet i alightly above the r=- i m{,setpoint. 7tbut the initial set pressure was 11eering j ruteustamaant by the venqpe, the spas performed both testa satisfactorily. *
- l i During the April 7, 1994 event, the pressuriser safety valves ranottened as designed.
122,. Pinine Stru h ea1 Yn+ = ity " i i e as duringa iresult of the se114 p1 mat somdations that oesurred the event i \ the 50RWs disaharged at ebear motpoints to mitigate over-pre,ssurisatiam of the monator coolant syntes. The operaties of t&e FORTS resulted.in a discharge oc rivia , i cros the pressuriser to the Pressuriser Ralief tank (332). ! The piping and su during the event.pports were evaluated for Iceds emperienced ; i Included wese Pom7 opening and elesing ( times, number of orales, as well as fluid temperatures and , and fluta conditions i.e. enter, steen and two . ! pressures phase. T $e dotataed noeults of this,evaluattom are [ oonta.ined in an engineerimy evalestino. ! In addition to the above, seatin genes has evaluated this i event for the peessuriser and mossles. It has been f, determined that this evenk is boundes kr estisting sales oceqpaaent fat anal or those anal done en other westinghouse p iting similar features. o
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avisvs4 lea u. = m m 42.'_^.41 m. 2 - ,, 1 i 6 . l
- N1Jt-W94089 5 1
Attachment 1
! i A number of walkdowns were parversed by members of !
1 sagineering Quality & plant Betterment, Eneervlos Inspection and Assuranet.
- damage or emoessive an 4
rigid suppemats Asaremnitofthmanwathdowns{1 Ape movement was cheerved. & piping, j and anabore were observed la their essign position,s. i xt should be.moted too oometant spring i with bent rode sts were found s sowever, these s(upports areC-pBR-143 and c630s-149), operable. six-way restraints, anchere'O- aosat i.e., tuo feet foes 14e and e-Pan-Ese respectively. No damage to piping er the anchore was ) obaarved,
- based on thaea findings, we have oomstuded that i
the bent rods are met e resvit of the April 7,1994 event. j . The design condition. heut rods were replaced to restare the supports to taoir i j In suineary, based on the results of'the pip evaluation, the m systen i 7 3 avaamation per by Westinghouse, and SIMB system Weikdowns, the 90EV and safety i valve piping from the peeasuriser to the W52 was and is j strw;.usally adequate and the ourWent analypet benada the events of April 7, 1994.
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( , sales has experiemoed det flow indication that has indicotton la the Main steam eight channsla periediamily. Investigation ' re-onlibratica of the of the enamtlies determined that indicated trift was not a real steam flew. Upon prewfoua detailed emanimation of the piaat process parameters, it was deternimed that instrumentation tubing routing is a magnittaant somtributor to the problem, 98248 has postulated s.aat this drift &ag is des to being trapped in the tastrumentesten tubing. The was not designed er installed la eooordanos vi AS1Etubing 4 measurement requirements. Se otiainate this probles, 98860 flow l has installed a design in sales Unit 1 that included ! the fo11ew a1 en-insula , larger aamaannage 1 i
- 3) la ing), and 3) re= routed tpbiime in ,
with Amts s . This new configarstion should el the trasmed gases and ensure filled lines. l ' conTr auration has ntC good restits The new for a limited operating time M . The dee16n change is planned to be i installed en vast a sering the aunt refueling esta j tollowing a confirust.lan of the results se Unit 1.ge 1 i - 1 . i . - .
eqww wits w a % v ~e ' * .^.t.2 .. 2? - ~ . - i t i .. i - j . I NTJt-N94049 4 1 Attachment 1 - j (' v, wina- amm - -<*w - L( . j - n. selee reannical specifications (T for the minimum shift ocuposities for both sa/s) lem ta eyewating is (A) Three (3) senior Boeotor Operators (smos; which i imelusas one senior muelear Shift SupervSeer (suss) and ) two Euclear Shift tugegvisors (Ess Sitterflunation. et the tvu N6s can 2412111 the sanft techgioen).Adv.iser I { (3) Feer (4) Wuolear control Operatore (NODS), l (c)
- one statedsaiet above. Tentaat Jhaviser (sta) if not fulfilled as 4
I In su , eneh unit has tue (a) N00s in the sentrol room while in 1-4. They are ised by one 1) We (sno-licensed), with the tuss overalt i reopensimility for both units.( As sua is else1aceameet hav j the minimes shift coupesiticin and any be one of theuded in amo-licensed supervisers. - 1 ! Licensed operator simulator training has demonstrated tha't s all Desien Basis Anoidents (Dak erants) and operet,Lonal i transients oma he smooessfully mitigated with the minhua shift tien desorihed above, amesetere, the ptseentlyi ,
- ( requires ical specifications is deemed to be adequate, i l
rue apett wm event was initiates by the unusually large amount of grass that ampumaleted en the eiseutettag Water i i travelling careens. Ehe resultant doun poser abould beve been annaged effectively with propeu,eseeeroe management and ' direction from the NES. As diesessed at our meeting en May 6, 1994, the number of parecenal ressurses ses met a causal factor of this event. One of the asia centributing fairters was how the sesourses womo unnaged by the use. ;
- Unclear communications'between the on-shift personnel and '
incorroet priorittaation of tasks for the osotrol reen personnel were contributors to this event. Spesifically, the NES decisi to transfer the group heems lasteet of manually ts* the main turbine was not the utilisation remooreae at that time. After event.' management e':pectations concerning resouros management and direction of sersonnel were portened with eal liosases shift personnel on the simulater. Sevessi recent events inwelving ~" 1 rapid power reenotions see to eissulating water problems naa 4 been accomplished successfully by other shifts including,the removal of the unit from servias, pesas believes taat une { present requirement for the T/s minimum shift omiposition is appropriate. . i 4 i 4 e r , , - m *- - _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _
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5 e.w. s. ' Doctr6c and Gas Comp *ar j i Steven L Matocher9er PutAc Semco Electric and Gas Company P.O. Box 236. Hancocks Sridge. NJ 08038 009-339 4199 j ww w n ma eme.mn omeer KAY131994 l N1Jt-N94094 ,i Regional Administrator ! U.s. Nuclear Regulatory Commission
- Region I i 475 Allendale Road King of Prussia, PA 19406-1415
Dear Mr. M&;rtin:
4 . j REQUEST FOR SUPPLEMENTAL INFORMATION { SALEM GENERATING STATION i UNIT No. 1 l DOCKET No. 50-272 l ! On April 25, April 29, and May 10, 1994 PSEEG issued letters t9, l
- the NRC and identified actions that had been taken or would be taken as a result of the investigation into the April 7, 1994 salen Unit i reactor trip and safety injections. On May 11 and 12, 1994 the NRc requested additional information concerning Main j Steam Flow Transmitters, Power Operated Relief Valves, Shift I composition, Management Effectiveness, Marsh crass, Work Practicas and Unit 2 "Jesign Modifications.
The additional requested information is provided in the following
- attachments to this letter:
Attachment 1 Main Steam Flow Transmitters ~ Attachment 2 Power Operated Relief Valves Attachment 3 Shift Composition Attachment 4 Management Effectiveness Attachment 5 Marsh Crass
- Attachment 6 Work Practices Attachment 7 Unit 2 Design Modifications PSE&C will submit a separate letter to request your agreement'for restart and lifting of the Confirmatory Action Istter. Should you have any questions regarding this submittal, please do not .
hesitate to contact us. i
- sincerely, As s
)
Cs I 1 Attachments (4) , 9ttoSS3t>7f Sfp
g g. o 60 m , u. $ , . rxau44weanc vva _. .6cu - o, w i . 1 . 4
. Mr. T. T.. Martin 2
- NLR-N94094 I i
i C Mr. J. C. Stone, Licensing Project Manager - Salea j U.S. Nuclear Regulatory commission " one White Flint North 11555 Rockville Pike Rockvilla, MD 20852 l United States Nuclear Regulatory Comunission Document control Desk 1
- Maahington, DC 20555 1
j Mr. C. Marschall (809) USNRC Senior Resident Inspector { ^ Mr. K. Tosch, Manager, IV ' NJ Department of Environmental Protection i Division of Environmental Quality Bureau of Nuclear Engineering CN 415 i Trenton, NJ 08625 i f i
.and. .
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5-13-84 ; 12:47 i PSEAG LIC & Rffe SENT BY: 301 504 2162: 4/3 1 ! f.~ 1 i - ATTACIDIENT 1 1 't a,wnw prAu ruegeranw=Ta urn uware um_mys
}
on May 11, 1994, NRC Region I requested additional information j i relative and to salem reactor Unit Nos. protection 1 and system 2 main logic relays. steam flow instrumentation The following information I is provided in response to the NRC roepasst, j STEAN. FIDN INSTRUMENT IQRIFT .AND CALIlBATIDM i 1 The steam flow in each main steam line is deteraireet by continuous 1v l measuring the pressure Gifference across the steina line flow ' i restrictor. The flow restrictor is a venturi type flow meter with an overall pressure drop of approximately 5.0 paid at 1004 rated flow, steam flow measurement drift has occurred since initial plant operations. This phenomenon was ggesented to the NRC at Region I on May 15, 1989. It is believed that the steam flow calibration was with tiac due to entrained gases collecting in changing the sensing(increasing)ich lines, wh is caused by insufficient sensing line slope and the use of insulated condensate pots. Two independent consultants have supported this determination. Technical specifications require a qualitative channel check to be performed every 12 hours. Additionally, the System Engineer routinely trends the steam flow channels while at full power. Recalibrations are performed whenever the indicated steam flows ekceed station administrative limits of i 34 of rated steam flow as compared to the on line calorimetric reactor power while at 2004 rated thermal power. The administrative limits are contained in salem operating procedure SC.0P-DD.23-CD23(2). Escalibrations have been performed to correct drifts of i 3% to 5%. See the attached Unit 1 steam Flow - Cycle 11 graphs. 1 Decreases in indicated steam flow have been observed after reactor trips or plant shutdown because of gas entrainment in the sensor I instrument tubing on either the high or low side of the sensor / ' transmitter (see the attached Unit 1 steam Flow - Cycle 11 graphs). With changes in pressure in the steam lines, non-condensible gases will either go into or out of solution. Morisontal or negative slopes in the sensing line can result in the collection of these , entrained gases and add to sensor differential pressure error. l 1
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EFFORTS TO CORRECT IMsTRUMENT DRIFT l To eliminate gas entrainment and resulting instzument drift, a modification has been installed on Salen Unit No. 1 that included l installation of un-insulated larger condensing pots and larger ; diameter, properly routed tubing with greater than 1.0 inch /ft slope. i h e
5-13-94 ; 12:48 PSEAG LIC & Rfre 301 504 2162;s 5/3 E BY: i - l It is believed that the presently installed, modified steam flow I sensing lines will effectively reduce the drift concern. There has been limited operating time with this newly installed modification. A similar DCP for Unit No. 2 has been prepared, SORC l i approved, Fall 1994 outage. and is currently scheduled on the active work list of the I In the event that recalibrations are required during the current Unit i No. I fuel cycle, further analysis of the effectiveness of the modifications will be performed. Imssons le5rned from Unit No. I will l be applied as practical to the Unit 2 modifications scheduled for the Fall 1994 refueling outage. I cYeLTNG OF STwant Flow INDUT BRYAYS IMfB TO fMtTFT AMD MOYett Gradual upward drifting of the steam flow signals, combined with the low signal / noise ratio of the process resulted in the relay chattering that has been identified. The modifications to correct steam flow drift and the installation of a dgeping circuit to de-sensitise the transmitters 8 time response will significantly reduce relay chatter. j The main steam flow drift evaluation has determined that the most i probable cause of the drift is instrument line configuration, as opposed to transmitter or sensor drift. Electrical noise associated with the steam flow signal is not considered to be a
- contributor to the cycling concern. Positive steam flow drift of 34 to 54 coupled with sensed process noise, not electrical noise,
! allows the instrument loop comparator to exceed the setpoint. It i is the process noise that causes the multiple trip and reset l comparator functions. The reset value for the setpoint is 14 steam flow, 40 avde, of the four volt loop span. The administrative limit I of 2. 3% discussed above has minimized this cycling concern. l A design modification to install a damping circuit to desensitize the ! transmitter in order to dampen process noise, has been implemented at Unit 1. This modification will help prevent relay cycling as 4 described above. The installed Unit 1 modification is being evaluated l to ensure adequate resolution of the process noise issue, and to . support evaluation of a future design change for Unit 2. STEAM PRESSURE PUIAE DURING APRIL 'F. 1994 EVENT l The turbine stop valves are reverse check valves held open by a hydraulio actuator. The quick closing of the turbine stop valves generates a compressive pressure wave which travels up and down the i pipe at the sonic wave speed. The effects of these shock waves on the {; sensing lines and differential transmitters were recently analysad as' a result of this event and determined to be a contributor to the j spurious high steam flow signals. The efforts to reduce sensed a process noise discussed above will help eliminate falso steam flow j signals resulting from pressure pulses. j 4 J 1 .
SEST By: 5-13-M : 12:48 : P5E&G UC & RErr. 301 504 2162;* 6/32 l . fanic TRATMs' nap e r txrRInc Apart 7. issa sym r l There is currently insufficient data to support e oeuse/effect relationship trains' between response duringrelay the April chatter and the 7, 1994 difference in the lorfic event. and B relays share inputs from each of the Channel Note that I and II Train A transmitters. All relays performed well within the Technical Specification requirements based on response time testing. The as-found relay drop out times were tested and found to be reasonable l for relays of this type, based on manufacturers' information on the replacement relays. Testing indicated that Train B responded slightly l ' slower inputs. (15 manc) than, Train A due to spurious short duration pulsed PSEsG attributes the root cause of the ditfarence in the logic trains' response to the short duration of the protection signal combined with normal variations in relay pickup and dropout times. l A visual inspection of the high steam flow input relays indicated discoloration of the relay cases and some apparent carbon deposits. These relays will be sent to P8E&G's laboratory for analysis in an attempt to determine the effect orl actual relay performance. ! All testing showed that both logic trains performed within the Technical specifications requirements for actuation and time response. l ASSURANCE OF v1TNTAINING STRAM FIDN r'RAMMEL PERFORMANCE WITHIM TECHNICAL SPECIFICATION LIMITS - Each shift, channel checks are performed for steam flow indications. comparisons between reactor calorimetric power and steam flow l l indication are also performed on a regular basis. During channel checks, if one steam flow channel differs from the other channel by 5% at >154 power, Technical Specification 3.3.1.1 is entered. System engineering is notified when the steam generator steam flow / power level channel check 3% administrative limit is exceeded, per operations procedure SC.0P-DD.ZZ-OD23 (2) . Upon such notification, calorimetric and steam flow differential pressures are evaluated and recalibration is performed if necessary. The recalibration of the transmitter (either directly or by adjustment of the summator) re-establishes the 0-120% steam flow corresponding to , 0-1004 transmitter output. This relationship is the basis for the setpoint calculation, and the scaling of the steam flow channel. As long as the transmitter relationship is maintained, the setpoint analysis (SC-CM007-01) is valid and the current Technical Specifications setpoint ensures that the trips will occur when required to remain within the safety analyses. 1 l j ' l
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- i ATTAcmENT 2
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i 1 j EVAIBATICBI OF UNIT 1 AMD 2 souum OPWDETED am.Tw TnvE (pony) meeeWikTLTTY l ) Each PORY used at Salen is an air operated Copes-Vulcan 2-inch globe i valve, with 3-inch inlet and outlet connections. i seat, unbalanced plug, cage-guided, globe valve. This The valve is a single design is ! typically used in both the commercial and nuclear industries in a wide i i range of applications, including steam, water and flashing fluid. The cage-guided, single seat unbalanced plug tria relies on actuator force tc close the valve. The cage-guided plug is the focal point of the design j and provides a number of advantages, such as
+ guick change tria capability, e
concentric alignment assurance for seating surfaces, i + even distribution of fluid thus limiting side-loads, i + restriction of lateral staa and plug deflection due to { 4 side-loads. l SALEM UNIT 1 PORV INTERNALS REPIACEMENT $ The internals, (stem, cage and plug) of the PORVs, 1PRI AND 1PR2 on the j Salen Unit 1 pressurizar experienced material degradation following the i~ reactor trip on April 7, 1994, and were subsequently replaced with new internale. The design change replaced the stem, plug and cage assemblies i with new assemblies as shown below: ! ITEM EXISTING MATERIAL NEN MATERIAL Sten ASTM A276, Type 316 ASTM A276, Type 316 Cond. B, Chrome Plated Cond. 8, Chrone Plated 4 Plug ASTM A276, Type 420 ASTM A479, Type 316 j Full Stellite i except top surface a ! Cage ASTM A276, Type 420 ASTM A564, Type 630 l (17-4 PH) a l The above new materials selected for this application provide wear resistance and were recommended by the valve supplier (copes-Vulcan) for ! this modification. , 1 A new plug design was implemented which eliminates the boas used in the ( existing design and provides a more rigid stem / plug interface. The staa is now pinned to the plug instead of through the boss. In the new j design, the plug height has been increased to account for the elimination i of the boss, thus providing the same stroke length as before. This j modification, therefore, will not affect valve opening or closing' time. ? l 1 ^
m____ _ _ . _ _ _ _. _ _ _ _ _... __ _ ___ _ ____ _ _.__ _ _ _ _ __ _ _ _ o-au-M ' 6d' ' ' " " * " * ' " ' - * - ' * " * '
@ T BY' I
I To decrease the likelihood of stem and plug wear, PsEEG has modified its i installation procedures to reduce the possibility for misalignment. The revised procedures provide greater assurance of smoothness of movement i and improved stem assembly centering. This is accomplished by hand j stroking the valve periodically during the valve assembly process. The i 4 tight clearance and tolerance are important for wear characteristics and functionality of the valve. sliding contact of the valve is not unexpected due to the intentionally tight tolerances of the valve design. i The replacement of the internals of the PORVs changes neither their i functional nor their performance characteristics, nor will this replacement affect the ability of these valves to perform their safety ! functions during any design or licensing design basis event. f The actions taken, as descibed above, are appropriate to ensure the j continued operability of these valves. i i i i SALEM UNIT 2 PORVS , During the 1993 Salean Unit 2 Seventh Refueling Outage, plug, stem and ! cage tria assemblies composed of 17-4 PH material were inadvertantly installed in the salen Unit 2 PORVs. I 17-4 PM stainless steel tria l ! assemblies were previously used in the salem PORVs and the acceptability I of their performance is supported by testing conducted by EPRI and l ! documented in EPRI NP-2628-SR, "EPRI PNR Safety and Relief Valve Test ' l Program, safety and Relief Valve Test Report", dated December, 1982. A summary of the valve tria currently installed as new components is 4 given in the following tables l t l ITEN EXISTING MATERIAL REAT TREATMENT { Sten ASTM A564, Type 630 H1100 i (17-4 PH) l Plug ASTM A564, Type 630 8900 i (17-4 PB) I cage ASTN 1564, Type 630 N1100
- (17-4 PH)
I 17-4 PH stainless steel is a material which has been used for many years, and which continues to be used, in valve applications (including PORVs) ~ ~ at other nuclear plants as well as in non-nuclear industry service. ] EPRI conducted a series of tests on safety and relief valves at two test i sites, Wyle and Marshall. These included tests of copes-Vulcan valves j similar to the salem PORVs with 17-4 PH stem and N ug materials. At the i j (* Quotes on the Wyle and Marshall test site information are taken frca j Reference (1) )
- l t
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j SDT BY: W** "' 0 i 1 5 i wyle testDuring design. sitw, "a total of eight (8) tests were performed on this valve all tests, the valve full demand. Following completion of testing,y opened and fully closed on inspected by the Copes-Vulcan representative. the valve was disassembled and ' i had partially ' washed out' during the testing. TheNoange to body damage gasket was observed j that would affect future valve performance.** lj ; i At the Marshall test site, "the valve fully opened on demand and closed i on dame.nd for each of eleven (11) evaluation test cycles.** Additional l testing perforr.ed after ths successful testing produced the following ! results (specific information relative to the additional testing J parameters / conditions is not detailed in the report). "A new set of the ' l same design cage and plug parts were then installed and the valve was 4 j ayoled to investigate the cage to body gasket perfot m and to support other Marshall steam station test functions. !
- demand and closed on demand for the next 43 oycles.The valve Six fully opened on 1
j i cycles were performed under full pressure / flow conditions.(6)The of these remaining i cycles were either dry, unpressurized actuations conjunction with other valve testing. During the next five full or openings / closings in i ' pressure / flow testa performed, the valve did not fully close on demand. However, position. the valve always closed to within 13% of the full closed ! surfaces."* Disassembly showed galling of the cage and plug guiding As a result of the unknown parameters / conditions of the additional tests, results of these tests are inconclusive. It is noted that other plants are currently operating with similar 17-4 Pa tria assemblies.
~
'i (* Quotes on the Wyle and Marshall test site information are taken from Reference il) A large body of data on wear is reported in an early report on the Naval i Nuolsar Program (Reference 2). In this research, wear is reported in i terms of venght loss (allli ? wear travel (aq/lb-alllion) grams)
. per A low value pound is associated load for a with million poor cycles wear of i
resistance. The data in Table 7-3 of the reference involved both piston-cylinder and journal-sleeve tests. The wear for the 420 against I 420 is reported as ranging from 130-185 mg/lb-sillion, while the wear for ; 17-4 PH against 17-4 PH is reported as 460 mg/lb-sillion. For i i comparison, the wear for 304 stainless steel against 304 stainless steel, 3 i a combination known to be susceptible to galling, is 3,200 mg/lb-million. It is therefore concluded that, although 17-4 PH with 17-4 PH is more susceptible to wear than 420 with 420, the 17-4 PH plug and 17-4 PH cage i combination installed in 2 Pal and 2PR2 is expected to be satisfactory for the current fuel cycle. l The wear of 17-4 PH is significantly dependent on the hardness of the . - i material, which can vary substantially as a function of the heat ! treatment. The Salen Unit 2 stem and cage were aged for four hours at i 1105 r, then air cooled, with a reported average hardness of 35.00 i Rockwell C. The plug material was pre-heated at 860 F for one half hour, j j aged at 900 F for 1 hour, then air cooled, with a reported average hardness of 43.50 Rockwell C. The purpose of heat treating the plug and 1 j the cage to different hardnesses is to improve the wear characteristics in service. In order to reduce wear / galling, a Copes-Vulcan practice is j to maintain a Rockwell c hardness difference of 8 pointe via the heat .i ' 5 1 a 4
~
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treatment process in like material. In the Naval Nuclear Program waar i tests reported above, there was no mention of the 17-4 PH pairs of 1 materials wear having had different aging heat treatments to improve their characteristics. The 17-4 PH pairs of materials now in Salen Unit j 2, with the two 17-4 PH pairs with the same different hardnesses, hardnesses. are expected to perform better thar t I I In addition, the EPRI tuts made no mention of the plug and cage material hardnesses. j Without an appropriate diffarential in plug and oege i hardnesses, wear would be expected to be greater than in the case where
- the plug and ange do have an appropriate differential in hardnesses. The which is the desirable combination.Salen 2 plug and cage.de have a hardness differe The valve supplier, copes-Vulcan, has stated that 17-4 PH oan be used for i
this application, and that it is an ASME code listed material for j pressure retaining parts (Reference 3) . } In summary, the 17-4 PH stainless steel stem, plug and cage installed in the hardness) salen 2isPoRV valves-(with the plug and cage having a differential in regarded as being a satisfactory materials selection for this application for the period of one fuel ayole. PORV's with 17-4 PH I internalw test facilities. were tested at operating conditions at the wyle and Marshall j so adverse performance was recorded at Wyle Lab. The 1 first set of tria materials following the testing indicated no adverse findings. The second set of tria, following*a total at Marshall Test also i of 48 cycles, rep ~orted galling of the cage and plug guiding surfaces. 1 The valve closed to within 13% of the full closed position. No findings } related to the valves ability to open were reported. i i In the event of a PORV's failure to close, the block valves are capable i of integrity. isolating the PORV to maintain reactor coolant pressure boundary These valves have been verified to be capable of performing i their function under design basis conditions in accordance with the j Generic Iatter 89-10 Nov program. A 10 cFR 50.59 safety evaluation has been performed which concluded that the 17-4 PH tria assemblies, installed in the Sales Unit 2 PORVs, will 1 perform as designed with reasonable assurance and reliability and will remain capable of performing their specified functions for the current fuel cycle. l 1 I (
-,,-~,c, , , , - - ,-----.,,-n , . --
l g gp a 6a a, , at.w, . a w s ' e su.c- vv6 995 'o w -oo, w i 4 . 4 I } PEFERENCES a i I i
- 1. EPRI NP-2628-SR, "EPRI PWR Safety and Relief Valve Test l Program, Safety and Relief Valve Test Report", December 1982 l 1
- 2. TID-7006, Corrosion and Wear Mandbook for Water Cooled 1 l
i Reactorm, D.J. DePaul, Ed., USAEC, March 1957
- 3. Istter and attachment of May 2, 1994 from T. Runkle of l t
Copes-Vulcan to C. Lambert of PSE&G 1 i l 4 t l i e 1 .i i 1 1 I l 1
.and -
1 l
) l 1
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- SENT BY
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- j ATTACIDEENT 3 ,
2 EA = = RTEY i PSE&G's operational experience has established our confidence in 1 the ability operate theof the presently facility. required shift crew to successfully i Our experience has indicated that licensed i operator' simulator training with the minimum shift composition, as j required by Technical specifications, is appropriate to properly I mitigate all Design Basis Accidents and operational transients. i i PSE&G April 7thidentified event. aOne number of root causes contributing factor and wascausal factors for the utilisation orthe l i ! available resources by the Nuclear Shift Supervisor (NES). The
- resources available to the Nss were appropriate to successfully
! control plant utilised. operation, if they had been more efffficiently { The prioritisation direction and sequence of actions is ' referred to as resource management in our corrective actions as i shown on our April 29, 1994 let$er (Ref: NIA-N94084). l l i A number of other corrective actions have been taken. Some of the I corrective actions are in the form of enhancements. rocedural/ training I i ! Other actions involve d scussions of lessons learned ' ! with all shift personnel, and insuance or en operations Management ! Information Directive to all licensed and non-licensed operators ) ! consunicating the April 7th event. the lessons learned and management expectations from i ' i I { Some sessions of the topics discussed with shift personnel during training include: I . (1) temperature control associated with rapid down-power s j .aneuv.rs, 4 l (2) resource management, (3) m ioritization of tasks and re-enforcement of proper communications, (4) minimum tamparature for criticality and associated corrective actions. 4 Procedure changes associated with this event include: j h (1) 81(2) .OP-AB.COND-0001(Q) , Loss of Condenser Vacuum ' (2) 81 (2 ) .0P-AB. CW-0001 (Q) , Circulating Nater System Malfunction. l (3) 51(2) .OP-AB.TRB-0001(O) , Turbine Trip Below P-9 4, (4) 51(2) .OP-IO.33-0004 (Q) , Power Operation 3 s i 2 i
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i ' i o The procedure changes and training enhancements coupled with the { re-enforcement of management's expectations will provide less 1 j challencies proper prioritizationfor the operators, of tasks. better management of resources and i 1
! In summary, the corrective actions to enhance our procedures and 4 the ability of'our personnel to manage transients will result in improved control room resource management. In conjunction with the i
I
; licensed operator simulator training and demonstrated ability to mitigate all Design Basis Accidente, these items form psE&G's basis j for concluding composition that the Technical Specification minimum shift is appropriate.
i l 4 1, 1 ! i l 4 . l i i 0 i i
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****** " T EFFECTITENESS l PstsG has taken a number of actions to ensure adequate supervisory and management oversight of plant operations. Many of these actions have been completed and plans are in-place to j implement the remaining actions. The primary focus areas ares t
I e salem Performance Improvement l j 4 Quality Assurance / Nuclear Safety Review Oversight e Augmented Independent oversight 1 I m se areas are discussed in more detail below. i l a / l l SALEN PERFORMANCE IMPROVEMENT 1 I twrahansiva parfar=^aca ima== - nt , i PSE&G Management has implemented significant material condition ! upgrades at Salem, including many design changes that directly i improved control room operations. A significant procedural i upgrade program was completed in 1993. While some improvement in j personnel performance has been achieved (e.g., reduced number of
- personnel error LERs), we recognised the need for continued improvement in this area. PSEGG recently performed a comprehensive performance assessment of deficiencies observed
, over the last few years, to susure we fully understood them and i that appropriate actions were in-place to improve salem j performance.
- PSE6G has incorporated the results of this assessment into a !
i Nuclear Department implementation plan. This implementation plan ! ! will be our major focus for 1994 and beyond. Some of the actions identified in this plan are completed and others are underway. Many of the actions result in cultural changes which take tias and nurturing. salan r.nhanced sunarv1=arv ovarmishe In order to make an immediate impact on the organization, the following near ters actions have been initiated to improve supervisory management oversight of plant operat. ions. Our primary areas of focus are lead &rahip improvements at all levels e
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4 .
- within the salen organisation, to assure the proper sense of 3
ownership from all salem employees, and to improve overall etficienty through teamwork. i required to ensure across the board improvement. Improvements in these key areasi j Improvements in ' 4 leadership, ownership, improved management focus. and teamwork will primarily result from ! The improved focus will result from organization structural changes, putting the "right people" into key positions, investing sufficient supervisory time in the j field, and continued naturing of the supervisory monitoring
- program.
i 3 Personnel and structural changes are in progress. The intent is j to unitise planning, Operations and Maintenance below the manager level. salen staffAs by part of this re-organization, approximately (80 individuals. we are increasing the i total is additional supervisors.) The additional supervision will About 25% of that ensure sufficient oversight, increase time in the field, and i enhance confidence that expectations are being met. A supervisory model was developed to align and clarity standards i and expectations for supervisory personnel. This model has been i communicated to supervisory pedonnel. The overall objective of j these changes personnel focus. is to improve teenwerk, ownership, and salem - 1 A new team of department managers is in-place at salen., In addition, we have established Station Planning as a se?arate department with its own manager. We have added a second . Maintenance Manager and separated the mechanical and omtrols 8 departments under their own manager. This results in increased management focus for both the mechanical and controls areas. Two new individuals have recently been assigned as Unit 1 and Unit 2 Operating Engineers. A third Operating Engineer has been i 3 $ established on an interia basis to provide in-field oversight and direct monitoring and assessment of supervisory personnel until such time as our standards are institutionalised. We have assigned a Unit 1 and Unit 2 Senior level supervisor to the i operations work Control Center, to provide a direct link to . station planning and ensure timely notification and resolution of } equipment deficiencies that affect operations. The effort to place the right people into key positions is i i continuing. As part of the planning and maintenance i restructuring, maintenance senior supervisors and department engineers, and planning outage managers, department engineers and senior supervisors had to reapply for their positions. selection will be based on panel interviews and professional assessment ' provided by a consulting firm. During April, the department engineer positions in maintenance e,nd station planning were filled. These individuals have assumed their duties. These I changes will provide the opportunity to improve teamwork, ownership, and focus for all station personnel. The target date } j for completion of the senior supervisor selections is the and of June.
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i, SEST BY. 5-13-94 12:07 : P5EAG LLC & REG. 301 504 2162:223/3 i i k ."
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- . A middle management implemented to im level review of troubleshooting plans was i
troubleshooting. prove the quality and results of i I of troubleshooting activities has improved.These reviews have determined \ weekly focus and ownership meetings have been initiated by the Salem management team with their people. Thic includes 1 I individuals from department head positions to the custodians, j These meetings focus on what is important to produce overit-free j operation and what each individual can do to improve salaa performance. i i stronger efforts onleadership event freeissalen in-pleos to focus individual and team operation. i Improvements in the i hardware, design, and procedures will continue. As discussed ' above, many changes have been implemented and others are in-progress to improve performance. Additionally on-going re-analysis of existing projects to ensur,ethere is that the i } current Salen priorities, management team concurs with the project scope and l and that'any operabdon issues are properly addressed. j The affactive use of near term emphasis our people. will be on leadership and making more i i i gyALITy_AgggBAggtfNacuan SAFETY evTru ovenersiiy i PSE&G has taken a number of steps to improve the QA/MSR oversight i j and ensure this function is effective in identifying problems to appropriate plant management. j plans are listed below. Specific completed actions and Replaced the General Manager - Quality i Assurance / Nuclear Safety Review. Raplaced the Manager { - Nuclear safety Review Nsa . j They were provided direction from senior man (agem)ent to focus attention on improving oversight effectiveness. i codified our behavioral expectations for Quality i Assurance / Nuclear safety Review personnel with the j Quality Assurance and Nuclear safety Review Philosophies. 1' Conducted a third party independent effectiveness evaluation of the NSR organisation, including assigr.ed individuals. Evaluation results helped to focus our . ,_ l 3 i efforts to redirect the department, ensure that the department is providing an effective oversight function, and that properly qualified individuals are in place. Replaced the salsa SRG-Engineer (group supervisor) in i i April of 1994. j - 3 : j -
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i t - 1 4 j - I all MSR with them. supervisors, and are currently being rev These appraisals are substantially more detailed than has been the nora. They clearly convey { annagement expectations and define required behavioral changes. .i
- i Rotated Hope the QA Creek Salen QA Manager Manager to salaa. in February, and moved the j Since taking his 1 position in February, the salem QA Manager meets i one-on-one with the General Manager - Salen Operations 1
approximately weekly to discuss findings and observations. 2 3
- salen QA Manager is meeting with the operating shifts during the requalification training cycle to explain quality, and define QA's role and how it supports plant operations.
These meeting last approximately 3 hours. The sessions are eventy split between presentations and questions and answers. was extremely positive. Feedback from the first group 4 j for May 19. The next group is scheduled 4 1
- i several actions have been taken to upgrade surveillances.
! surveillance Reports now discuss the ' { Pour Imvels of Defense of Quality Model, and cite
- findings in terms of the Four Elements of Quality and i indicate which findings levels were less than effective when are identified.
4
- follows: We define the four levels as i
i -
- 1) Individuals and work groups
- 2) supervision and management
- 3) Independent assessment
- 4) External observation 4
j We have salen initiated station semi-annual QA assessments of each department.
- July. The first set are due in 2
l General Manager - QA/MSR is personally workin i Audits Group to enhance audit effectiveness. gInwith thethe i last year we have made substantially greater use of technical specialists. i blocked audit schedule to one that supportswe have moved from a co approximately two person-and evaluations per year. years of discretionary audits " i
- j At the beginning of this year, we initiated periodic Issues Meetings.
i QA/WSR Managers attend these meetings i to discuss items requiring autual support and i coordination, areas for,QA/NsR improvement, and ways to improve Nuclear Department support.
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) i - 1 i . L * { we further categorize surveillance findings in terms of which element (s) of quality were deficient. we have ! strengthened surveillances on critical evolutions. 1 Following the daily Plan-of-the-Day meetings, Salma QA ! asets to define evolutions emergent surveillances on eritical that day. j at salen Unit 1 in early April.We established 24-hour coverage i Unit i startup, Oh personnel who were previouslyDuring the up ! licensed operators will monitor startup activities in { the control room on a 24-hour a day, 7 days a week basis until reaching 1004 power. i 4 i we believe that the actions taken to date and those planned will ! significantly improve our self-assessment capability at Salam. } i attention, areas Deficient will be identified and escalated and brought to management's as appropriate. 1 l j ' AucanrwTED TunworunwuT ovennfairi 4 For an interim period, we will supplement the current Man i oversight with 5 additional people. They will re l the Manager - NsR and initially provide 24 hour,7port daysdirectly a week to i coverage of for oversight of plant activities and evolutions. -
- Evolutions typical of those we would expect to overview include
f - Reactor startups and shutdowns 1 ! - i I Low power operations ! i Special tests (e.g., turbine valve testing) j - Selected surveillances 1 selected major system evolutions i Safety tagging and work control f - Shift turnovers and plan-of-the-day meetings 8 Key maintenanca evolutions Material condition walkdowns ,i 1 t control room demeanor and conduct .. i Daily feedback will be provided to the sales management team by the Manager - NSR. Weekly feedback will be provided to the Vice L; j President and Chief Nuclear officer, and documented in the monthly report. Items requiring immediate attention will be j escalated as appropriate. i
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l The evaluated need to continue the augmented N8R oversight function will be periodically. The decision to terminate the augmented overeignit will be based upon station performance, nature and j significance of observations, and implementation of NSR ' organizational changes to improve NSR oversight. The VP & CNO i must function. concur with this decision prior to removal of the oversight { The augmented oversight willSalen address j in-place prior to MODE 2 on Unitboth
- 1. salen Units and will be I
i statMARY AND CONCIRSIONS J j j our comprehensive performance assessment defined specific problem statements. We have assigned responsibility for resolution at i identified weaknesses, prepared actions plans and associated measure ourand schedules, established appsppriate performance indicators to i i progrees. We believe this effort will establish ! long-term cultural improvements. i In the interim period, we have made changes and expanded our line management structure, particularly in the supervisory area. We have strengthened and { refocused our QA/NSR oversight. An augmented independent i oversight function is being implemented to provide real time . i i assessment of ongoing station activities, and to ensure prompt management attention to any noted deficiencies. I we are confident that the structural and personnel changes ! discussed above will provide the impetus and management attention j required for significant and lasting improvements.
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g.g.m , 14 00 QCaMJ b8b O w dul 0u0 A60&i464/4 i . 1 i . 1 j . - ATTACIDtINT 5 1 3, } - um=== ammen urnmanen pr.mm i , i i PSE&G's response to the increased marsh grass loading is divided into 1 short-term issues. and long-term actions and additional studies of the grass i Prior to the April 7 plant trip, PSE&G was aware that the i ! marsh grass loading was significantly densar than normal from prior years and had taken actions to mitigate the impact of the grass influx. i The amount of grass seen this year at the circulating Water Intake structure is such more than anticipated based on past experience. This i i which was characterized by significant ice storms. years marsh grass sit
- was followed by exceptionally high tides that resulted in theThe severe winter deterioration its way into the and uprooting Delaware Bay. of the marsh grass, which eventually made 1 As a result, operations and maintenance personnel were assigned to the circulating amount of grass Waterinflux Intake was structure anticipated. during. periods of time when a large j was to ensure that personnel were available to clean the screens byTh i spraying them and to maintain the screens in an operational condition i by performing minor repairs, such as shear pin replacements. This practice will be re-instated it warranted by grass loading conditions.
~ J This decision will be based on the trending and assessments discussed below. j pSE&G haswater Circulating cospleted system. some equipment upgrades that will improve the These were done prior to the and of 1993 and include:
+
3 Blowdown valves have been installed on the Unit 1 and 2 travelling screen low pressure headers to clear siltation and improve spray nozzle effectiveness. l ' + screen wash control panels and instrumentation have been replaced / rol ability. inhed on Unit 1 to improve system performance and refueling outage Similar 2R8. improvements will be made to Unit 2 during
! Subsequent to the trip, procedural enhancements were implemented, which included the addition of minimum condenser vacuum and circulators in-service trip. criteria for initiating a manual reactor and/or turbine This provides guidance to the operators to assure that their preclude a to response an influx of marsh event.grass is appropriate and to help to -
a future similar The procedural enhancements were 3 reinforced to the operators through training. a 1 ?
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I 1 . circulating water system.Further, longer-term, enhancements are being plann 4 i They include the following: e i circulating water screen modificationes smoother screens, } more efficient removal of grass and debris) travelling k _ j i It is planned operational speeds. to modify the traveling screens to permit high By increasing screen travel speed, the volume of river water that any given screen must filter between cleaninge is reduced, thus increasing t
- detritus without plugging.density in the water which can be naaa=he level of
{
=adated 1
i multiple speeds, the highest of which is 17 teet per minu The of new design is approximately expected double the currentto permit operation at a top speed design. 1 The design details which will permit this higher speed include j replacing the current metallic screen baskets with baskets
- constructed or fiber reinforced composite material (thus lowering weight and lowering insrtial loadings on seaeen
$ motive ! gearingsomponente),and controls and for thereplacing higher thespeeds. screen drive motors / 4 i i fabric with a new, smooth weave wire mesh spec ' ! designed to reduce grase " stapling" and thus permit more efficient detritus re:aaval from the screens by sprey water. The circulating water screen modifications are expected to be
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completed 1996 for the by other June 1995 unit. for one of the salem units and by June is constrained by the basket manufacturer.The schedule for this modificati underway to improve the installation date. Efforts are a + i j Upgraded and levelize trash rakesvelocity intake to improveprofiles trash rack cleaning effectiveness i i It is planned to replace the existing trash rakes with an ! improved "clamshella design to enhance trash rack cleaning i effectiveness and levelise intake velocity profiles. This will assist in precluding trash rack occlusion due to large
- debris and miso assist in precluding sudden screen detritus i
loadings due to release of accumulated debris. 4 t, This 2RS. modification is expected to be completed by the end of .. j 1
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d Upgraded screen wash pumps i
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i j upgraded materials and improved ability to accas traveling screen detritus (carryover ) i increase the reliability of these pum/carrythrough). ps, which are crucial This will to j traveling screen effectiveness. It is further planned to model the screen wash system to determine op 3 {
; of laprovements made.
The remaining six pumps will be replaced contingent on successful operation of the first two. j The and of two ptap ' modification is expected to be completed by the 2R8. ( e Redesigned spray wash headers a j
- the traveling screens to improve detritus handlingIt
! capabill. ties, which incluja spray nossle additions and I re-orientations, internal piping modifications, and new design j flap seals between the stationary and moving screen components. These modifloations are expected to be completed by June 1995
~~
4 { for one unit. of the salen units and by June 1996 for the other i { pending New Jersey Pollutant Discharge Elimination syste i A taska force from holistichas been initiated perspective 5 to analyze the Circulating Water system j Their charter includes a review of all
- people, and the environment. interfaces with the Circulating Watet' system, in j They will also review additional i engineered solutions, such as physical barriers in the river
! that there are various approaches being considered to improve, to the ensure l ability of the circulating Water System to mitigate marsh grass. l i Additionally, Intake is showing the density a decreasing of grass trend. loading at the Circulating Water The most recent data shows.a ? substantially lower density than was recorded trip. at the time of the plant The decreasing trend een be attributed to the and of the ! seasonal cycle, which is marked by a abange in transport mechanisms ! (ice, snow, rain, establinhaent wind) of new and intidal growth the patterns marshes.asTherefore, well as by the
- impact is expected to be over for 1994. the major i
i In addition to the planned enhancements, PSE&G is also conductinga ! number river. of studies to q'aantify and characterise the marsh grass in the i ! the movement of grams in the water column in front of the intakePsE&G structure. ! This study consists of a full-scale bathymetric survey i well as dailythat (sounding) extended nearfield surveys. 300 feet in front of the intake structure, as The daily surveys consist of S, i ' 1
g gy: 5-13-84 ; 13:01 PM LIC & PICR- 301 504 21b2;s30/3 soundings at transects of 5, 10, and 25 feet at the various tidal cycles movement. to determine the impact of plant operation and tides on grass Based to remove the marsh grass via dredging. on these daily surveys, PSEEG will determine the need I be reduced as grass loadings continue to diminish.The scope of this study will In addition, PSEsc is conducting a study to identify the factors that influence the occurrence of high grass loadings. The goal of these periods isoftocritical studias enable us to develop a predictive model to forecast loading. hydrological studies prepared for the intake structure.PSE4G is also reviewing th review, Based on this marsh grass further occurrences.studies will be considered to identify and mitigate the The com'oination of the upgrades that have been made to the Circulating Water System, the availability of operations and maintenance personnel to be assigned to the circulating Water Intake structure, the procedural enhancements and training, and the end of the seasonal cycle provide a measure of confidence in the Circulating Itater system's ability are implemented. to operate reliably until.2he longer tera design enhancements 1 1 i i
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- g. c-10-34 10.U1 , f"3CALI w&L. 6 KELr* OVA 0U4 s.AC/.e401/d; ATTAGNENT 5 ,
WORK PR&cTIcRS ; l PSE&G recognizes the vital role which properly performed work plays in the safe and reliable operation of its nuclear units. This document describes the work control processes in effect or under development at PSEEG's nuclear facilities. These processes ; provide assurance that our work activities presently meet or j exceed industry standards and will continue to improve. . PSEEG work control processes are defined in Nuclear Department ! Administrative Procedures (NAP) NC.NA-AP.23-0009(Q) Work control ! Process, NC.NA-AP.EE-0069(Q) unck eantent eaardinnelen, and NC.NA-AP.35-0015(Q) Safsty Tannina.Pronram. These procedures identify the actions to be followed to address . equipment problems. The process includes steps to perform the following: Problem identification operability determination Planning and scheduling Work package development . Removal of equipment from service Return of equipment to service operations approval to start raintenance work performance supervisor verification squipannt retest In order to continually improve the work practices at Sales, PSE&G Management is increasing its focus on the work control process. The following corrective actions have been or are being taken:
- The Vice President - Nuclear operations directed station managers and supervisors to increase in-plant and face-to-face supervisory contact tims. The increased supervisory -
presence will improve work monitoring and assessment, availability and socessibility of work direction and timely application of appropriate oorrective actions, if needed. PSE4,G is reinforcing field observation skills with all supervisors via en established work observation program.
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- The onsite safety moview Group has been assigned responsibility for reviewing outage schedules and performing qualitative Risk Assessment against procedurally-defined criteria.
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j p m. -*w wi - .w*- - - - - - - -- -= - - ~ .w. i l ): + As an interia enhancement, PSE&G has assigned middle-level i i management representatives with specialized technical skills ' to review and approve controls troubleshooting. These personnel, possessing proven technical ability in the controls area, review I&c troubleshooting plans before implementation. These reviews have resulted in improving j the quality and results of troubleshooting activities. i + i PSE&G is carefully reviewing the scope of future outages to 1 ensure that the station infrastructure required to support outage scope is sufficient to preclude schedule-induced ) pressures and to ensure adequate management oversight. i e i PSE&G intends to reduce the number of Plant Betterment & j Maintenance contractor firms from three to two. This will provide stronger oversight. In addition, PSE&G will direct craft supervisory personnel, responsible for complex installation packages, to arrive on-site prior to the outage. This will ensure that appropriate pre-job reviews are performed and organisational interfaces are defined. All craft personnel will esoaive additional training in PSE&G's safety tagging program. l 6 PSE6G is improving the focus of the station Planninq ! organisation by establishing separate groups for Unit 1 and j Unit 2. Further improvement will be achieved by j establishing separate Work control Centers for each unit.' The work control Centers are expected to be in place by the and of 1996.
- PSE&G has established a Work control High Impact Team for I
Outage support. This team's function is to l i i 1. Perform pre-outage work process reviews. These reviews i encompass wack package assembly and rev1wws, safety j tagging, and equipsant staging. 'l 2. Review the work control process. Specifically, they provide input to the process which identifies and controls the issuance of amargent work, work package { close out, safety tagging, and status of scheduling j updates. . i i 3. Review previous outage incidents for lessons learned from events related to the work standards, contractor control and work control process. i k 1 I
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gy g o-w oo . 6a ut . raum m a acu~ uvosua ao.. m i f . i i The actions stated above provide for a better focused organisation to oversee planned activities and emergent work. I In addition, PSESC Management will assess the effectiveness of the corrective actions via tracking and trending of personnel i error incident reports related to work control and field ] observation results. t ) A review of the performance indicators at sales show an improving i j trend. Beginning with 1990 and continuing through 1993, the following Salem 1 and 2 combined indicators confirm this j performance improvement: 3 1 1. Corrective work order Backlog decreased by approximately j 1000 work orders (50% reduction). ! 2. I Preventive Maintenance overdue Work orders decreased from I 610 to 37 (94% reduction). 1 1 3. { Total leaks at Sales decreased from 760 to 81 (894 reduction). . )
- 4. Unplanned Reactor trips decreased from 18 to 4 (784 reduction). ,
- 5. Licanese Event Reports decreased from 84 to 32 (624
, reduction). - ! 6. Personnel Error Licensee Event Reports decreased from 21 1
to 7 (674 reduction) . 1 PSE&G believes these indicators confirm an improving trend in 1 performance. The less-than-expected results for the last Sales i l Unit i refueling outage were due to the large scope of work and are considered an anomalous deviation from projected results. - 1 COHctBSION t i PSEEG has established a well-defined work control process. PSE&G } has developed programs for performance trending and review and
; for management oversight to cotatinually upgrade the work control
- process. We believe continued improvement will result from i communicating clear expectations to our workers and effective -
j monitoring / assessment by management personnel in the field to j provide reenforcement. - od es 4
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rnrre 2 ATEAMMENT 7 i ' n== ram x.-a-reawamm i As a result of lessons learned from the April 7,1994 event at i Unit implemented 1, operator retraining at Salen Unitand 1 and procedural
- 2. enhancements were
- outageoutage refueling of sufficient duration (but not later than th These changes are,: currently scheduled for October 1s, 1934).
l Belief valva (MS10) circuitry to aintaise challenges to th ! Steam signal toSafety reduce Valvesspurious (MSSVs), Engineeredand theSafetydampeningFeature of the steam flow I ESP) rapid closure of the turbine stop valves.actuations caused by com These actions are considered systems. enhancements to reduce cha11anges to the plant safety i During the nominal re-qualification cycle, operators are trained j in the the proper appropriateoperation responses of the MS10's. to 411 of these events, including i delays associated with the NS10 controllars. operators we ! automatio operation of the MSlo's credited in the safetySince there is no analysis, there is adequate time for the operators to respond appropriately. - i Fros a historical perspective normally generated following a,reactor a safetytrip. injection signal is not required acs temperature (Tave), remains above the 54 setpoint. experienced on April 7,one of the root causes of safety injection flow transmitters to pressure pulses generated by turbine valve 199 closure. ) the safety injection signal experienced on April 7,1994. The person procedural changes and management direction provided to the < operators via focused simulator training will provide appropriate compensatorycontrol. temperature sensures as related to downpower operations and Rc8 To further enhance shift crew response to potential plant transiente similar to the Unit 1 event, operators were given additional following areas: simulator training and written guidance in the - low power operations, control room resource management, and proper actions to be taken for Solid State protection System (SsPS) train disagreement. - The Melo design modification only affecte automatic operation. Automatic operation of the MS10's is not credited in the safety analyses, which assumes the Main Steam Safety Valves (MasV)
_ - - - - - . . . . - _ . - - . . . - - - .. _ ..--.- - _... _ - _-. _---.~.
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) . l . - ( , operate for overpressure protection. i discussed events, as as such part of the recovery actions from a number ofManual Melo loss of feedwater, loss of offsite power, outside the control room. break, loss of load, and shutdown from feeedline break, steamline i of an us10 is bounded by the analysis of Main steamAdditionally, the ina Depressurisation accidents, and the steam Generator (s/G) j pressureevent. Rupture is assumed to be controlled by the Masv's during a Tube l - t j The steam flow signal design modification reduces the effects of t process noise, thereby reducing the potential for inadvertent EsF system actuations. i The operational enhancements described above i i that transients remain within the limits of the plant safet analyses. Although thers design changes could be performed at power, psrso would not realise a. net safety gain by assuming the risk associated with work within thd' solid state Protection system racks. Therefore, delaying the implementation to an outage of sufficient duration outage, currently (but notfor scheduled later than the next refueling October ! 15, 1994) is appropriate. I l i ) J l l e
Enclosure Status of Msjor Issues Affecting Restad Activities at Salem-1 The following issues have been evaluated by NRC staff including (1) assessment of licensee l submittals dated April 25, April 29, May 10 and May 13,1994, (2) independent inspection of licensee activities and (3) discussion with appropriate licensee representatives. l i A. Equipment
- 1. Pressunzer Power Operated Relief Valve (PORV) Operability Issue: As a result of the initial safety injection on April 7, the reactor coolant system (RCS) filled with water. Without the normal pressurizer steam space to dampen pressure excursions, the continued injection from the first and second automatic safety injection actuations resulted in r-*M actuations of the PORVs to limit RCS pressure. As a result of the challenge to the PORVs, the NRC AIT questioned whether any damage to the valves had occurred.
PSE&G Response: The licensee removed the PORV internals for inspection. 'hhe l results of the licensee investigation showed that excessive wear was exhibited on the internals of one PORV and slight cracking on the internals of both PORVs. The licensee identified the source of the cracking at the boss used for the stem to plug interface in the valves to be intergranular stress corrosion cracking (IGSCC), compounded by the stress induced from the different thermal expansion characteristics of the valve internal materials. The cracking occurred where the stem of the valve, which was made of a 300-series stainless steel, was pinned through the boss to the plug of the valve, which was made of a 400-series stainless steel. PSE&G replaced the internal parts of the Unit 1 pressurizer power-operated relief valves (PORVs), IPR-1 and IPR-2, with new internals: a valve stem and plug made of 300-series stainless steel und a valve cage made of 17-4 pH stainless steel. The new stem and plug have essentially the same thermal expansion characteristics, which will relieve the stresses which contributed to the observed cracking. Further, a new design of the valve ,,,,. eliminates the boss used in the previous design and provides a more rigid stem to plug interface. Other factors that promote the IGSCC include the preload stresses that are applied when the valve internals are assembled by the manufacturer. In fact, similar
1 l ( i l l Status of Major Issues Affecting Restart Activities at Salem-1 (continued) l cracking, though not as prominent, was eNe:ved on other valve ! internals that the licensee maintained as new spares. ! Consequently, the licensee has initiated action to report this i apparent equipment defect in accordance with 10 CFR 21. i The licensee also modified the procedures used to assemble and i install the PORVs in order to prevent potential valve internal i misalignment. PSMG believed the udsalignment, which was due j to valve instalhtion technique, contributed to the scuffing and 1 galling observed on the valve internals after the evet. i NRC Followup: The NRC reviewed and diecineeswi with licensee engineering the f i results of vendor analysis of the affected PORVs. The inspectors i subsequently reviewed the PSMG design change package and ! accompanying 10CFR50.59 safety evaluation for the installation of the new valve internals 'Ihe iaeaaemars determined that the new material combination, which has been used in this application before, and the new installation procedure adequately resolve the PORV operability concerns. .
- 2. Pressurizer Safety Relief Valves Issue: As a result of the challenge to the PORVs dire =i above, the NRC AIT also questioned whether any damage to the safety valves had occurred.
PSMG Response: PSMG took ssps to assure the operability of the pressurizer safety relief valves (IPR-3, IPR-4 and IPR-5). These steps included visual ia=aardan. and non-destructive examination of the , valves and lift setpoint and seat leakage testing by a vendor, Wyle Laboratories. IPR-3 and IPR-5 tested satisfactorily. IPR-4 exhibited some seat leakage at 90% of the setpoint and lifted at a slightly higher setpoint. Wylelightly lapped the seat of the 1PR-4, adjusted the setpoint, and the valve retested satisfactorily. NRC Followup: 'Ihe NRC discussed the linaneaa test plan with PSMG engineering, reviewed the test results achieved by Wyle Labs, and ,. compared the performance of the IPR-3, IPR-4 and IPR-5 with cther comparable industry results. 'Ihe iaeaar'ars determined that PSMG's actions had been appropriate to assure that the pressurizer safety relief valves were operable prior to restart of Unit 1. . 2 e
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! Status of Major Issues Affectmg Restart Activities at Salem-1 (continued) 1
- 3. Pressurizer PORV and Safety Relief Valve Piping and Supports Issue: Following the Unit I trip, the pressurizer filled to a water solid
- condition, which resulted in operation of the PORVs and
. subsequent discharge of fluid from the pressurtzer to the j l pressurizer relief tank. 'Ihe rd cycling of the PORVs, and j the =MaH repeated discharge of fluid, prompted the NRC to )
- question the structural integrity of the affected PORV piping and ;
! supports. ! i 1
- PSE&G Response
- To assess the structural integrity of the PORV piping and supports, ,
i the licensee performed an engineering evaluation (S-1-RC-MEE- l L 0898) and several system walkdowns. The engineering evaluation l referenced numerous calculations, assessments, and additional l engineermg evaluations performed both prior to and following the event. The licensee's engineering analysis enveloped the effects on the system caused by the event. Based on system walkdown observations, the licensee concluded that there was no observable , l damage to piping or their supports due to the repeated discharge j
- of fluid through the PORVs. i t NRC Followup
- 'Ihe NRC reviewed the details.of the system walkdown, and the j
engineenng evaluation (S-1-RC-MEE-0898). Based on these j reviews, the NRC concluded that the questions on the structural i integrity of the affected PORV piping and supports had been adequately resolved. I 4. Steam Flow Transmitter Response to Turbine Trip 1 Issue: The initial Solid State Protection System (SSPS) actuation resulted l i from the coincidence of low RCS temperature (due to operator ! error) and a spurious high steam flow signal. Spurious high steam j flow signals were previously identified by the licensee, but their i
. cause had been attributed to a cc bination of the SSPS logic (a reactor trip automatically redu: 'e high steam flow setpoint from 110% to 40% of rated stes 41ow) and the actual decay in steam flow following a reactor-turbine trip. .
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E Status of Major Inues_ Affecting Restart Activities at Salem-1 (continued) i l t l PSE&G Response: Upon closer analysis following the event, PSE&G identified that
- tiae actual cause of the indicated high steam flow signal following
- a turbine trip corresponded to the pressure wave initiated by the
! closure of the turbine stop valves, that appeared to the main steam i flow transmirter as a short duration high steum flow condition. ! The licensee subsequently inelW a resistive-capacitive network ) l to decrease steam flow instrument sensitivity to short-duration l ! steam flow signals, while not paventing the instrument from
- properly sensing a true high steam flow condition. l l NRC Followup
- The NRC reviewed the licensee modification package and j concluded that the transmitter time delay circuit is an appropriate
! means of resolving the spurious steam signal phenomenon without l compromising the, safety function of the steam flow transmitter. ! I 1 5. Steam Flow Instrument Drift j Issue: Steam flow instrument calibration at Salem station has been known l to change with time [ drift] since initial plant operation. As a result, ! indicated steam flow, for the same power level, increases with time at power and decreases with time after a plant trip or shutdown. Periodic re<:alibration had been required to make ! indicated steam flow equal 100% at 100% power. This l phenomenon had caused, along with process noise, spurious l frequent tripping of steam flow bistables and logic input relays. ! Although this phenomena did not appear to play a direct role in the i event, probably due to recent Unit 1 modifications, the tdstoric frequent tripping of the birtable may have contributed to premature
- deterioration of the safety injection logic relays and the different l responses of the safety injection logic experienced during the i event.
i i PSE&G Response: 'Ihe licensee stated that the cause of the instrument drift was entrailed gases in sensing lines leading to the instruments. In l l order to correct this problem they have replaced the instrument ! sensing lines with larger tubing,' larger condensing pots, reoriented , j the lines to a consistent downward slope and' have removed ,. - insulation from sensing lines and condensing pots to promote condensadon and facilitate escape of noncondensible gasses. This modification was ipelW in Unit I during the last outage (Nov i '93-Feb '94] and will be installed at Unit 2 during the next outage j [Oct '94]. Results from operation at Unit I since startup have i 1 4
i . j Status of Major Issues Affecting Restart Activities at Salem-1 (continued) I been inconclusive, since the unit has not been maintained at full i power m any period sufficient to verify the dfectiveness of the j modifications. However, no rtH:ahbrations have been required , l since the modification was installed. Additional plant operating l time at full power will be needed to determme if the modification has been effective in reducing or eliminating the " drift". l i ! The licensee has a surveillance procedure in place to monitor j steam flow instrument calibration at both units. The procedure i includes acceptance criteria for identifying unacceptable drift and j identifies when recalibration should be accomplished. l The addition of the resistive-capacitive network to resolve the i reaction to short duration pressure pulses will also reduce the i sensitivity to piv0es noise signals as discussed in item 4 above. , ! l ! Licensee calculations show that calibration adjustments have not ! violated any technical specification requirements. j 2 ! The licensee ackncwledges the frequent tripping of the bistabl's, e i but believes there is insufficient data to support a cause/effect i relationship between spurious frequent tripping (chatter) of logic j relays and the difference in the logic trains' response during the ! event. ;
- 1 i
! NRC Followup: NRC staff has reviewed the licensee response concerning steam i i ficw instrument drift. The licensee provided detailed information i on their monitoring program and associated calibration adjustments that have been made to ensure steam flow set point values remain within technical specification required values. { 2 ! 'Ihe NRC staff concluded that the steam flow instrument drift should be minimized by the condensing pot and sensing line ) modifications installed at Unit I and planned for Unit 2. The
- procedure for monitoring steam flow instrument calibration has i been reviewed and found to be Wble.
l . s i j i l 1 4 W e-
i l i Status of Major Issues Affecting Restart Activities at Salem-1 (continued) f
'Ihere is not a prapaadaranca, of evidence to prove that there is a l
- nexus between steam flow instrument drift and associated input j relay chatter and apparent differences in steam flow safety l injection logic relays. The NRC staff has also concluded that the ,
- different responses of the "A" and "B" safety injection logic relays
- are explainable as normal variations in time response of these
{ relays. i l Installation of a resistance-capacitance circuit in the steam flow
- instrument measuring circuit should minimize the steam flow i instrument's sensitivity to short duration steam pressure pulses as well as pses noise. 'Ihis action appears acceptable.
j; Based on the licensee monitoring program in place to ensure l i instrument drift 30es not result in the violation of technical j specification limits, the safety function of the instrumentation will
- be assured.
i j 6. Solid State Protection System /High Steam Flow Input Relays , ; i l ! Issue: Following the reactor trip and initial automatic safety injection (SI) i of April 7, operators rameahari that only train A of the solid state ! protection system (SSPS) had actuated. Several actions controlled by SSPS train A also failed to go to completion resulting in several components not operating as v~i. The apparent disagreement between the SIlogic trains was not provided for in the EOPs, and i operator response to the event was delayed as they manually ! aligned the two trains and the affected components. i ! PSE&G Response: Due to the different responses of train'A and train B of the solid i state protection system (SSPS) to the event, PSE&G conducted ! further examination and testing of SSPS components. The licensee concluded that the very short duration of the high steam flow ] signal explained why only train A of SSPS initiated. Also, the i various components within a SSPS train are operated by different i latching and seal-in relays, that also have different response times. j 'Ihis fact, along with the short duration high steam flow signal, . 4 explains why not all actions of train A (main steam and feedwater ! isolation) went to completion. While the lictstsee testing showed
! a difference between the time response of the two SSPS trains and found discoloration in some SSPS relays, the licensee determined
{ i that both channels operated within the SSPS design and Technical l
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1 i . Status of Major Issues Affecting Restart Activities at Salem-1 (continued) Specification requirements. Further testing results confirmed that had an accident condition existed, both SSPS trains would have actuated and all actions would have gone to completion. The licensee nonetheless replaced the high steam flow iqut relays, and subsequent testing showed the differences between the channel time l responses had been reduced. PSE&G provided additional guidance to plant operators on manual actions to be taken in the event the two trains of SSPS respond differently. l l NRC Followup: The NRC staff monitored the licensee investigation, reviewed the initial test data, and observed portions of the licensee follow-up l testmg of the SSPS relays. The insgiuis determined that the licensee's root cause was acceptable. The staff also determined that the replacement of certain relays was prudent, and that the guidance provided to the operators was appropriate.
- 7. Main Steam Atmospheric Relief Valve (MS-10) Controller Issue: The MS-10s did not automatically respond to and control high steam generator pressure on April 7,1994. Following the plant trip and initial safety injection, the reactor coolant system (RCS) l temperature increased as a result of core decay heat and reactor 1 l coolant pump heat. This RCS heatup, and the ccisesponding i increase in steam generator pressures were not rwiw by the l
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Salem operators. Steam generator pressures increased above the setpoint of the atmospheric relief valves, because of a failure of the MS-10 controllers to promptly respond. Consequently, the steam generator code safety valve lifted. The steam release through the safety valve caused a cooldown of the reactor coolant l system. The cooldown of the RCS resulted in a rapid pressure i decrease that initiated the second automatic safety injection due to an actual low pressurizer pressure condition. PSE&G Response: During normal pisnt operation the MS-10 controllers provide a constant close signal to the valves since normal steam pressure is much lower than the valve opening setpoint. This results in the saturation of the controller circuitry. As a result, the automatic , ! opening of the valves is delayed during actual conditions of high l steam generator pressure by an amount of time it takes to clear the saturated condition. The controllers were modified shortly after initial startup of the Salem Unit to prevent inadvertent opening of MS-10. PSE&O has now implemented a design change to install t 7
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Status of Major Issues Affecting Restart Activities at Salem-1 (continued) a discharge path for the capacitor in the comrol circuit which was susceptible to the saturation phenomenon. This design change re-installed the part of the circuit which the licensee had previously removed. 'Ihe controller gain and reset times have also been changed to further improve the controller performance. NRC Followup: The NRC reviewed the design change package which implemented the changes in the MS-10 controller circuit, discussed the modification with licenene engineering, and concluded that the re-installation of the capacitor discharge path would provide better automatic control of steam generator pressure during transient plant conditions. Resident inspectors will observe licensee testing of this modification during plant heat-up.
- 8. Rod Control System Operation ,
i Issue: The rod control system was being operated in the manual mode l during the event due to ongoing system troubleshooting and operator uncerttinty with regard to the system operability in the automatic mode. If the system had been operated in the automatic mode the excessive reactor coolant system cooldown may have been minimized or avoided. I PSE&G Response: At the time of the event, the rod control system deficiencies had been resolved with the exception of munitoring a system isolator ! to determine if a drifting problem had been coris. tid. Final l system testing was scheduled the day of the event. Following the event, troubid --Ag determined that the automatic mode was fully operable. NRC Followup: 'Ihe AIT reviewed the results of the troublesiwoting and testing of the rod control system and determined that PSEAG had adequately corrected the system deficiencies to permit operation of the rod control system in the automatic mode.
- 9. Circulating Water Intake Issue: Marsh gr' ass accumulates in the Delaware River and is drawn into the circulatmg water system by the circulating water pumps.
When the grass quantities become large, it challenges the traveling screens' ability to remove the grass as fast as it accumulates, clogs the intake flow path and causes loss of cooling to the main 8
i i i l Status of Major Issues Affecting Restart Activities at Salem-1 (continued) i i condenser. Loss of cooling to the condenser requires reduction of l j plant load, or plant shutdown. j i i PSE&G Response: 'Ihe licensee's response is divided into short and long term actions, i In the short term the licensee has assigned maintenance and I operations personnel to the circulating water intake structure to ! maintain and clean the screens. Prior to the last refueling outage l the licensee installed low pressure headers to clear siltation and ! improve screen wash spray nozzle effectiveness. Screen wash control panels and instrumentation were replaced or refurbished. Procedural enhancements have been made since the event to give i operators more guidance on responses to an influx of marsh grass. Criteria for initiating a manual reactor and/or turbine trip have ' ! been included. The density of grass loading is currently showing ! a decreasing trend. 'Ihe major impact of marsh grass is expected , I to be over for 1994. l l Long term enhancements include modifications to the traveling i screens to permit higher speeds. 'Ihe higher screen speed will j increase the grass removal capability of the screens and lessen the probability of loss of circulating water flow due to gmss intrusion. i Higher speeds will be achieved by replacing the screen baskets i with lighter material and splacing f,he drive motors / gearing and i controls for higher speeds. 'Ihese modifications are expected to be ! completed by June 1995 for one Salem unit and by June 1996 for the other unit. 1 i In addition, the existing trzsh rakes, which are positioned in front of the screens, will be replaced to enhance trash rack cleaning and j levelize intake velocity profiles. This modification is expected to ' be completed in October 1994.
'Ihe licensee plans to replace two screen wash pumps [there are 4 l
per unit] with pumps of upgraded materials and lower maintenece requirements. 'Ihe licensee then intends to evaluate the screca wash system to determine optimal pump operating range, and to monitor the system effectiveness. 'Ihis modification is expected to , be completed in Octooer 1994. Pending the results of the experience with these two pumps, the remaining 6 pumps may be replaced with the new design. I l
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i I . l i 1 i Status of Major Issues Affecting Restart Activities at Salem-1 (continued) PSE&G plans to make othw modifications, including spray nozzle additions and re-orientations, internal piping modifications and new designed seals between statiocary and moving screen components , to improve grass handling capabilities. The implementation i schedule for these modificaticas has not been established. The licensee is also reviewing the circulating water system, the i grass movements and loadings, and will consider various l approaches, such as physical barriers in the river to improve the
- ability to mitigate marsh grass and renwval of grass by dredging.
l No schedule for completion of these studies has been provided. l NRC Followup: I.ong and short term plans for eqping with the grass problem have i been reviewed by the staff and diermand with the licensee. Loq ! term plans appenTto be aimed at coping with potentially severe !- grass intrusions. Each of the licensee's proposals appears to have j merit. The effectiveness of these modifications remain to be i demonstrated, The NRC has reviewed the licensee's procedures j and traimng of operators for coping with grass intrusions.
- Evaluation of these procedures is discussed below. Plant design l and the procedures that the licensee now has in place assure that l the loss of cirMativ water to the main condenser will not i challenge the safety of the mdear plant.
i ! B. Procedure Improvement.t
- 1. SC.OP-DD.ZZ-OD22(Z), " Control Room Reading Sheet Mode 5 Through 6" i
l Issue: Following the plant cooldown subsequent to the event, the NRC i identified the Salem Unit I reactor vessel level indication system l (RVLIS) indicated reactor vessel water level at 93%. When j questioned, the Salem control room operators could not explain the
- significance of the indication, nor were they required to monitor l this indication in the current plant operating moe.
PSE&G Response: RVLIS values are now logged when a unit is in Mode 5 (Cold 1 Shutdown) or Mede 6 (Refueling), and the procedure requires ^ i response' actions when the indicated level is below the minimum j value specified in the procedure. I, i i j 10
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0 Status of Major Issues Affecting Restart Activities at Salem-1 (continued) NRC Followup: De NRC staff reviewed the procedure change, discussed the change with Operations management, interviewed operators to assess their knowledge of the new requirements, and observed i operator training in the Salem simulator. The inspectors concluded l that action addressed the NRC-identified deficiency in Salem ! control room operator use and application of RVLIS indication j when the plant is in Mode 5 or 6. I
- 2. S1(2),OP-AB.COND 0001(Q), "1.oss of Condenser Vacuum" t
3 Issue: During the rapid downpower conducted by Salem Unit 1 operators
- imnwiintaly preceding the reactor trip, the operators took j extraordinary steps to attempt to keep the unit on line while j dealing with the ioss of circulating water pumps and main j condenser coolingi The NRC determined that a lack of procedural
! guidance existed for operators on when to trip the turbine and/or i reactor during low power operation.
- PSE&G Response: The procedure now specifies actions to trip the reactor and/or i turbine as a specific function of primary coolant temperature, i condenser vacuum, condenser back pressure, reactor power, and
! turbine power conditions. i NRC Followup: NRC reviewed the procedure change and noted that the specific l j guidance provided in the procedure now adequately directs l operators on what the necessary plant conditions are to remove - certain components from service. De inspectors confirmed . operator awareness of the new requirements through operator l interviews and through observation of simulator training on the j new procedure. 1 j 3. S1(2).OP-AB.CW-0001(Q), " Circulating Water System Malfunction" S1(2).OP-SO.CW 0001(Z), " Circulating Water Pump Operation" l Issue: The rapid downpower maneuver performed by Salem Unit 1 ' operators was necessitated by the rapid loss of the unit circulating
- water pumps due to river grass accumulation and the resultant loss .
l of main condenser cooling. De NRC determined that the i operators lacked procedural guidance on what specific actions were j required when dealing with the effects of river grass on circulating water pumps. 4 1 - I 11 t E
o Status of Majo_r Inues Affecting Restart Activities at Salem-1 (continued) l PSE&G Response: These procedures now specify operator actions for the condition ! when two or more circulating water pumps are out of service and identify actions for opereurs to take in the case of abnormal condenser vacuum situations. NRC Followup: The NRC reviewed the procedure change, assessed operator l knowledge of the new instructions, and observed their practice in ! the Salem simulator. De laWors determined that the new ' i ! procedures provide the proper guidance to the plant operators for the loss of circulating water pumps.
- 4. S1(2).OP-AB.TRB-0001(ry, " Turbine Trip Below P-9" Issue: During the April 7 downpower maneuver, Salem operators reduced reactor and turbine power at different rates. De resulting power mismatch resulted in the overcooling of the primary coolant system ,
I and the subsequent operator action to withdraw control rods, which l led to the reactor trip. He operators did not have guidance to l manually trip the turbine off-lins to restore primary coolant temperature. PSEAG Response: The turbine trip procedure now inwipuidas guidance for operator response to inadvertent or excessive primary coolant cooldown conditions when reactor power is belove the P-9 setpoint. The l procedure revision now includes specific direction to the operator to go to a new procedure attachment if at any time primary coolant temperature reaches 543 @w F or less; the Technical Specification minimum temperature kr criticality is $41 degrees F. The attachment provides direction to the operator to recover primary temperatung and if tunperature can not be maintained above the minimum tunperature for criticality, to manually trip the reactor. 1 l ( - W 4 12 e
j . . i i l y d j Status of Major issues Affecting Restart Activities at Salem-1 (continued) ] l NRC Followup: The NRC reviewed the procedure change and noted that the l i 39aw for operator action relative to a manual trip of the turbine } was appropriate and properly addressed the concerns of the event, j The inspectors subsequently verified, through interviews, adequate j operator knowledge of the new guidance and observed satisfactory
, performance of the new procedure at the Salem simulator.
i 5. Sl(2).OP-IO.ZZ-G004(Q), " Power Operation" [ Issue: 'Ihe power mismatch between the Salem Unit I reactor and turbine resulted in the ca.weling of the primary coolant system to the i i point where coolant temperature went below the minimum 4 temperature for criticality as specified in the unit Technical ! Specifications. 'Ihe operators did not have adequate procedure guidance for required action when plant opemtion did not meet the j Technical Specification requinment for minimum temperature for i criticality. r f ! PSE&G Response: De procedure for power operation of the Salem units now includes specific directions for maintaining primary coolant j temperature above the Technical Specification minimum i temperature for critical operations while performing a plant power 4 reduction. The body of the procedure directs the operator to a ! new procedure attachment if at any time during the power reduction primary coolant temym. airs reaches or goes below 543 ; {; degrees F; the allowed minimum temperature for critical operations is 541 degrees F. De attachment provides direction to l l l the operator to recover primary temperature, and if temperature can not be maintained above the minimum temperature for criticality, to manually trip the reactor. , i NRC Followup: De NRC reviewed the new guidance and specific direction provided in the procedure change for maintaining primary coolant temperature above the Technical Specification limit. The ! in.i,s.;urs conducted operator interviews and observed operator ; ~3 simulator training and concluded that the procedure change and operator training adequately addressed the issue. ,,,,. 4
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Status of Major Issues Affecting Restart Activities at Salem-1 (continued)
- 6. Emergency Operating Procedures (EOPs)
Issue: During the operator response to the reactor trip and multiple safety . injections, the operators encountered situadons where the EOPs did i i not provide specific guidance or direction. These situar:ons included: Resolution of solid state prr*W system logic train disagreement, Manual operation of the steam pnerator atmospheric relief l valves to contml steam generator pressure and primary l j coolant system (RCS) hestup, and l - Prevention *of solid RCS conditions and, if they do occur, l a plant cooldown under those conditions. l l PSE&G Response: PSE&G is pursuing long term C+ affecting the EOPs and ! Critical Safety Function Status Trees (CSFSTs), woriang in i l conjunction widi the Westinghouse Owners Group. In the interiin, the licensee has pmvided additional ga% concerning these ; situations to operators in an Operetions Deparmymt Information Directive (ID) and in a simulator training lesson plan which l addresses the entire eyesit. In response to the above situations, the ID provides guidance to operators on: when a safety injection train l disagreement is noted, to manually initiate a safety injection acturlion for the train that did not automatically acWate; following a reactor trip, to take manual control of the MS-10s at any time i steam generator pressuit is at or above the valve setpoint with no apparent valve motion; and, during EOP use afbr initiation of l CSFSTs, and if no higher path conditierwist, the Shift Technical Advisor is to refer to Yellow Path hedsstion Procedures to monitor RCS parameters and other indications in order to detect or prevent unexpected plant corditions, such as solid RCS conditions. l Reading, discussing and understanding the ID, and instruction using the simulator lesson plan were required of all licensed and non-licensed operators prior to their assuming a watch. ,. l i i 3 14 e
d 4 l Status of Major Issues Affecting Restart Activities at Salem-1 (continued) l NRC Followup: The NRC discussed the considered EOP changes with Salem Operations Department management, reviewed the guidance l provided in the department's ID and the simulator training lesson ) plan, and observed the training of operators using the lesson plan i at the simulator. 'Ihe inspectors verified operator knowledge of ! the new guidance through interviews of several operators from l different shift crews. 'Ihe inspectors concluded that the guidance i provided in the ID and the training provided at the simulator were i an effective means of resolving the evidenced EOP concerns. l C. Salem Operating Crew Shift Management Responsibilities i ! Issue: In addition to the above !dentified equipment and procedure issues, the NRC identified several areas in which Salem control room l operator perform *ance and resource management affected the j response to the' event. These areas included: l l . Control room crew communications, i l . Prioritization of personnel assignments and use of !, additional licensed operating personnel, and } ! - Scope of Senior Nuclear Shift Supervisor
- involvement in Emergency Operating Procedure j (EOP) operations, i
! . Event Notification and Communication PSE&G Response: The licensee responded to the above identified concerns by the l l issuance of a Salem LW Department Information Directive ] (ID) and simulator training lesson plan. Specifically, (1) operators received guidance relative to management's expectations on the l
- quality of communications as to clarity and directness, and the avoidance of vague or imprecise instructions or responses; (2) l i formal training and guidance were provided relative to the j management and control of operating personnel resources to assure that conservative actions are taken to either stabilize plant "
i j conditioris in a safe and controlled manner or manually trip the ! j reactor or turbine; the ID included g@= on whero to assign l j personnel when the rod control system is in " manual", and the acquisition of additional personnel for sigaificant off-normal i events; and (3) the Senior Nuclear Shift Supervisors role relative 1
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I Status of Major Issues Affecting Restart Activities at Salem-1 (continued) to plant events was clarified to maintain supervisory overview and ) not become engrossed or involved in assisting the crew with EOP implementation. All operating crews received the simulator traimng on the lesson plan derived fmm the event, and all shifts were required to read and understand the directions provided in the ID prior to resuming a watch. I Before entering mode 2, the licensee will establish interim guidance for all communicators and shift supervisors relative to 1 providing to the NRC fuller detail and explanation on significant events. Action to madify the emergency plan relative to I l procedures on event notificadon and communication will be initiated with all Involved agencies within the next seven days. NRC Followup: The NRC reviewed and iaW the above procedure changes and , training enhancements. The review included interviews with i licensed operators, disc =mians with Operations Management, and observation of crew training at the Salem simulator. The ingius concluded that the ds made to the noted procedures, the additional training supplied to licensed operators, and the guidance provided or planned by management to the operators would effectively address the personnel performance issues identified as a result of the event. l ) D. Unit 2 Consideration Issue: Considering the procedure &c , training and hardware modifications identified from the event for implementation at Unit 1, the NRC questioned what short and long term corrective actions were planned or being implemented at Unit 2. PSE&G Response: As a result of the event at Salem Unit 1, W. tor retraining and 1 procedural enhancements were implemented at Unit I and 2. Design modifications were performed at Unit I and are planned for Unit 2 no later than the next refueling outage, that begins October ,. 15, 1994. t
- Operators were given additional training and written guidance on response to marsh grast, dew..m and low power operations, RCS temperature control, control room resource management and l
16 o
Status of Major Issues Affecting Restart Activities at Salem-1 (continued) proper actions to be taken for solid state protection system train disagreement. Operators have been trained, prior to this event, on > how to cope with MS-10 controller malfunctions and how to operate the system in manual. They were given additional training on use of MS-10 valves to control main steam pressure following the event. , The Unit 2 PORV internals are of a different material,174 pH l stainless steel, than those at Unit 1. 'Ihe 17-4 pH internals are 1 l approved for this use by the vendor and are similar to those which l were installed in both Unit 1 and Unit 2 at the time of. initial l operation. Finally, the licensee has not experienced any problems ! i with this material to date, and believes continued use until the next , refueling outage igjustified. l 1
'Ihe licensee believes that delaying implementation of the hardware fixes to an outage of sufficient duration, but not later than the next refueling outage, currently sheduled for October 15,1994, is l w + iate. ,
l NRC Followup: 'Ihe NRC reviewed the 10CFR50.59 safety evaluation for continued operation with the Unit 2 PORVs in the as-is condition.
'Ihe NRC verified that the internals of the Unit 2 PORVs were l replaced with components made from 17-4 pH stainless steel. In addition, the NRC confirmed that the material changes for the internals were appsoved by the PORV vendor. 'Ihe PORVs will be inW and a design change considered during the next refueling outage. 7he Wars concluded that the Unit 2 PORVs are acceptable for continued operation of that unit.
'Ihe NRC staff has reviewed the planned modifications (MS-10 control circuit, and steam flow instrumentation configuration and
- circuit time delay) at Unit 2 and concluded that compensatory l measures provided by improved procedures and operator training are &_hle until the next outage of sufficient duration to install l the modificatens.
! ^
'Ihe inspectors have reviewed procedures and training related to coping with rapid power reluctions, use of reactor vessel level instrumentation, manual opwation of MS-10s, RCS temperature l
control, logic train disagreemeot, control of noncondensible gasses in the vessel and cooldown of a solid RCS. With these procedures i. 17 e
6 . { l i Status of Major Issues Affecting Restart Activities at Salem-1 (continued) ] l in place and the associated training completed, operation of Unit j 2 until October 15,1994 is considered acceptable. l E. Management Effectiveness in Resolving Long-Standing Problems Affecting Performance j at Salem Issue: Since the November 1991 Turbine-Generator failure event, which resulted in review by an Augmented Inspection Team, PSE&G has i continued to experience recurring operational, design, and ! maintenance-relased problems. Contributing causes to these ! occurrences have beat weaknesses in management and oversight i of activities, inadequate root cause analysis, failure to follow j procedures, personnel error, ineffective approach to resolution of i problems, and insufficient corrective actions. While none of the i events have advfreely affected public health and safety, the ! licensee's apparent inability to demonstrate improving performance j has been a continuing concern to the NRC. l ) j PSE&G Response: In their May 13, 1993, letter, PSE&G noted that they have established plans and completed actions relative to: (1) Salem Performance Lege.a.t; (2) Quality Assurance / Nuclear Safety l l Review Oversight; and (3) Augmented I%t Oversight. Prior to the event PSE&G management had already implemented significant material condition upgrades at Salem, including design changes that directly improved control room operations. Additionally, a Procedural Upgrade Program was completed in 1993. Although improving y fwn- + was indicated by the j reduced number of events caused by personnel error, the licensee rwamid that =rief=1ory performance had not yet been ! achieved. Cnamtly, the licensee commissioned a special j Ceegd.casive Assessmaat of Performance Team (CPAT) in the summer of 1993 to review and assess PSE&G's performance as j i indicated by the assessment of several deficient condidons and ! situations over the last few years. The CPAT activities are now completed and the results have been factored into the Nuclear l Department Tactical Plan (Plan). The Plan identifies the program ,,, I for implementing a comprehensive series of measures designed to I effect and assure performance improvement. 1
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i - l i , i t j Status of Major Issues Affecting Restart Activities at Salem-1 (continued) i Actions were also taken prior to the event relative to leadership l j imprenement, including organizational structure changes, , l reconstitution of the organization with more capable supervisors, j and establishing requirements for increased supervisory oversight
- activities in the plant. An additional operating engineer has been i l assigned to provide direct monitoring of the performance of ,
j supervisory persamel until all management enhancements are l ! completed. l 4 ! The management of Quality Assurance and Nuclear Safety Review & Oversight Groups has recently been changed to improve oversight j effectiveness. Other supervisory changes have been accomplished I to effect better overall performance. An LPt consultant ! has provided an , evaluation to assure the selection of properly l qualified y-wsg! for this area. Enhanced procedures and j policies for safety review, audits, assessments, and communications of findia-a were established prior to the event. ! Subsequent to the event and until the results of the CPAT effort i are established and the planned enhancements in organization, j personnel, and policy are completed, an Augmented Ladaaandent Oversight group was selected to maintain full oversight coverage i on all shifts, 7 days per week. De group has been directed to j monitor activities such as reactor startups and shutdowns, low
- power operations, special tests and surveillances, major system and maintenance evolutions, work control performance and control
{ room conduct, and shift turn-overs and planning meetings. 'The l individuals will provide daily feedback to the Manager of Nuclear Safety Review, and weekly feedback to the Vice President and 4 Chief Nuclear Officer. De Augmented Ladanaadaat Oversight coverage will be maintained until significant improvement are ll noted in station performance and in the quality of the Nuclear i Safety Review function. l t i Finally, the licensee has expressed confidence that these structural and personnel changes will povide the impetus and management l t attention necessary for significant and lasting impm ww.at. , , , . i NRC Followup: Previously, the NRC has mh 1 and assessed the licensee's ! CPAT effort. De CPAT was thorough and developed a ] comprehensive list of problems and weaknesses that appear to be causal to the recurrent failures noted in the licensee's performance. ; ! 19 l l 4 i . l
i I. , 4 Status of Major Issues Affecting Restart Activities at Salem-1 (continued) ]
'Ihe NRC has also reviewed the Nuclear Department Tactical Plan l
i widch identifies the action and perfonnance schedule to resolve ! cach generic problem or weakness identified. 'Ihe Plan appears j thorough in the appmach to resolution of the VMusses. 'Ihe j schedule, while extending into 1995 for some m the more difficult ! matters appears timely in view of the scope of the effort. NRC i has already noted aggressive action to reevaluate the quality and i performance of managers and supervisors in the Salem , ! organization. Several replacements have already occurred, } including the replacement of the previous General Manager-Salem j Operations with the current Vice President-Operations for PSE&G. l NRC has reviewed the credentials of the individuals assigned to < the Augmented Independent Oversight group. 'Iheir background, ! experience, and ability seem to be appropriate for the task at hand. l It is the Wh hatt the group will be successful in its i endeavor to monitor the quality of performance and provide the i necessary f=thack to the right level of management to assure ] effectiveness and management cognizance of the quality of operations. . ! While a positive trend has not yet been demonstrated in Salem i performance, the near-term and long-term actions initiated by the ! licensee appear to be sufficient to cause is.rova. cat if ! management maintains their commitment to the program. ; i l i l i 4 l
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g g imi BRitti$>tatES,TPOlatt ! I WAsMINGTON. Oc 20s10 080s May 11,1994 Mr. Ivan Selin - l Chairman l U.S. Nuclear Regulatory Commission i Washington, D.C. 20555
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Dear Chairman Selin:
I The Nuclear Regulatory Commission has evaluated the events that occurred at the Salem I nuclear facility on April 7 and I am very concerned that the Commission is moving too quickly to grant permission to restart the reactor. .
'Ihe system and human errors documented by the NRC cannot, in good conscience, be considered an aberration; indeed, they are all too familiar. The l
events of April 7 were simply the most recent in a long history of =hanical and management errors that are an ongoing threat to the people who live in Salem's shadow. In my review of the April 7. alert, I believe it is imperative that the re-start of the facility should be conditioned upon the NRC's assurances that all outstanding mechanical and management problems have been resolved and that a fine in the maximum amount will be levied upon the licensee. As the NRC and the Public Service Electric & Gas (PSE&O) describe it, the chain reaction of operator and system errors were triggered by cooling water intake valves becoming clogged by river grasses - a problem that apparently has exceeded the technical ability of the intake system. Plant records show that l clogging had occurred before. No action to prevent recunence had been taken, although the operators adopted their own rudamentary approach to the problem -- ! manually hosing grasses off the screens. As you are well aware, mechanical problems alone do not begin to address the deficiencies in Salem's ope:stion. Explanadons for vanous elements of the April 7 events - such as clogging intake valves, mkhnadi-d power levels, and vulnerabilities in safety injection systems - Ignore the root causes of Salem's abysmal record. f As the record shows, these root causes can only be described as the product The events of April 7, in of operator complacency bordering on incompetence. ! 3 MOSM *Wf W .- - ._- - _ .._ _ _ __ _ . - -
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sEN a1oes wlui + seisa41s72 m.m m ; Page 2 Mr. Ivan Selin 5/11/94 the context of Salem's problem-prone past, inexorably leads to this conclusion. For example, Instead of simply tripping the turbine, the technicians attempted a manual response to the reduced cooling water intake. They did not have ,
" confidence" in the automatic system. 'Ibe power level was taken too low, l causing a trip when it rose again. Safety injectors failed to woric as " expected," l responding at different times to the spurious signal created by the trip. l During the subsequent investigatipo of the shutdown, the NRC discovered a j I
radioactive gas bubble at the reactor vessel lead. l PSE&G has admined that it does not routinely monitor for the collection of gases in the reactor vessel head. 'Ihe operator had attributed the water dispWanent to "instrament error" but had made no effort to confirm whether that assumption was Wd correct. The NRC also found two pressure-relief valves with " higher-than-expected" wear. The valves, which control cooling water pressure in the reactor, are part of the safety system to prevent core overheating. If the valves had failed during the April 7 alert -- and the wea'r on them made that possible -- the reactor core could have overheated. A regional NRC official called the condition of the l ' valves "a very real threat'in this community." PSE&G has said only that the unexpected wear on the valves is the subject of an ongoing investigation. l In the context'of Salem's operating history, the most recent alert is truly i and deeply disturbing. ' System failures caused, or exacerbated, by operator and management failures characterize Salem's operating record. Four NRC Auf =74 Taytion Teams (AITs) have been sent to Salem in as many years.
'Ihe Commission has fined PSE&G for Salem violations 10 times since operations began 17 years ago. Most notably, NRC fined Salem 5850,000 in 1983 after Salem I's automatic shutdown system failed. 'Ihe NRC report on the incident found that " licensee management control and reactor trip system reliability" were implicated in the failure of the automatic shutdown system.
As recently as March 10 of this year, the NRC proposed to fine PSE&G l
$50,000 for violations of its license requirements regarding equipment maintenance. 'the Region I Administrator found that:
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l "These violations, in our view, are a direct result of continued i demonstrated wealmesses in perforrnance. of first line supervisors ! and middle management at the Salem facility and are of concem to ! the NRC. Collectively, the violations damaamated that e=1 mas **! l exist in the maintenance and control of work process activities, ! which could, under other circumstances, adversely affect the l operability of safety related equipment at the facility." + While these specific viointions wege not part of the April 7 events at Salem, l i they demonstrate the pervasive nunagement problems that characterize the ! facilities operations -- and, again, problems that have characterized operations at ' Salem for years. More than 20 other NRC findings of violations at Salem throughout its . I history have gg resulted in fines. Among those is the November,1991 explosion
- of the Salem II steam mrbine. The NRC concluded that the most '
l prominent causes of the explosion " involved personnel error, insufficient preventive maintenance and inadequate surveillance." As you will recall, the l NRC, over my objecdons, declined to impose fines because PSE&G reported the l l explosion and $75 million fire to the N'RC. j ~ : j In light of Salem's history of inadaan='a management; I reccomend that, at a minimum, the NRC addres_s the following concems: First, the extent of clogging problems and the adequacy of the current l
- system to handle intake demand and river grass clogging in the future must be resolved. If the system is deemed to be incapable of handling the river grass f problem, what are the technical solutions and when can they be implemented?
Second, the cause of the safety valve wear must be determined. An "on- ' going investigation" is not an adequate response to a problem of this magnitude, j Salem's record makes the promise of future vigilance particularly hollow. The community surraunAing the Salem plant, which includes my state of Delaware, is l entitled to a guarantee that the cause of this problem has been detennined and its j j recurrence has been prevented. , i Third, before the plant is restarted, the public needs to know if the NRC l can, and will, correct the pattem of management and system failures that are real dangers at Salem. Power should 'not be restored to the facility until the NRC can j l-
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l l Page 4 l Mr. Ivan Selin 5/11/94 restore public confidence in its ability to ensure safe operadons. l For more than a decade, I have sought expanded oversight, enforcement l and sanedons to make the Salem facility v'a according to the law. And while l l the NRC has rapa='~ny, documented the operator and system failures at Salem, ! the Commission has .never enforced sneaningful reform at the plant. Salem's record shows that the chronic problem of human error at all levels of operation has not been solved by the gaining and re-training pmgrams I undertaken by the udlity. The NRC m,ust ensure management reform by any and allmeans possible. Finally, I 'T 1 that the NRC impose the maximum fine allowable on l PSE&G. 'Ihe h J this incident, in the context of Salem's history, justify the i Commission's t.~y & Sgent response. After each incident at Salem, the NRC accepts the opersh .tssurances that significant reform of management and supervision has been undertaken. As the last event inevitably deman*ates, the same problems persist. In fact, the NRC prnmia*& in a letter to me dated May 13,1992, that it would " monitor the liscensee's efforts closely and would not hesitate to take any fu:ther actions appropriate to effect necessary changes in operations or attitude.'.' - I hope that you share my concems about the Salem facility. As the NRC is
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charged with protecting the public trust in regulating the operation of nuclear i facilities, I urge you to use all means at your diepa*=1t o pmvide the public with : l evidence ofinsaningful changes in Salem's operations and of the NRC's ability to ensure that the changes are not short-lived. Before I close,I would like to take this oppornmity to command the NRC staff for their responsiveness to my office in this matter. 'Ihe staff has been both cooperative and forthcoming when responding to our inquiries. My staff has spoken to NRC staff daily since the April 7 incident, enliminating in a three hour meeting in my Wilmington office with several NRC officials. IIcok forward to your response. ince ly, . I dl Joseph R. Bideri, Jr. L i - United States Senator
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_) / UNITED STATES n NUCLEAR REGULATORY COMMIMilON ' s j wAsMNGTON D.C.20055
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CHAMMAN The Honorable Joseph Biden, Jr. United States Senate Washington,.D.C. 20510 l
Dear Senator Biden:
i on behalf of the Commission, I am writing to you concerning the NRC staff's decision on the restart of the Salem Unit i nuclear facility. The commission shares your concerns about the past difficulties that the licensee has had in effecting improvements in performance over the past several years. The decision to authorize plant restart after an event such as the one at Salen on April 7, 1994, resides with the NRC staff. I i The factors the staff considered in reaching that decision are summarized in the enclosure to the May 14, 1994 letter to you. This enclosure also summarizes their evaluation of the technical issues you raised in your May 11, 1994 letter. j The NRC staff has also taken a number of actions due to the . concerns we have on Salem facility operations. For example, the j public meeting on May 6, 1994, was held specifically to ensure a a public airing of restart issues and licensee efforts to improve performance. Through the use of an Augmented Inspection Team j- (AIT), the staff has learned much about the technical problems leading to the April 7 event. Once the AIT's report is issued, the staff will determine what, if any, violations and enforcement i activities need to be pursued. The event itself will continue to ! be evaluated to identify any generic technical implications. The i NRC staff has established 24-hour per day on-site inspection , coverage during startup. The staff will also be evaluating I licensee performance to determine what additional special inspection activities may be necessary and appropriate at Salem. l Because of our concerns, and in order better to understand the I
- restart issues and the licensee's actions-to address them, the
! Commission took the extra step of holding.a public commission
- meeting with the licensee on May 9, 1994. During the meeting we 4 I
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{ heard directly from the licensee on recent personnel, organiza-tional, and managerial changes, some implemented prior to the event, and those staff about we also changes. received an independent assessment from our The Commission supports the NRC staff's decision concerning restart and is satisfied that the changes the licensee has made ! are well-founded; however, we will not be completely satisfied until those changes bear demonstrable and sustainable results. The Commission is monitoring the staff's activities at Salem. We will ensure that our and your concerns are addressed. l Sincerely, Ivan Salin i l I l l r
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j f %, j UNITED STATES G.)gh% 00$ j NUCLEAR REGULATORY COMMISSION g WASHINGTON. D.C. 20681H1001 July 5, 1994 i The Honorable Bill Bradley i United States Senator 1 Greentree Centre Suite 303 Marlton, New Jersey 08053
Dear Senator Bradley:
I as responding to the letter you sent to Richard L. Bangart on June 14 1994, asking the Nuclear Regulatory Commission to address concerns raised byiarie Wellerf ane of your constituents, regarding plant operation at the Salem Nuclear Generating Station. I understand your constituent's concern and thank you for giving us the opportunity to respond. I can assure you and your constituent that before any decision is made regarding the possible use of escalated enforcement, including civil penalties, for a given violation, the NRC will have already assessed the safety of continued or resumed operations to ensure adequate protection of the health and safety of the public. In the case of the recent events at Sah m, 4 before allowing the reactor to resume operation, the NRC staff reviewed licensee corrective actions to ensure that resumed operation would be safe. The NRC continues to hold Public Service Electric and Gas Company (PSE&G) i management accountable for the performance of the station and has taken - enforcement action on several occasions to emphasize the importance the NRC ! places on effective and safe operating practices, and the proper adherence to regulatory requirements. PSE&G has acted to restore, replace, redesign, or repair equipment or hardware that contributed to, or was a factor in, station 1 performance or operating practices that needed improvement. Supervisory and technical personnel in the Salem organization have also been reassigned or otherwise replaced in an effort to improve the performance of the station. ' PSE&G is continuing to review personnel effectiveness and is expected to make other personnel changes as necessary. The NRC Augmented Inspection Team review of the April 7,1994, event indicates that the public health and safety was not impacted. However, because of the i series of occurrences at Sales, the NRC is directing increased regulatory 4 attention on PSE&G's management, operation, and maintenance of the Salem facilities. 1 i
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2 The Honorable Bill Bradley l I want to assure you that the NRC staff will continue to closely monitor plant operations and will not hesitate to take any necessary regulatory actions. The NRC staff is currently assessing apparent violations of the regulations related to the April 7, 1994 event and will apply the NRC enforcement policy, as appropriate. On June 24, 1994, the NRC issued the inspection report on the April 7, 1994 event. A copy of the inspection report is enclosed. I trust this letter will satisfy your constituent's concerns. Sincerely,
./
QT a us M. T or ecutive irector for Operations ,
Enclosure:
Inspection Report l l l 1 I i 1
l July 6, 1994 The Honorable Bill Bradley l I want to assure you that the NRC staff will continue to closely monitor plant I operations and will not hesitate to take any necessary regulatory actions. l The NRC staff is currently assessing apparent violations of the regulations ! related to the April 7, 1994 event and will apply the NRC enforcement policy, 1 as appropriate. On June 24, 1994, the NRC issued the inspection report on the l April 7, 1994 event. A copy of the inspection report is enclosed. ) I trust this letter will satisfy your constituent's concerns. Sincerely, JanesM.Taylg6$081SWf Executive Dirgsjes'eA. Tap 0 f r Operations
Enclosure:
Inspection Report ; DISTRIBUTION: See next page
- PREVIOUS CONCURRENCE 0' m E LA:PDI-2, [ PE:PDI-to #ti:fAl-2 D:PDI-2 #
- TECH ED *DRP/RI kN I'Y ME H0'N) JZIm h : tic CMILLER RSANDERS EWENZINGER DATE h M /94 [a/30/94 o; -/2, /W94 6 /J./94 06/28/94 06/30/94 of f'u *ADRI *D:DRPE Abd_ .D/NRRA EDC OCA l WE JACALVO SVARGA RMAN 'M JTOLOR /[b DATE 06/30/94 06/30/94 I//4c/94 Tk[94 q/d/94 7 /0/9[
OFFICIAL RECORD COPY FILENAME: A:\SA101932.GlN
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/ w*'o , UNITED STATES y 3. {gg NUCLEAR REGULATORY COMMISSION 3 / 8 REGION i
* , 475 ALLENDALE MOAD
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KING OF PRUS$1A, PENNSYLVANIA 1s4061415 Docket Nos. 50-272 50-311 JN 2 4 994 EA No. 94-112 Mr. Steven E. Miltenberger Vice President and Chief Nuclear Officer Public Service Electric and Gas Company P. O. Box 236 Hancocks Bridge, New Jersey 08038
Dear Mr. Mil:
enberger:
SUBJECT:
NRC AUGMENTED INSPECTION TEAM (AIT) REPORT NOS. 50 272/94 80 AND 50 311/9480 The enclosed report refers to a special onsite review by an NRC Aug:nented Inspection Team (AIT) fmm April 8 thmugh April 26,1994. The team reviewed the cucumenances surroundmg the automatic reactor shutdown and two automatic actuations of the " safety injecnon" system that occurred at Salem Unit 1 on April 7,1994. The report discusses areas examined during the inspectica. De ineraedaa focus was on the potential safety significance of the events, and included detailed fact-finding, determination of root causes, and evaluation ofoperanonal and managenal y L. - =. Theinspecnon consisted of selective examination of pmcedures and representative reconis, observations, and interviews with personnel. The AIT determined that the predominant cause of the event was the combination of pre existing equipment problems or vulnerabilities and the resultant challenges to the operators, and operator errors that occurred during the traneimat Other failures and their causes were reviewed and are discussed in the metachad report. De AIT concluded that both the equipment problems and
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operator errors could, and should have been avoided by licsmama management through a closer review of the operator needs in resptase to the frequent and expoeted transient conditions resulting from the grass intrusions at the ciH-dag water structure. M De AIT found the liemanad operator respons?., the initiating event, a loss of cir-ladag water, was weak. Operators did not take some actions that they were trained to perform. However, overall operator response was sa:cessful in achieving r. stable plant condition; unfortunately, much later in the event sequence than expected, and too less to avoid a significant challenge to the pressurizer power operated relief and safety relief valves. While we note the actions of PSE&G to improve plant hardware and procedures prior to the event, both hardware deficiencies and inadequate procedures played key mies throughout the event sequence. Also, the actions taken by PSE&G before and during the event to mitigate the frequent grass intrusions at the Salem circulating water stmeture were both well conceived a A h t# W'
JLS4 2 A 1996 Mr. Steven E. Miltenberger 2 generally well performed. However, these initiatives were not accompanied by a similar review of task performance and procedural guidance in the control rooms to ensure that licensed ; operator response to the potential or actual loss of circulatmg water would also be successful. It is for these reasons that the NRC views the relatively poor perfonnance of the operating crew during the April 7,1994 event to indicate not just weak performance of certain licensed operators; but rather, and more impcrtantly, an inadequaes assessment by management of the prevalent operating conditions at the plant and subsequent development of an .yyivyriate operating philosophy to meet the expected needs. It is not the responsibility of an AIT to determine compth with NRC rules and regulanons or to recommend enforcement actions. 'Ihese aspects will be h@ followmg additional NRC management review of this report. A representative fmm the State of New Jersey, Department of Environmental Protection and j Energy (DEPE), observed parts of the onsite AIT inspeedon activities. A copy of a letteT from Mr. Anthony J. McMahon, Acting Assistant Director, Radianon Protection Element, NT DEPE l to NRC is enclosed with this letter. 'Ihat correspondence describes three issues not specifically addressed in the AIT report. Also enclosed is the NRC reply letter describing our plans to address those concerns. In accordance with 10 CFR 2.790 of the Commission's regulations, a copy of this letter and the enclosures will be placed in the NRC Public Document Room. We will gladly discuss any questions you have concerning this inspection. Sincerely, [ T. Wiggins, Act e Director Division of Reacior safety i
Enclosures:
- 1. Inspection Report Nos. 50-272/94-80
- 2. Letter, dated May 20,1994, f6 A. J. McMahon, NJ DEPE to J. T. Wiggins, NRC
- 3. Letter, dated June 24,1994, from J. T. Wiggins, NRC to A. J. McMahon, NI DEPE i
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JJN 2 4 996 Mr. Steven E. Miltenberger 3 cc w/encis: J. J. Hagan, Vice President-Operations / General Manager Salem Operations S. LaBruna. Vice Pmsident - Enginemng and Plant Betterment C. Schaefer, External Operations - Nuclear, Delmarva Power & Light Co. R. Hovey, General Manager - Hope Creek Operations F. hason, Manager, U-=ing and Regulation R. Swanson, General Manager - QA and Nuclear Safety Review J. Robb, Director, Joint Owner Affairs A. Tapert, Program Adeninimator R. Fryling, Jr., Esquire M. Wetterhahn, Esquire P. J. Curham, Manager, Joint Generation Departmera i Atlantic Electric Company Consumer Advocate, Offim of Ccesumer Advocate William Conklin, Public Safety Consultant, Iower Alloways Creek Township K. Abraham, PAO (2) Public Document Room (PDR) local Public Document Room (Li'DR) Nuclear Safety Informadon Center (NSIC) NRC Resident Inspector State of New Jersey D. Davis H.-Otto, State of Delaware, Departmant of Natural Resources & Environmental Control f I ; l l i l l I
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Mr. Steven E. Miltenberger 4 JUN P 4 Igga bec w/encis: The Chairman Commissioner Rogers Commissio::er Remick Commis-Joner de Planque J. Taylor, EDO J. T:fmt. OEDO W. Dean, OEDO J. Saxn, NRR S. Dembek, NRR C. Miller, PDI-2, NRR J. Wrmiel, NiiR A. Thadani, NRR J. Calvo, NRR R. Jones, NRR W. Russell, NRR I. Ahmed, NRR H. Rathbun, NRR W. Lyon, NRR A. Chaffee, ,VRR/ DORS /EAB M. Callahr.n, OCA J. Kauffman, AEOD E. Jordan, AEOD M. Hodges, RES P. Lewis, Research M. McCormick-Barger,, RIII At% Paul Bochnert, Chairman, ACRS Ken Raglin, Technical Training Center DCD (OWFN PI-37) (Dist. Code #1E10) INPO T. Martin, RA W. Kane, DRA J. Wiggins, DRS R. Blough, DRS E. Kelly, DRS W. f 2nning, DRP J. Durr, DRP R. Summers, DRP S. Barr, DRP L. Scholl, DRP R. Skokowski, DRS J. Stewart, DRS D. Holody, EO E. Wenzinger, DRP J. White, DRP C. Marschall, SRI - Salem Resident Inspector, IP2 Region I Docket Room (with concurrences)
1 U. S. NUCLEAR REGUIATORY COMMISSION REGION I REPORT / DOCKET NOS. 50-272/94-80 50 311/94-80 LICENSE NOS. DPR-70 DPR-75 UCENSEE: Public Service Electric and Gas Company P.O. Box 236 N-hs Bridse, New sermy 0803: 1 FACILITY: Salem Nuclear Generating Station INSPECTION DATES: April 8-26,1994 INSPECTORS: Stephen Barr, Resident Inspector, Salem. DRP (Asst. Team IAnder) J. Scott Stewart, Examiner, DRS i Iqbal Ahmed, Senior Electrical 5=i -- , NRR i Wanen Lyon, Senior Reactor Systems Engineer, NRR John Kauffrnan, Senior Reactor Systems "=p=-x, AEOD I.arry Schou, Reactor Engineer, DRP
- Richard Skokowsid, Reactor Engineer, DRS i Howard Rathbun, NRR Intern ;
STATE OBSERVER: Richard Pinney, New 1ersef Department of Environmental Protection and Energy TEAM LEADER: b- A (e[3bi[ R.1 inminers, w a.e- daw , lects Branch 2, DRP APPROVED BY: V - 0 I/ James T. Wiggins, Acti$Mrector Date Division of Reactor Safety . j
'i f'fP,
l EXECUTIVE
SUMMARY
j Areas Inspectad: An Augmented Inspection Team (AIT), catsisting of personnel from Region I ' AEOD and NRR, inspected those areas necessary to ascertain the facts and determine probable causes of the automatic reactor shutdown and multiple automatic initiations of the safety injection system that occurred on April 7,1994. 'Ihe team assessed the safety significance of the event, including the resultant plant operation with a water (liquid) filled pressurizer and its chaltaage to the pnmary coolant boundary integrity and the potential vulnerability of the ultimate heat sink to the same marsh grass intrusions that eh=11= ad the plant nonnal heat sink, which was the initiating event for the sequence of events on April 7. 'Ihe adequacy of the licensass design, l maintaamace and troubleshooting practices relative to the safety igjection system was reviewed. 7he possibility for any potential generic implicariana posed by the Salem svent was assessed. Esadla: 'Ihe Augmented Taaaaedaa Team (AIT) hd,i,M a sequence of events detailing the circumstances sunnuadia: a Salem Unit 1 plant trip and a series of safety injoetion system actuations. Tt was found that the events tai to the loss of the pressurizer steam bubble and the normal reacter coolant system pressure control system, and an Alert declaration. 'Ihe AIT noted through an evei.' sequence and causal factor analysis that the root causes of key events generally included a combination of component failure and human error. Additional procedural guidance for, and prioritization of work activities of control room operators would have resulted in a, better responte to the event. 'Ihe AIT found in general that the licensee response to the almost daily event of grass clogging of the ciciadag water screens was very well planned and i coordianted for the additional workload at the cirealadag water structure. However, as indicated l by the performance of personnel and eqWe in response to the April 7 event, the licensee l did not adequately plan for, and coordinate, the activities corresponding to the additional l workload in the control room resulting from the same event. 1 Finally, even though some equipment and licanead operators performed poorly during the ensuing transient on April 7, the core and its primary protective barriers were maintained throughout the event. In addition, the following conclusions were developed as a result of the AIT review and discussed at a public exit meeting held on April 26,1994: Summarv of concIn.iaa : l
- 1. No abnormal releases of radiation to the enviraanwat occuned during the event (Section 3.4).
- 2. 'Ibe April 7,1994 event challenged the RCS pressure boundary resulting in multiple, successful operations of the pressurizer power vaated relief valves and no operations of the pressunzer safety valves (Section 3.I al .
- 3. Operator errors usurrM which complicated tiid14ent (Section 4).
l H
EXECURVE
SUMMARY
(CONT'D)
- 4. Management allowed equipment problems to exist that made operations difficult for plant operators (Sectice 7.2).
- 5. Some equipment was degrated by the event, but overall, the plant performed as designed (Section 3).
- 6. Operator use of emergency procedurus was good. However, pWiiM ictdequacies were noted with other operating procedures (Section 4). l
- 7. Licensee's investigations and troubleshooting efforts were good (Section 5).
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TABLE OF CONTENTS EXECUTIVE
SUMMARY
..................................... ii EXECUTIVE
SUMMARY
(CONT'D) ...............................iii TABLE OF CONTENTS .......................................iv
1.0 INTRODUCTION
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 l 1.1 Event Overview .................................... I 1.2 Augmented Inspection Team Activities . . . . . . . . . . . . . . . . . . . . . . 1 2.0 GENERAL SEQUENCE OF EVENTS .......................... 2 3.0 PLANT RESPONSE TO EVENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 3.1 Soud State Protection Symem (SSPS) Response . . . . . . . . . . . . . . . . . 4 3.2 Pressurizer PORVs, Safety Valves & Associated Pipe . . . . . . . . . . . . . 7 3.3 Circulating and Service Waer Systems . . . . . . . . . . . ..,...... 13 3.4 Reactor Systems Respouse . . . . . . . . . . . . . . . . . . . ......... 16 3.5 Atmospheric Steam Dump Valves and Steam Generator Safety Valves . . 21 4.0 PLANT OPERATOR PERFORMANCE & PROCEDURE ISSUES . . . . . . . . 21 4.1 Operator Response Prior to the Plant Tsip . . . . . . . . . . . . . . . . . . . 22 4.2 Operator Response Following the Plant Trip and Safety Injections .... 25 4.3 Procedum Adequacy and Usa . . . . . . . . . . . . . . . . . .. . . . . . . . . . 28 4.4 Event Classificanon & Nodfications . . . . . . . . . . . . . . . . . . . . . . . 30 :
4.5 Simulator Demonstration .................................. 30 4.6 Reactor Vessel I.4 vel Indication System (RYLIS) Monitoring . . . . . . . . 30 4.7 Operations Concksions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 5.0 EVALUATION OF TROUBL.ESHOOTING ACTIVITIES ........ .... 34 t 6.0 OTHER FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 7.0 SAFETY SIGNIFICANCE AND AIT CONCLUSIONS . . . . . . . . . . . . . . . 42 7.1 Ssfety $lgeifw ................................. 42 7.2 AIT Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . 43 8.0 EXIT MEETING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ,, . . . 49 ATTACHMERT 1 - AIT Charter ATTACHMENT 2 - Sa'.ety hjection System Logic Diagram ATTACHMENT 3 - feefisw a,iy Action Letter ATTACHMENT 4 - Sequence of Events ATTACHMENT 5 - Acronyms. ATTACHMENT 6 - 2xit Meeting Attendees ATTACHMENT 7 - Figures IV
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DETAILS 1.0 EiTRODUCTION 1.1 Event Overview On April 7,1994, operators at Salem Unit I were operating that unit at 73% power. De plant was at a redu:ed power level due to the miuctions of cor*aws cooling efficiency resulting j from the problems river grass had been causing at the unit's condenser circulating water (CW) ! intake structure. Shardy aMar 10:00 a.m. that morning, a severe grass intrusioc occurred at the l intaka structure, and nuny of the Unit 1 CW pumps began to trip. Operators consequently began to reduce plant power in order to take the unit turbine offline. As a result of operator i error and equipment ccimptiemelaae, a Unit I reactor trip and automatic afety injecdon occuned ! at 10:47 a.m., and a subsequent secued automatic safety indection occuned at 11:36 a.m. De l subsequent sequence of events resuland in the Unit 1 primary coolant system S!!ing, resulting l
- in a loss of1.ormal pressuriser pressure control at normal opemeing temperature and pressure. l l De licersos declared an Unusual Event and subsequendy an Alert condition at the unit. I
- De events of April 7, from the initiating doampower transient to the ensuing reactor trip and j safety irdections, were cornplex and involved a combination of giwi errors and equipment failures. ;
] ! 1.2 Augmented Inspection Team Activities l j & April 7 1994, p senior NRC raanagers determined that an AIT was warranted to gather i infortnation on the plant trip cod subsequent safety ht}octica system men =*iane at Salem Unit t. De ATT was initiated because of'the complexity of abs events, the uncertainty of the root causes of some of the condidons and equipment probleem that had been encountered during the events, and possible generic implientinas A charter was formulated for the AIT and transmitted to the ts;am on April 8,1994 (Atemenmaat 1). De NRC Region I Regional Adminianator. dispatched the AIT carly on April 8,1994. De AIT met with PSE&G management and staff regarding the facts known at that time for the April 7 event. , On April 8,1994, NRC Region Iissued a confirmaaory ac@n letter (CAL) Osat 4acumented the verbal commitments made by the llanaean to the NRC regarding the control (4 activities for equipment that fhiled to operate properly during the event, PSE&O sgport of the terin inspection acdvities and the subsequent restart of the unit. De CAL is enclosed as Attachment 3. De team completed initial inspeedon activides on April 15,1994. Addirlans1 onsite iaeamion was conducted on April 17, 20 and 21,1994, to perfonn additional operator interviews and to review tlie results of ongoing troublesnooting and testing activities. De work directed by the , AIT charter was completed and a public la-i+ -1 exit meeting was held on April 26,1994. The AIT participated in two congresskmal staff briefings, a public NRC and PSEAG
. - ~ _ . _ _ _ _ . . _ _ . _ _ _ _ __.._ _ _ _ _._ _ ___ _ _ _ _ _ _ . _ . _ _ _
t s 1 i 2 l j managtment meeting on May 6,1994 and an NRC Comminioners' briefing on May 11,1994. j he A1T provided information/ findings to NRC Region I for use in developing the issues j warranting corrective action or further analysis prior to restart of Unit 1. i j 2.0 GENERAL SEQUENCE OF EVENTS a j On April 7,1994, prior to the reactor trip and safety iejection events, Salem Unit 1 was
- operating at approximately 73% power. Operators were operating the plant at less than full
] power due to the effect marsh grass in the Delaware River was having on the Salem units' { cix2 M=5 water (CW) systems. Over the course of late winter and early spring, heavy 1 accanulations of the river grass at the CW structure were clogging the CW system travelling
- screens which protect the CW pumps from river debris.
! No: .c ... j By apprmimaanly 10:302t.as. on April 7, the power level at Unit 1 had been decreased to about 60 % power as a result of an increase in candaneer back pressure due to river grass interfering l j with the travelling screens at the CW structure. In response to the approaching loss of CW,
- Unit 1 operators began a unit load reduction at 15 power per minute. From 10
- 15 a.m to 10:40 j a.m., several of the Unit 1 CW travelling screens clogged with grass and caused the
- corm
- w= diag CW pump to trip off line. Operators anesepted to restore the pumps as they j tripped, but by 10:39 a.m. only one CW pump was available. As the CW pumps were lost from
! sernce, opemtors increased the rate of the downpower maneuver from 1% to 3% to 5% to i eventually 85 per minute. As the operator raepaaeihls for controlling tubine power reduced j the unit load, the operator responable for reactor power correspondingly reduced reactor power j by L Gg the reactor control rods and by boration. . 1 l Initially, during the downpower maneuver, operators reduced turbine power ahead of reactor ? power, and the resulting power mismatch caused slighdy higher than normal temperature for the primary eaalmat system. At about 10:43 a.m., the Nuclear ShiA Supervisor (NSS) directed the i operator controlling rencear power to go ao the electrical distribution control panel to begm j shifting plant electrical loads to offsite power sources. At that time the control room crew ! members believed the plant was stable; however, they failed to r-l= that reactor power was j still decreasing due to the delayed effect of a boron addition that had been made. This led to i revenal of the power mismatch and a decreasing T., At 10:45 a.m., the NSS identified the l i r=demat overw:coling aandI*ian, went to the rencear control penal and began withdrawing control l rods to raise coolant temperature, and then turned over control once again to the onginal { operator. His operater continued to withdraw the control rods, and reactor power increased j from apprmimaanly 75 to 25% of full reactor power. Since power dropped below 10% power,
- . the power range "high neutree flux-low setpoint" trip had automatically reinstated, establistung i 255 reactor powe as the automatic resceor trip seapoint. When reactor power reached the 25 %
setpoint, at apprurimanely 10:47 a.m., the reactor autamariestly tripped. I ! Almost immediately following the reactor trip, an automatic safety injection (SI) =a*W. De
- SI was initiated only on Train A of the SI logic on high steam fi m coincident with low primary j
coolant T . Although the operators did not recognize it at the time, the licensee later i r
i j l 3 determined that the high steam fkm si',nal was a nault of a pressee wave cuated in the main j steam lines by the closing of the turuh'e stop valves when the tubins automadcally tripped. In l response to the reactor trip and SI, the cperators emessed Emergency Operating Psocedure (BOP) ! EOP-Trip 1 at 10:49 a.m. Due to the nature of the initiating signal, the SI actuation did not ! successfully position all necessary components to the =:=*=d, post-actuation position, and the ) operators, as part of EOP performance, maniially repostioned affected components. At 11:00 a.m., the tiemaeae declared an Unusual Event based on a " manual or ma*=aane emergency core j 4 cooling system arvundna with a discharge to the vessel." During further performance of the j f .OP, operators had to reest the SI logic, and it was at this point that they realised that Train B i of the SI logic had not actuated and that there was thus an appannt logic disagreement. j As the operators were performing the required EOP steps, the primary coolant system continued to heat up due to decay heat and running the reactor coolant pumps. As the primary heated up, l steam generator pressure consequently increased, and because of pre existing problems with the q steam genemsor arvaanpharic relief valve (MS10) =*=aade control, steam generator pressure ! was not properly controlled by *hese valves. Concurrently, dus to primary heatup and the volume of water added by the SI, the pressuriser filled to solid or near solid conditions, and the 3 pressuruer pouw operated relief valves (PORVs) periodically =*=aadantly opened to control 4 prunary pressure. Shortly before 11:26 a.m., steam generator pressus increased to the ASME i code safety valve lift seapoint in the Number 11 and/or 13 seems generator (s). 'Ibe opsming of 1 the safety valve caused a rapid cooklown of the primary coolant system, and due to the solid ,
- water stans of that system, a aaineWat rapid decrease in primary sysemes pressure. At 11
- 26 j a.m., primary pressure reached the ai*=aade SI setpoint of 1755 peig, and sinos Train B of the 1 SI logic remained armed, a second mi*=aada SI was actuated by that train of logic. Operators
,! had also Warinad the decessing primary pressus and manually initiated SI moments after the
- automatic initiation.
1 l 2 Following the second SI, operators remained in das BOP network and pursued stabilizing plant I conditions. At 11:49 a.m., the pressuriser relief tank (PRT) nipture disk ruptmed to relieve the ! incnasing tank pnesse which resuhed from tbs vahuns of primary inventory relieved to the i PRT. At this point, the operators were fhood with cooling down tbs plant from nonnat operating
- temperstme and presses without having a steam bubbis in the presuriser to contml primary passmo during the transient. Onos the BCCS isdection was tenninneed, operators controlled l plant pasare atuough a aasahiandan of charging and landown using tbs chemkal and volume j control system. At 1:16 p.m., liaaaeaa management deciered an Alert under Section 17.B.
j " Precautionary Stan6y,' of the Salem Bvent Classification Guids. The licenses decision to
- voluntarily entar this Emergency Activation IAvel was made in onier to asgas the activation of the Salem Tarhair=1 Support Center (TSC) to pnwide the Salem operators with any technical
' ne.iermace that would be required as they cooled down the plant. By 2:10 p.m., the 'ISC had been fully staffed, and at 3:11 p.m., the operators restored a bubble in the pnaariner. . l i j . j i .i 4
, . ~ _ - - . - . - . - - - N l i i } 4 i ! At 4:30 p.m., operators restoral pressurizer level to the normal band and returned level contml l to automatic. 'Ihe operators subsequently exited the EOPs and used integrated operadng l puxadures to cool the plant down to Mode A (Hot Shusdown), which was achieved at 1:06 a.m.
- on April 8, and then to Mode 5 (Cold Shutdown), whicit was achieved at 11
- 24 a.m. on the j same day.
i A detailed sequence of events is provided in Anachawat 4. ) 3.0 PLANT RESPONSE 'IO EVENT l 3.1 Sopd State Praeacelaa Systan (SSPS) Response i 3.1.1 SSPS Desedptism
'Ibe fuocoon of the reactor pranar+ian system is to sense an approach to unsafe raadseians within j the reactor plant and then initiate automatic actions to protect the nector fusi, the reactor coolant i system and the primary comeninnunt fmm damage. A block diagram of the system logic is given in Anar4inwat 2. Process sensors monitor various plant condmons and provide an output to the system bisables. When a trip setpoint is exceeded the bistable doenergiaan its maaaei=aad input
' relays which then provide an input to the solid state logic cucuitry. %e solid state logic pmceases the various inputs, determines if an unsafe condition is being appmached and, when appropnate, actuates the output relays to cause a protecove action. 'the protective action may j be a reactor trip or the actuanon of the safeguards equipment. As shown in the block diagram, _ each channel bastable cas.tmis a relay in both Protection Systent Trains A and IL 'Ihe two protection trains have identiail fhactions to anmus that is the event of a falhus of can train the automatic protection actions will tm. ensured. Another design feature of the systen is that, once initiated, a protective acnon shall go to completion. This festme is achieved by various means for the different safeguards equipment. In some cases relays within the solid state protection system electrically seal in and thereby ensure the preesceive action aaael==== to completion regan11ess of the duration of the signal. For sorne P this feness is waaTH M by
=apaaane= and circuitry downstream of the solid maae pecesction sysean circuitry. Por example the main steam iaalatian valve closuse (MSIV) dos is " sealed-in" when aanylatching relay, within the MSIV contal circuitry, is released by the assion of a solid sess protection system buner relay. For these cosaponents, the durados of the input signal must last long enough for the leeching relays to acanes.
Symam Actuation I.agic
'Ibe protecnico system is designed such that the failure of a single component cannot prevent a desired automanc protective action fmm occurring. Likewise, the design ensures that a single component failure cannot cause an unnecessary system ar+uariaa 'Ibese design otiectives are i accomphshed by having multiple instrumentanon channels and redundant protection trains. A l vital component of the protecnon trams is the solid state logic. 'this logic ensures that more than one instrumentation channel is sensing an unsafe condition; however, it does not require l l
I 1 I l
l 4 l t . ! 5 l all channels to initiate a protective action. For example, to protect the plant from the effects of
- a main steam line break accidet, the protective system monitors differential pressures from i which main steam line flow rates may be inferred, unain steam line pressures and the average l l reactor coolant temperature (T ). One of the enadniaan required to cause a protective action !
i is the coincident
- ries ==w* of both:
i ! 1. High steam flow in two of the four main seena lines. (Esch steun line has two flow ! instrumants with an manacianswi bistabia. 'the logic considers s6 sam flow in a particular ! ! steun line to be high if one of the two bistables are tripped.)
- and, i 2. Low T., condition on two of four reactor coolant system loop temperature instmment l channale; ag' low steam line pressure on two of the four main steam line pressure
- ch=nels.
i j When this logic is satis 5ed the protective actions that are initiated are the iaaladaa of the main steam lines and a safety injeccon. The safety igjection logic then results in closure of the feedwater control and bypass valves, main feedwater isolation, trip of the feedwater pump i turbines, realignment of various system valves and dampers and actuation of the safeguards i equipment control systems (e.g. safety injection pump and emagency diesel generator startug). ;
'Ihe solid state logic processes the various systern inputs in a similar manner as necessary to generate the appropriate protective action based on the particular accident analysia. ;
j . 3 Some of the safeguards equipment receives actuation signals from both protecdon trains (e.g. l
- emergency core cooling pumps, emergency diesel generators). Other equipment (anasienng
- mostly of train specific safety injection system valves) receive actuation signals froen only one i of the protection trains. The system design is such that the components that are actuated from i a single train alone, result in completing the saisty function. 'Iberefore, a single logic system j failure will not result in a total loss of mfaty function.
} When the solid stats logic guarates a protective action signal one of two actions occur. For a j j reactor trip the undervoltage coils of the renesor trip circuit brunkers are doenergland directly
- by the solid sans logic chouits. Por an of en amor poesceve andons,.the solid stase logic j circuits control the operation of a masser seiay in the Safeguards Equipment Cabinet. Depending i on the number of relay contacts that are needed to maansartish a preenctive function, additional slave and buffer relays are n'ilimad 'Ibe slave relays are contmund by a master relay and buffer relays by a slave relay. Some of the control cirasits use additional control relays in the operation of the safeguards equiament, as diacunaad previously. For the MSIV system, each la'ehias relay, once actuated, operates aalanaid valves that cause individual MSIVs to close.
'!he resuhant effect is that for the MSIV: the series operation of a masser, slave, buffer and latching relay is required before tim protective action, generated by the SSPS logic, is assured of going to completion.
i i
i ,i 6 3.1.2 SSPS Response During the Event
- During the plant transient that occuned on Salem Unit 1 on Apnl 7,1994, the solid state i protecnon system responded to a sustained low T., anadidan and aniacidaat short durahan high l l
steam flow indratiana. 1he low T., condition was a result of actual plant anaditions . expc.-ienced during the rapid plant power reduccon. The short duration high awarn flow signals i occuned followmg the main turbine trip, These high seesa fkw signals were not the result of ! an actual high steam flow aandidan resulang from a postulated steam line break; but rather, I were caused by a pressure wave in the main steam lines that occurs when the turbine stop valves rapidly close during a tubine trip.
- Hieh Steam Flow Sieaal Annivnin j . .x .
j 1he team reviewed PSEAB1 analysis of the high secam flow signal menacineswi with the initial i safety injection on April 7,"1994. At Salem Generatmg Station the steam flow in each main steam line is determined by measunng the pressure difference across the steam line flow l restnctor. The flow restrictor is a venturi type flow meter. However, the pressure taps are on l each side of the flow restrictor and there is no pressure tap at the throat. i l Following a reactor trip the P-4 permissive selects a new seapoint for the high steant flow safesy j injection and steam line isolation. This new seapoint is equal to a 40% power sesam flow l equivalent. Additionally, P-4 also initiates a turbine trip. According to PSE&G analysis, the quick closing of the turbine stop valve maeariatad with a tubine-trip generates compressive pressure waves in the main samun line. These pressure waves travel upstream towsiil the steam generator and are reflected back and forth from the two ends of the pipe. These waves are also reflected such that they enter the paasure sensing lines for the pressure transmitters, where a pressure difference is then indicaand, and intermittent, short duration, high steam flow signals is ac, are generated. o se The team qih whether either Salern unit had experienced similar inteRBittent high steam flow signals following previous reactor / turbine trips. PSEAG reviewed past reactor / turbine trips and identified at least three aara=Laaa where short duratW high samm flow signals were 1 generated followns reassor/ turbine trips. Although PSB&G tm11dantined short duration high steam flow signals following previous reactor /nubine trips, as a result of the analysis during those prior events they detsnained that the aaadisian resuhed front the P4 high steam flow setpoint change and the time actual masam flow decreases below 405. PSE&O considered this to be an expected response of the instr =aa*=*iaa and that no vaadine=*ian was necesary. The spurious high steam flow signals caused by the pressure waves following a reactor /tabine trip were not identifiedl and therefoss, not evatusend until the Apn17,1994 event. Also, following the Apn17,1994, event PSE&G found that safety injections due to the spurious high steam flow signals had occhtred at anather Westinghouse plant and that time delay circuits me,e ins.d to address .is;piern. l
4 I . 1 1 4 7
}
l -
- Plant Response a
A review of the sequence of events generated by the plant computer following the reactor trip j
- and turbine trip indicated that protective action signals were generated in response to the high steam flow / low T., signals two times. 'Ihe sequence of events program divides each one second time interval into 60 cycles and identifies events that occur and/or clear within each one cycle ,
j time interval. AIT review of the sequence of events computer printout determined that the l l caiaridaar high manam flow and low T., naadneiaam were logically ansinnad twice just aAer the j reactor trip on April 7. 'Ihe first occurrence occurred and cleared within one electrical cycle i
! (0.0167 second). ' Ins second occurrence occurred during one cycle and cleared in the next
! cycle. Since it is not possible so determine when, wisida the first cycle, that the initiation ) i occurved, or when, within the second cycle, the trip condidon cleased, the acami duradon that i the trip signal was present emanar be determined other than it was premene for a maaimum of two ! cycles (0.033 second). 1
'lhe first occurrence was of such short duration that neither the A nor B protection system trains J
was able to actuate any se'. guards equipment prior to clearance of the input signal.
'Ihe second occurrence was suf5cient for protection train A to respond and resulted in a parnal
=camian of the safeguards equipment. The di5erence in the response times of the A and B l logic trains resuleed in the single train acniadaa. The reaaan for the partial actuation of the j equipment meereistad with the A rmeection train is that the short duration signal did not allow sufficient time for all of the seal-in and/or h% relays to respond. The safeguar_ds components that are actuated as a result of operation of a solid state protection system slave l relay (with a seal-in design) all performed as expected for the A protection system train. Other components, that have sont-in or lascidag relays within their specific control circuita, did not all operate. '!he laser set of components included tivo of the four MSIVs that failed to close, the l main feedwater pump turbines that failed so trip and the resia feedwheer isolation valves that j
failed to close. PSE&O temoed the system response so varying duration input signals so validate these conclumons. '!his testing is dhiaead in Section 5 of this repet. l' 3.2 Pressuriser PORVs,' Safety Valves & 4=an4=*ad Pipe
'!he pressuriser for each salem rescear coolant system (RCS) is equipped with two power l
cperused relief valves (PRI and PR2) that can be innhed from the pressuriser by block valves. ,
'Ihe PORVs are set so open at 2335 peig. 'Ihey actussed over 300 times during the event to '
4 relieve water and successfully prevented an RCS overpressure condition that could have i challenged the pressuriser afety valves. Also, they successAdly opened and closed several time aAer the event. .1 ' Post-event examination showed that both PORVs incurred wear of the valve internals; however, the valves still worked aher the event. Pradireirut of future valve operation, particularly due to the galling observed in PR2's valve stem, is judged impractical by the AIT. 'Ihe galling c d v
I e 8 lead to failure at any time, or the valve may operate numerous additional times before failure. Damage to PR1 was found to be generally less severe than to PR2. The licenw subsequently replaced the worn internals, which the AIT anaaidared an appropriate action. PORY Design Pigme 1 in Attachawat 7 shows the Salem PORV design. The valve is air actuated with the ! actuation diaphragm moving a stem (9) that passes through packing lomted in the valve bonnet. i
'Ibe stem is threaded into a plug (20) and an anti-rotation pin (8)is driven through the threaded l junction to prevent rotation. 'Ibe bonnet is bohed in pleos, and holds the cage (19) against a 1 gasiat (18) in the bottom of the valve body via the case spacer (21). 'Ibe valve seat surfaces are on the honom of the plug and along the inside of the cage toward the bosom. I.iAing the plug moves the plug seat away from the cage seat, aBowing flow. At the time of the event for Salem Unit 1, the stem was 316 eenialaae steel with a chrome plating, the anti-rotation pin was 300 senes stainlesa steel, and the plug and cage were 420 stainless steel. 'Ihe valves are manufactured by Copes-Vulcan.
This valve model was tested in the 1981 EPRI test program except that a combination of two different valve internals types were tested (a Stellite plug in a 174 PH cage, and a 174 PH plug in a 17 4 PH case). Some delayed closures were idaatikwl in the EPRI tests due to scoring and galling of some surfaces for the valve with the 17 4 PH plug. Originally, Salem Unit 1 used the 17-4 PH plug and cage internals. Subsequently, the liaansaa changed to a 316 stainless steel, Stellite plug. -
'Ihe change to the 420 stainless steel valve internals was completed in 1993. 'these new internals had no service life other than testing prior to the April 7,1994 event.
SW-* to the event, the licenses replaced the valve internals using the 316 stainless steel stellite plug in a 17 4 PH cage. PORY Performance During Event
'Ibe PORVs actuated over 300 tienes during the event to relieve water and successfully prevented an RCS overpressure aandhiaa Pigure 2 in A*'ach==at 7 depicts the RCS pressure during the transiset aAer the second SI actuados. It was during the period toes about 11:30 a.m. to 12:00 noon that the PORVs experienced the greatest amount of operation.
Each PORV is equipped with a " valve not fully closed" position indimeiaa activated from the valve stem. 'Ihis provides a positive irviicariam if the valve is more than - 5% open and is a recorded indicanon. 'Ihe lic==== reconstructed the number of valve cycles from this indication by counting a cycle as a cinnbination of passing 5% on an opening motion followed by passmg l 5% on closmg. On this basis, PRI cycled 109 times and PR2 cycled 202 times. Cycle times ! vaned from 0.3 see to 2 sec. I
9 Post-Event Examination and Evaluatino The licensee obtained the fonowing informs' ion for semperstme downstream of the PORVs 6cm the TMaial Support Center logs: Approximate time, Tail pipe Pressurizar Pmssuriser April 7 temperature, 'F temperature, 'F pressure, psi 3:30 p.m 215 650 2250 4:16 p.m 212 2260 6:53 p.m. 211 7:00 p.m. 605 1800 8:00 p.m. 205 595 - 1500 Roughly 212 'F or greater is eM nadar these conditions if the valve is open or lenking signi5cantly. The observed behavior from 6:53 p.m. to 3:00 p.m. indicated that the PORVs were closed and not lenking significantly. 'Ihe earlier values could be due to tailpipe cooldown following the event. For comparison, the Unit 2 thermocouples indicated 135 - 150 *F at about 5:00 p.m. on April 23,1994, while that unit was operating at power. Following the event, lia.aaaa personnel obsesved the the leak rate into the preemiiser relief tank (PRT) was similar to that =iaia= before the event (0.66 gym prior to the event; about 0.64 spm at 5:00 p.m. following the event). The source of the leak appeared to be frees a pressurizer safety valve, as is disentead later in this section.
'Ihe AIT noted that the licenses initially intended to accept the PORVs as operable following the event without a visual inspection of the valve P Newever, as a result of an AIT request for the engineering evabetina of the PORVs upon which that operabuity determiandan was based, the licenset then elected to open the valves for inspection.
The nn.a poet. event, preliminary ===iandam of PORY PR2 showed gauing of tim seem where it passed through the bonnet and severs wear / scrapes, bet little or no gaHing, along part of the plug and cage. The damage was concentrated on the side toward the outlet, which the licensee indicated was aanalent with past experience. The licenses sino indicated the case appeared soner than the plug. The sent did not exhibit obvious coming. 'nm plug was sported as freely movable in the cage by hand. Valve PRI did not exhibit stens wear, although there was some wear to the plug and case and there was a possible cut in the valve seat. Both valves had an axial crack on both sides of the and-rotation pin. This crack passed through the backseat.
i 10 f
! The licensee plannad to reassemble the internd pans and the bonnet fmm PR2 in a different j valve body and test to destruction with water at - 2300 psi if a test facility can be found that
! will use the radioactive components. De internal parts from PRI will be carefully examined. ( De finanean will aramiaa new internal parts for the PORVs to see if there are cracks in the j vicinity of the anti-rotation pins. i l Primary Code Safmy Valves i 1
- ne pressuriser for each Salem reactor coolant symem (RCS) is equipped with three safety j valves (PR3, PR4, and PR5) that are set to open at 2485 peig (t 15). Pnasme never reached l the safety valve setting during the event, although the PR4 tailpipe temperature indicated high.
i Post-event testing shonned that PR4 was weeping; a condition the AITjudges to have existed l before the event. De licensee plans to replace PR4 and will also remove and test PR3 and PR5. j .rano. I Valve tailpipe temperature for PR4 was obser9tho be - 216 'F at - 12:00 noon on April 7 (220 *F via post trip review report), whde PRJBtl PR5 indicated a more normal 130 - 135 'F range. (Roughly 212 'F or higher is expected under these conditions if the valve is open or
- leaking signi5 candy, depending upon both the pressuriser and pressurizer relief tank conditions.
j Note that the Unit 2 thermocouples indicanad 135 - 150 *F on about 5:00 p.m. on April 23 while i the unit was in mode 1. Also note that these temperatures are not recorded, ne only ! information was fmm logs and personnel recollections.) Dis elevated tailpipe ^ ..g eture } raised the question of whether PR4 lined during the event. t l Attempts to evaluate the tailpipe temperature indicanan operability following cooldown failed; l apparently mistakes were made by the liaaneaa in selecting sensors to test and the
- instrnawatarian was damaged during PORV dimenamhly and during instrumentation evaluation.
i Review of RCS pressure data and PORY open/close behavior shows that the pressure never siyal&=dy exceeded the PORV liA pressure of 2335 psig. Dua, PR4 should not have lifted i unless its seapoint was signi8 candy low. Each pressuriser afety valve has a 0.15 to 0.3 inch
- limit switch, which corresponds to - % to % open. neue is no record of a limit switch
, indicating open during the event. - De leak rate into the presemiser relief tank (PRT) was 0.66 gym befuse the event and was i estimaand as - 0.64 gym at 5:00 p.m. following the event. nis is eaael*=t with a leak that j was unaffected by the event. l Post-event testing of PR4 at Wylie Laboratories showed valve liA at 2515,2516, and 2524 psig, ! with seat leakage at 90% of tbs setpoint alue. (The valves are supposed to open at 2485 gisig l with a i 15 tolerance, which gives a maximum allowable of 2510 peig.) Wylie indicatad to the licensee that 25% to 35% of the safety valves they test will exhibit such leakage. j ! De combination of event pressure, leak behavior, and postarvent valve testing suppon a j conclusion that PR4 was leakmg prior to, during, and following the event and did not lift during l the event. The AIT did not assess the slightly out-of-tolerance lift setpoint for PR4 since it had i no effect on the event. l 1
1
- - l 11 pORVK'ade hfarv Valve Pinine The tiramaan performed a visual inspection of the piping and supports downstream of the PORV and safety valves inarnadiataly aAer the event and stated there was no evidence of damage.
Iater, aber ===' '=3 piping upstream of the valves, the licenses reported two support rods were bent; but that these were not believed to have been damaged during the event. The tiran== found no other pipe or support related damese. Aher the AIT effort, the firmanae completed their evaluation of the associated piping and determined that no flaws occurred as a result of this event. This evaluation was reviewed by Region I as part of the effort supporting restart -t and will be dsmenaaaad in a fuese sport. m licensee diae==ad pressurizer nozzles and its piping system with Westinghouse nasading pressure tranniants upstream of the PORVs and reported an awpaesariaa that there was little effect. The pressurizer volume would be expected to dampen such transients and no afety valve operation would be expected. The licansaa reported that an analysis assuming 2350 psig and 680
*F resulted in a usage factor of 0.01 for 350 fullapen/ full-close cycles.
'!he licensee's analysis was based upon PORV opening times of 0.5 see and 2 sec for closure.
The licensee did not address shorter times, the influence of a lower temperature (pressuruer temperature dunng the event was p:obably as low u - 550 *P), the e5ect of both valves being , in operation rather than one, or the influence of the valve not going fully open before receiving l i a close signal. The AIT believed addirianal analysis was necessary to establish the lack of l impact upstream of the PORVs. This concern was diaenenad with the liamaa. Subsequent to l the AIT completing its iaeaae+ ion activities, the licenses provided additinaal evaluations of the associated piping to the NRC for review prior to restart. The AIT did not assess this additional information. AIT Evalnariaa of PORVs. Rafety Valves and Ameae3**ad Pine h galling (or deep gouging) observed on the seem of PR-2 is of concern. The valve is designed with a clearance around the stem such that it should not touch the hannar With this clearance closed and with the seem dragging against the inside of the bonnet, the ability of the plug to open or close ornld be severely a5ected. Ofintement, the seem damage and plug damage were both on the dcr.vnstream side of the internal amembly which leads to the hypothesis that the damage could have been at least partly flow-induced. ; As previously mentioned, this valve model was tested in the 1931 EPRI test program, except that different valve internals were tested. The 420 semintens steel plug and cage in the PORVs at the time of the event, is a martensitic etnialaam whose baniness is depandam on the heat treatment. This is a much-used alloy where wear and corrosion resistaara att both impst. PSE&G and Copes Vulcan indicated the valve with the 420 stainlaan steel internals p% sed well in the field in similar applications.
12
'Ihe .iT found the PORVs' operability to be indeterminant after the event because of the observed damage, although noting that the valves opened and closed upon command shortly before disassembly. 'Ihe ATT also notes the PORVs were relied upon for low tenperature ca.y.wre pre (L'IDP) following the event, but prior to disassembly, and were also relied upon as a vent. 'Ihe AIT concluded that the licensee met the legal requirements for demonstratirig the PORVs operable prior to relianz for L'IOP purposes. However, the AIT believed that since the PORVs were operated in a ocodition beycod that envisioned in the PSAR (i.e. multiple nemariana involving steam and water), additicaal evaluation was appropriate.
Salem's FSAR analyses include an allowance of 20 minutes to reset safety SW for inadvertent actuations. Westinghouse recently provided information on this topic to the licensee as required by 10 CPR 21.21(b) (Gasperini, J. R., " Inadvertent ECCS kma'iaa at Power," Latter to Dave Perkins, Public Service sectric and Gas Ca=aa_ay from Weednghouse Bectric Coryv..Gcs, PSE-93-212 June 30,1993.). "Ihis staand that:
" Westinghouse has discovered that potentially non-conservative nemmptions were used in the licensing analysis of the Inadvertent Operation of the ECCS at Power accident.
Based on preliminary sensitivity analyses, use of revised assumptions could cause a water solid condition in less than the 10 minutes an=med for operator action time. If the PORVs were blocked, the PSRVs (safety valves) would relieve water and potentially cause the accident to der =da from a Condition H Incidant to Condition III incident without other incidents occumns indaaaadaatly. Per ANS-051.1/N 18.2-1973, a Condition 11 event cannottenerate a more serious event of the Condition III or IV type without other incidents occurring ir#+;='=tly "
"Ihe letter further stated that Westinghouse adopted the following criterion:
.s "The pressurizer shall not become water solid as a result of this Condition H transient within the minimum time required for the operator to identify the event and termiante the sourte of fluid increasing the RCS isa..h y. Typically, a 10 minute operator action time has been assumed *
(NOTE: Chapter 15 of the Salem FSAR dennan enaditinn H events as faults of moderate frequency including " spurious operation of the afety M-:-f= system at power," and, Condition III events as infrequent faults including small break LOCAa.) .
'Ihe AIT concluded that the Westingbouse recommended actions may need to be re===iard in light of the Salem experience. 'Ibe Salem operators took about 17 minutes to terminale safety injection during the first SI and 12 minutes to terminasa the injection on the second SI. The pressurizer did in fact become water solid and yet, plant operators reapanded appropriately to the inadverr.st EECS actuations per approved EOPs.
I
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~-
6 a 13 l Solid plant operation as encountered during the event is not specifically addressed in Salem's licensing basis as addressed in Chapter 15 of the Final Safety Analysis Report (FSAR). j r_i-ia= basis analyses generally do not reach solid plant conditions. For example, the i applicable LOCA analyses involve two phase conditions rather than the angle phase resulting i from a solid RCS, and a licensing basis inadvertent safety indoction does not lead to a solid RCS. j Regardless, the pressure and temperature challenge to the RCS pressure boundary is generally l enveloped by the composite of analyses addressed in Chapter 15 of the FSAR. Consequently, the AIT evaluated the event with respect to challenge to the RCS pressure boundary and addressed whether the event could have logically progressed to a more serious condition. 'Ibe AIT found that no RCS pressure boundary design parameters were ascended during the event. The operators restored a pressuriser steam bubble before conductag a plannad plant cooldown, thus eliminating the potential problems that may have occurred if a solid cooldown were attempenwi 'the AIT judges that not being strictly within the lie ===ia= basis envelope is not a signi6 cant safety concern for this event. The AIT addressed the possibility of progression to a more serious accadent due to PORV o-safety valve problems and concluded that multiple additional failures would have been necessary. Further, the AIT judges the most likely such accident sequence would have been a loss of coolant accident (LOCA), which is within the design basis for the plant. 3.3 Circulating and Service Water Systems Overview As diammaad y.sdsasty, the evesnt of April 7, !994 evolved from an initial problent of plugging I of the Salem cirruta+ia= water (CW) intake screens followed by CW pump ai*waarie trips as water level difference across the intake screens reached the 10 foot trip value. Although CW is necessary for plant operation at power, it is not essential to the plant's afety. However, the vulnerability of the CW system to grass intrusions ch="==== continued power operation of the i plant as well as ch=11a=== the plant operators and safety systems in response to the resultant i transient conditions, as occurred during this event. Consequendy, the AIT assessed aspects of CW operation. In contrast to CW, service water (SW) is vital to safety - it provides the safety related ultimate heat sink. Salent CW, Salem SW, and Hope Creek SW are located in three sinullar intake structures along the Delaware River. ' Ibis observation immadimanly raises the question of j whether the problems that occurred with CW could also occur with SW. Consequently, the AIT
==ead the potential for a loss of Salem SW in light of the problems with the Salem CW.
Hope Creek experienced a loss of one SW pump wlule the team was on site, and the AIT briefly
===ad this event for applicability to general SW reliability, and concluded that the failure was unrelated to the events causing CW difficulties at Salem.
j . 1 l 1 i 14 l i i Badlass l The AIT found that the cantinuing problems exponenced with Salem CW present an important i challenge to plant operadon. 'Ihis could become a safety concern because of condnuing plant
- pernubstions that cause unaana-ary plant traneinmen, distracts the operators, and potentially leads .
j to nanan==eary challenges to the operssors and plant safety systems. While noting that the twaneam han previously approved a Icas term fix by modifying the CW design, the AIT believed , a short term fix was warranted, such as improving the operating procedures to respond to the resultant tranaents. SW operability was found to not be a short term issue, requiring corsective actions. 'Ihe i licensee indicanad that they have never'had a SW failme due to debris and the AIT found no ! other evidence to the contrary, indieneing that SW was not vulneraide the same initietor. 'Ihe ! AIT suspected that the design of the circulating water struceme leads itself to such vulnerabdity
- and that the service water structure design is potentially unaffecsod by debds. '!he AIT further l concluded that additional NRC review of service water system vulnerability was warranted but j was not within the scope of the AIT inspection.
wa,iaa of m and paaa ce wa.- va+ sr=_ and naa d warhi-l Salem and Hope Creek have three water intake structures positioned as shown in Fig. 3 in Attachment 7. Salem's SW intake is about 100 yds upstream'(north) of the CW intake and Hope Creek's SW intake is about 3/8 mile upstream of the Salem SW intake. Water entering each intake structure passes tiuough a trash rack, a moving screen, a pump, and, for SW, a filter. 'Ibese are shown in Figs. 4 - 6 in Attachawne 7. 'Ibe bottoen of both SW intakes is at about the river bottom, about 30 feet below surface grade. 'Ibe CW latake bottom is 50 ft. below grade and the dver bottom is dredged to that depth for the width of the intake struceme and for a distance of 100 ft. from shore. CW Performance During the Event In anticipation of addifianat grass intrusion events, the licensee had removed the front covers of the traveling CW screens and laid fire hoses that were used to wash aar===alanad grass and debris fkom the screens befoes the built-in screen washes were reached. Quick <tisconnects had been pewided on covers in the screen drives so that sheer pins could be replaced quicidy (3 to 7 minutes). Despite the fire hoses and running the screens as fast as poemble, the screen loads became so heavy during the event that shear pins were fading and screen clogging was causing a significant water level drop across the screens. One liranea* representative marimatad that the water level drop across the trash racks was about 1 - 1% ft. CW pumps tripped when level reached a 10 foot differential across the screens.
i i, 15 i There is no easily obtainable record of CW screen operanon. However, CW pump operation j was obtained and is summarued as follows: 1 1 l Five CW pumps were in operation during the initial part of the grass intrusion. Various l pumps tripped and were restored to operation by the efforts of the personnel staged at the CW structure. Just before the reactor trip, only one pump minad, and at the time of reactor trip, two were in service, ] j An ATT member observed one grass intrusion during the casite inspartian Fire hoses were l being operated to clean an asennatad 1 - 1% inch thickness of debris off of the screens. { Immadinemly aAer the attack, debris around the screen machines was aside to knee deep. Licensee personnel said the debns was waist deep following the April 7 event. 4 SW Reliability 4 ! IJcensee representatives informed the AIT that they had never seen a correlation between Salem
- CW debris problems and problems with SW at the Salem or Hope Creek sites. They further l indicated no historical problems with loss of SW due to debris. The AIT found no innennean that contradict those descriptions.
{
- The licensee provided excerpts fmm its' evaluation of'a June 1993 turbine trip / reactor trip due i to loss of CW (SERT Report 9307). (That loss of CW event was attributed to actions of a j diver eta-Mag a cuculator_ trash rack.) 1his stated that:
" ... service water rake and screens are not challenged by debris as are the circulating l
water systems. As a result, service water screens operates (sic) periodically as compared with constantly for cirad-6 water. The service water trash raks is used infrequently j while the circulating water trash rack must be cleaned at least daily during heavy i grassing periods.... 'Ibs Servios Water intake has not been subject to the same accumulation of trash and silt as the circulating water intala, For example, while the
! Corps of Engineers was dredging upriver in 1983, sitting caused the shutdown of all 1 circulating water pumps, but the service water intain was not affaceed. This difference in susceptibility to trash and silting is attributed to the location of the servios water intake directly on the river front. The circulating water intake is in a diverging section of the river and the resulting drop in velocity and eddy fonnation is more conducive to trash and sitt accumulation."
Licensee personnel also oAen cited the high velocity at the CW intake as a maior ocntributor.
- In addition to such factors, the AIT judges that the CW high flow rate is a maior factor in that it affects a much larger section of river bottom than affected by the SW systems and a 20 foc*
deep ' pit" is dredged in front of the CW strucan , Material falling into this pit is likely to be sucked into the CW intakes.
- 4 J
i l 1 l . l t 16 l j l ! ansed on this infonnation, the Arr concluded that there was no immatin* concern reganiing ! the reliability of the service water system; however, as previously stated, this issue warrants
- funher review by NRC as part of the planned reviews of service water systems and individual j plant evaluanons.
j Additional Infonnation Regarding Hope Creek SW l; De Hope Creek 1p- stated that no remot SW traveling screen failures have occurred due to shear pin failure. Several years ago, the screens were not routinely in operanon unless there l was a pressus di5muntial across the screen. Den the screen would saut at nonnat speed and j i==arlianaly shiA to high speed. Sheer pin failure would onen fouow. l Each screen at Hope Creek is now operated whenever the respective SW pump is operating, a l a shift to high spued does not cause shear pin failure. An una penhie increase in pressg e i differential when the screen is operating at high speed is addressed by starting another SW purpp 4 and stoppmg the first pump to allow the screen to cient via nonnal wash whde it continues 'to ! operate. A dhig to the I_h, switching between pumps in this mannar has always been ! sufficient to prevent a problem. De potentialis still raaa-aid in procedure HC.OP-AE.2Z-0122 (Q), " Service Water System Malfuar+ina," 7/9/93, which states: l i " Loss of service water can occur due to reed intrusion., De event typically occurs ! fonowing marsh burns fouowed by heavy rains and the next high tido.... His heavy intrusion overloads the screen wash system with subsequent intrusion of the reeds into the suction of operatmg servios water punsps. De resulting heavier than normal fiber intrusion clogs the service water pump strainers." De la=aaaaar was told that there are relatively heavy debris " hits
- roughly 3 times in the fall J
and 3 or 4 times in the spring in widch high diffesential pressee alanns across the travehng ; screens are received in the Hope Creek control roont. De response is to start a different SW pump and shut down the operating pump widle the screen anaelauan to operata. De built-in screen spray system has always been adequate to cisen the screen once the flow was .w.sved, ! and the problem has been handled without further an=puradan by swapping back and forth, a capability made posible by the two trains of three pumps each. 3.4 Remeter Systmas Response 3 De Salem Unit 1 event included aspects of potential concern with respect to the reactor fuel and the reactor coolant system (RCS). Rese are as fouows:
- 1. Power and criticality control
- 2. Adequate margin to the departure from nuclease boiling ratio (DNBR)
- 3. Adequate suhanalia* margm (SCM) ~
- 4. Rate of change of terenerature
- 5. Rate of change of pre are i
l l i i 4
- . . . -~- -.-- -.--.-- -.----- - - . - --. - -
s . 17
- 6. challay to fuel cladding *
- 7. Law temperature overpressure
- 8. Pre Cocidown and Cooldown Operations
- 9. Post-Event Usage of the PORVs (powerW relief valves)
- 10. Piping raneidarations Each is addressed as follows:
Power and enticality enntml Control of power and avoidance of aaadieiaan that could lead to rapid power escursions are important to protection of the fuel cladding and the RCS pressure boundary. Although power was rapidly reduced during the April 7,1994 evuot, no unusual con 8gurations resuhed and the reduction rate was saml1 when compared to a typical transient associated with a reactor trip from full power. This aspect of the event was not a challenge to the fuel or the RCS. The power increase rate just before the reactor trip was about normal, and actual power was small in comparison to full power. Heatup aspects of the transient were probably of little consequence since there was not a large local transient effect. For this reason, the AIT did not investigate such areas as transient @ e distribution within the fuel. Paaehian a lower temperature than permitted by Tachaient Speci5 cations raises questions such as: adequa_te rod control to attain shutdown; and, could a positive moderator temperature coefficient have ben sacr == eared. The licensee investigated these questions and reported that shutdown margin was always signi5 candy grunter than required. The modcrator temperature coef5cient always r-laad signiscently negative. These conclusions were Ladaa=da'itly
- verined by the AIT.
l Examination ofintermediate and power range nuclear instrumentation ladicatican was performed ! by the licensee and no signi5 cant deviations were found between the ladientiaan and actual plant l power during the power aermaniaa transient. 1he AIT concludes that no local or overall power conditions were reached that are of concern. Maa... a .iare frasa =.A-aea hailian r=+ta mNRm + l An adequate DNBR is necessary to assure that the fuel cladding does not become blanketed with l steam, a condition that would cause a rapid etaddiag temperstme excursion. The licensee investigated core thermal limits and the axial power distribution during the event and concluded that DNBR limits were not approncl# 1he AIT concurs with this menanaramat l i a 4 i
- I
, i s l l
l i l
_._.m. .. _ _ _ _ _ _ _ _ _ . . . _ _ _ . . _ . _ _ . _ _ . . . _ . _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
!8 AAmanae, enhanaline marrin (SCM) m .
Maintenance of an adequate SCM with an adequate DNBR assure that the fuel cladding remams cooled. De reactor coolant pumps (RCPs) r==minad running throughout the event and consequently large temperature vanations did not result and the reactor vessel upper head remained cooled. De pressure / temperature behavior during the event was evaluated and the ! minimum SCM was determined to be 39 *F. His occurred during the pressure transient at the time of the steam generator safety relief valve (s) lift. Much of the time the SCM was > 80 'P. ! Although all temperature and pressure indicariana subaenaeimaad that adequase SCM was always maiaemiaad, annunciator data indicated loss of SCM at -,--- E "y 12:20 p.m. during the event. De finanaae investigated these alarms and reported that overhead windows D 40 and D- ! 48, SCM low, are set to actuate at s 10 *F SCM, and that post event evaluation of annunciator historical data showed the following alarms: Item Date Time Train 1 4/7/94 12:20:02 - 12:20:05 A 2 1/7/94 12:22:57 - 12:23:00 B l 3 4/7/94 21:21:38 - 21:29:01 B 4 4/7/94 21:48:03 - 21:56:58 A 5 4/8/94 03:30:42 - 03:46:36 a.B 6 4/8/94 04:00:55 - 04:10:31 A ne finanean attributed these apparesit losses of SCM to the core exit thermocouple processing system (CETPS) iridientiaa that results froen pushing a tn's A or train B CETPS reset button or when a train of the CETPS is tested. Each of the two CETPS trains is provided with the following inputs:
- 1. 29 incore ther=aa==ta temperatures
- 2. RCS pressure
- 3. Containnwar radiation
- 4. Containment pressure The licensee stated that the apparent losses of SCM indicated in items 1 and 2 were due to the nuclear control operator pressmg the CETPS reset button. De rational is as follows. The.
bottom of the containment radiation scale is 1 R/hr whereas actual containment radiation is close. to zero. A zero will cause an alarm. The operator will respond by acknowledging it on CETPS followed by pushing the system reset button to re-arm the containment radiation input alarm.
, . - - -w-- . m-___- ,.
_ _ _ _ . _ _ _ . _ _ . - _ _ _ _ _ _ ~ _ . _ _ _ _ _ . . _ _ _ _ _ _ _ _ . _ _ _ _ _ _ . g 4 . 19 . 1 Depressing the reset button causes indicatad SCM to go to aero, a result noted in the operator's procedure. "Ihe specification for CETPS data transmittal time provides a maximum of 4 sec, j enanimaae with the 3 see time observed in table items 1 and 2. ) i i Table items 3 - 6 were attributed to performance of RCS hot les pressure chanaal functional l 1 testing. Placing the cimanal switch in the test position causes the RCS pressure input to CETPS to be zero. The tiemaan stated it venfled this testing as the cause by reviewing the control room l narrative logs and the overhead annunciator historical data, i l The Ar!' concurs with this ==plaa=*iaa of the loss of SCM indle=*iana and concurs that adequate SCM was maineminad throughout the event. - l I 1 ' l Rate of change of temperature
- ~ 'Ibe temperature change prior to initiating the controlled cooldown was less than 100 'F and the cooldown was conducted slowly and deliberately without approaching cooldown rate limits. Rate of change of temperature was not a problem.
I j Rate of channe of or===iire No large pressure excursions occurred that would represent a direct challaage to the RCS j pressure boundary (e.soept as noted below) or the fuel cladding. I Challenge to fbal cladding i
; The licensee reported that there was evidence of one or two fhet cladding defects before the j event and observed an iodine spike enacimaat with that number of defects aner the reactor trip.
i As discussed above, no conditions were found that could represent a challenge to the cladding during this event.
'Ibe ficanaaa obtained a gas sample froen the reactor vessel head on April 13 that ananimad of about 965 nitrogen, 35 liydrogen, and udnor ==anaea of other gases. No significant radioactive components were found. ' Itis is anaaimaae with a conclusion of no fuel damage since no sigai8a-M quantities of fission product gases were found.
'the AIT concludes that there was no fuel cladding damage and no conditions existed that reptueented a challenge to the fuel cladding.
tow temperarme overpreanne Temperature during the event never reached a value where low temperature overpressure would . be a concern. 1 l i i i l I 4 i l
^
i j 20 Pre {anidmm.and Cooldown Operatans The operators elected to restore the vapor space in the pressurizer aher the initial solid operadon
- in wiuch pressure was controUed by the PORVs rather than initiating an immediase cooldown.
1 hey additionally elected to not trip the RCPs. The AIT concurs with these starisiana A choice l to trip the RCPs or to attempt a solid plant cooldown could have signiScantly As. pike;s4 the i event. i 1he question of trippmg RCPs was raised during the event. *1he AIT considers such quescons i to be part of a reasonable > .J J. . of shernative acdons. In discussion with hey personnel ' who were in the connel room area during the event, it became clear that tids ahernative was never seriously considered for implementation. ! Maintaining RCP operation during solid oper : ion assured uniform RCS temperature, provided
- better temperature control, and allowed eye. tual entry into cooldown with a normal plant configuraban. Trippmg RCPs would have introduced a signiScant temperanne vananon into the RCS and would have caused average RCS temperature to increase, a paracularly difficult
- situation since a vanation of only 1 'F would change RCS pressure by about 100 pai.
Reactor coolant system pressure for several hours following the second safety ia!=*iaa is summarized in Fig. 2 in Attachmant 7. The part of the event during which the PORVs were controlling pressure occurred from about 11:30 a.m. to 12:00 noon.;Pollowing that, the PORVs were not challenged again. The operators essentially set the leadown rate and RCS temperature, and controlled pressure by varying the charging rate with the objeenve of =minemining 2150 i 50 psig. A pressurizar bubble was restored and pressuriser level reached 50% at 4:30 p.m. A normal cooldown from hot standby was initiased at 5:45 p.m. and was conducted without . difficulty. ,ou ran. Post-Event Usage of the PORVs The pressurizar PORVs were iJ upon for low temperstme overpressure protection and for venting fouowing the event. There was no evidence of a malfunction during this usage although, as discussed in Section 3.2, signiScant damage was found when the PORVs were disassembled. Piping Considerations As discussed in Section 3.2, the AIT has litde concern with piping downstream of the PORVs and safety valves. Previous analyses, testa, and the posteent ====iaasian of the piping by the hcannan have shown this piping was not challenged during the event.1he AIT qih the licensee regarding the potential for damage upstream of the PORVs.1he principal concern was the possibility of damage that could lead to a LOCA. This quescon had not been closed at the time of the AIT's exit from the facility, but was addressed by the lice- prior to requesting
21 restart agreement from NRC Region I. This additional information was reviewed by NRC Region I in order to lift the provisions of the CAL that was in place. Results of that review will be documented in a resident inspection report. ; Pr===idmar Dalief Taale (PRT) Ehmnwe Disk During the afety igjection arvustiana, the PRT ruptme disk ruptured to relieve the increasing tank pnesure, which resuhed frorn the volume of primary coolant inventory relieved to the PRT. As a result, m--- H ^ 'y one gallon of primary coolant was spilled onto the anneminman* floor. Subsequent to the event, the ruptus diak was replaced and the PRT '-^ : ' The rupture disk . operated as designed and no damage occurred to the PRT. Based on the AIT assessment of the reactor systems response during the event, no protective barriers failed and no abnormal releases of radiation to the environment occurred. 3.5 Atacopheric Steam Dunp Valves and Steam Generator Safety Valves Following the plant trip and initial safety iqjection, the reactor coolant system temperature increased u a result of core decay heat and reactor coolant pump heat. This RCS heatup, and the corresponding increase in steam generator pressures were not recognized by the plant ' i operators. Steam generator pressures increased above the seapoint of the steam generator safety valves because of the failure of the man =yenc steam dump valve (MS10) controllers to promptly respond. Consequently a steam generator safety valve hfted and the steam release through the valve caused a coGwn that initiated the second mutamade safety injection due to an actual low pressurizer pressure condition. The reason for the slow response of the semaarharic sesam dump valve was investicated by PSE&G and reviewed by the team. The results of this rev_ew is described in Secdon 5 of this report. The steam generator afety valves and low psessuriser pressure safety iqjection initiation ' circuitry w_: as designed. 4.0 PLANT OPERATOR PERFORMANCE & PROCEDURE ISSUES Grass intrusions at the cirenlating water intahs structure at Salem are a seasonal phanan==aa, , with more severe amacks in spring and autman. Lasses of circulating water pumps or screens afEsct randanear vacuum. Degradation of condanner vacumn can naaansien* reducing reactor l power or removing the turbine from service. The operator actions to cope with a grass intrusion are governed by procedures. In general, however, the actions taken by operators are a function of the extent and rapidity of the grass intrusion (and resultant loss of circulators and condenser vacuum), and prospects for rec . -y of any lost circulators. I l
'~ . - -
e 22 4.1 Operator Response Pdor to the Plant Tdy Preparations and Response At 'Ihe Circulating Water Intake Sinuarre PSE&G management had undertaken extensive efforts at the intabs struceme to combat the ciral=*ia: water grass intrusion and minimise the psultant, at least twice daily, transient. Management had assigned a shift supervisor, a mai supervisor, and an appr=3'== 12 person crew at the G4 water intake strumme for expected grass intrusions followmg diurnal tide changes. Phe hoses and shovels wee ,.. g " and used to remove grass from tbs screens during grass istrusions. However, during hoevy grass intrusions, es occurred on April 7, a high screen differential presome rapidly develops and disables the travelling screens by sacrificial failure of the shear pins that annaaet the screen motor to the screen gear. The extensive PSEAG efforts at the intake struceme had generally posidve results in dealing with prior grass intrusions. Management established special work control procedures to facilitate quick restoration of failed cir~la'ia; water screen shear pins. The special work control procedures allowed the local shift supervisor to approve work and blocking tags during' screen repair, thus bypassing normal work control' oversight. Records were procedurally required to be maintained by the local shift supervisor for all work perfonned however, the tagouts and work control history used during the April 7 event were lost and no pennanent record was made.
'Ibe local shift supervisor provided direct continuous en====icadan with both Salem control roorns.
Preparations and Response at the'nrrbine Hall Two off duty shift supervisory personnel were **ianat at the water box area dwing grass intrusion to assist in restoration of circulators to savice should trips occur. These individuals were available to assist in ymnp priming operations. The inspectors learned that shift supervisory personnel would, at times in the past, override the weser boa priming protective interlock for the circulators by manually lifting contacts.1his was found to be tbs <mse during the April 7 tranei,nr when an assempt to ressore the 12A cisculator to service was mammanful.
"Ihe on-duty Senior Nuclear Shift Supervisor (SNSS) manosuy lifted contacta, an action which is not direceed in approved operating procedmus. 1%is action by an SNSS sets a poor supervisory example for other crew ==m-a. As win be deemibed and developed below, the SNSS's presence would have Hkely been more haa= Annal in the commel room. His absence from the connel room was an example of management.
*=m.'" priarkbeden of andvities by shift crew In spite of the efforts in planning and guidance outside the control races to effectively respond to grass intrusions, personnel response actions at the cideig water intake structme did not fully meet plant management e**s, and an action in the tubine hall Gumpering a protective interlock) was,not procedurally duected and was taken by the senior crew manager.
. aos ;
.s%I
~'X l
4. 23 Praan=da e =ad Oner=aar D*=aaae In h tw nl un, m Mn) Plant and crew management had made no special preparation for control room operator moponse to routine, ama*=d grass intrusion into 4% water, even though the plant was operating with us isp.mt automatic control system in manual. The event revealed weaknesses in the existing procedures and training for control room response that might be required for a significant grass intrusion. Despies twice daily grass intrusions which caused power :=hw*iana and restorations, no na-paaaaaary actions had been taken by management to ensure adequais rencear and plant control during the power swings. Automatic md contal was out of servios on April 7 due to arrective maianaamaan Operaton had suspected that the T., - T., comprator did not work properly and rods were being manually controlled. No compensatory actions had been established to ensme manual rod contml would not adversely hinder rapid power changes, apparently because management did not foness the potential dif5culties that could arise. Crew management >=*ad the two anctor operators to coordinase the reactor transient during the grass intrusion. In partic'c'.ar, crew management fansaw no dif5culties wi*h one operator on control rods and boration, controlling reactor power and temperstme, while monisoring pressurizer level; and the other operator performing tubine load reduction while monitoring steam generator levels, and controlling halaarw of plant equipment such as heater drain pumps, feedwater pumps, and cirMada: pumps and screens. Review of control room logs revealed some differences between thoes logs and the final sequence of events which suggested some minor confbsion among the crew members. "Ihe operator assigned to control the reactor was also assigned to maintain a costal room log of activities. Review of the log revealed that ali circulator pumps were removed from service or tripped during the event. At the time of the reactor trip, consol room logs showed all pumps out of servios and none returned. However, subsequent PSB&G review of circulator pump amperage, talen from computer data obtained during the event, revent that two pumps were running at the time of the reactor trip.
'Ihe inspectors considered the alarm response procedures for low vacuum conditions to be weak becaum no specine tubine art, criteria were provided. Main aanda - vacuum is monieored by the operators as tubine last stage back pressure. The operator's attempt to maintala back pnesmo as low as possibis, with annunciator alarms at 25 indies of vacuum (Iow alarm) and 23 inches of vacuum (Iow-Inw Alarm). 'Iha abnormal procedure for high backpuneme (Iow vacuum) conditions aanami==I no reactor trip criteria. 'the seapoint for the now vnosers turbine trip was not speciSed by the procedme and the procedure stated that the operator should restore vacuum unless a tubine trip occurred between 1g and 22 inches Hg vacumn.
At 10:34 a.m. on April 7, the 12A, and 13A and 138 circulators were out of service. "Ibe abnormal procedure for cirmt dag water requires that loss of both 13 pumps in comb ~mation with any 12 pump out of service, mquires the tubine be taken offline within one hour. It was clear to control room personnel that action was progressing to perform a normal, but rapid,
~.
I 1 l l 24 i turbine shutdown until and unless the minimum number of circulators could be retureserto l service. The rate of turbine load reduction was an attempt by the turbine operator to maintain i a minimum t+b m. in the main condenser. The operators started the transient with the l normal 1 percent per minute load reduction rate. Within a few minutes, an 8 percent per minute j rate was used to unload the tubine. The reactor control operator was required to control nector 1 temperature and power while simultaneously adding boren and inserting control rods while the i turbine was bems unloaded. L i haae*=ha that circulating water could be returued to service in a short period of time and j prior experience in ==lamining turbins operations through grass intrusions were cone ^ 4 i factors in the operators continued attempts to snahin tubine operadoes while progmasing to ! a normal turbine shutdown. The SNSS left the conaal room during the transient to over-ride l a circulosor punp permissive interlock and restart the 12A circulator pump in an attempt to maintain anahnwr vacuum and prevent a turbine trip.1he SNSS would normally provide direction to the NSS on when a reactor or turbine trip should be initiased. The actions of the SNSS in combination with the extensive effort undertaken by station pernaaaal to maintain j turbine operation at both the G=?=h5 water intake and in the turbine hall reflected perceived j management ==ae+=daae that extraordinary effort would be used to overcome grass intrusions; ' and when viewed in conjunction with the below<lescribed lapses in control of reactor power and ! coolant temperature, indicase that attention was inapproprisesty diverted from the primary l systems to the balance of plant. . Numerous distractions were present in the control room during tL. nad reduction. Continuing commaaicariana with circulating water operators required nurmous ========= of plant l
- conditions and restarts or trips of circulators. In the ten minuW prior to the reactor trip, during I the cocidown of the reactor; seven circulator puny trips and three restarts occuned on Unit 1.
Additionally, the commaaica*iaae included Unit 2 activities as well as repeated circulseor screen trips and restans. During this period, the rod control operator inade at least one baron addition and moved control rods nearly 150 steps into the core. At low power, s.feedwater pump oscillation occurred and tbs BOP operator requested and received authorisation to idle a I j feedwater pump. The rod control operator was directed to leave the rod control panel and shift l normal plant electrical loads froni the mala generator to an offsite power somos. This evolution j required stues to five minutes to compleen. , a The reactor cooled to below the minimum temperates for critical operadon. The shift i supervisor noemd tbs cooldown and made a reactivity daags by personally withdrawing control - rods while the rod control operator was shifting nonnat plant electrical loads. The result of this change could not be determined by the inspectors. The rod cannot operator reenned to,the
- control panel. He was given a direction to raise power to renaces plant temperstme and began a steady control rod pull. The shift supervisor did not discuss the fact that he had manipulated j the control rods with the rod control operator when he returned and his duection to raise power j lacked specificity, i.e., how far or how fast to raise power. The reactor trip occurred when j power reachad the 25 percent power high flux trip. At the time of the reactor trip, the only i bcensed personnel in the control room were the shift supervisor and the two assigned control i
operators. Other shift supervisory personnel including an SRO, an SRO-licensed shift technical i l i i
I ] l I 25 ! advisor, and the SNSS were in the turbine hall anending so water box priming. The AIT concluded that these resources could have been more effectively used for ensuring reactor control and coordianeiaa of primary and earnadary plant operations. {
- SmumaEX i
PSEAG management's preparation for control room operator response to routine, expected grass l intrusion into circulating water was weak. A=ea==#k red contml, an important system for l j automatic reactivity control during rapid downpcwor maneuvers, was considered non-functional. i Dis posed an additianal burden to the operators. Operator guidance and procedmus for rapid j (-- -
;u maneuvers, loss of circulators, and restoration of T below the Technical j sparineneiana = lain == wess weak or did not exist. *11ds ama===lemaad on-the spot, subjecove
! decision-making and operasor response; rather than a pro 9t anned, thought out, operator i response. ne above wi=*=a= were manifeemd in poor--nad and control of canael room j activities (confusion and lack of supervision of a relatively inexperianand reactor opencr) prior to the reactor trip and safety iqjection. When the operators' effasts were nannanameful, the resultant plant conditions (I.o-14 T ) combined with a long-eamading equipment problem (main steam line pressure spiking on turbine trip) to cause the first afety injection. D e event suggested training waalmanas ameacimead with the above topics, as well as performance wenimanean (multiple, simultaneous reactivity changes and monitoring of reactor response) and control room supervisory waalmaa*= associzted -titii -@ of operator activities and resource allocation, e.g., extra llamaead operator personnel were used outside the control room for balance of plant equipment, rather than inside the control roosn lo assist with contml room activities associated with reactor control 4.2 Operator Response Following the Plang Trip and Safety Iql actions RanctorJripand.fi:staafety iniection At 10:47 a.m. on April 7, the reactor tripped on low power high flux (255) while temperature was below P-12 (543 degrees P). De rencear trip response was as expected. However, momentary main steam-flow' instrument spikes while in the Imw-T , aandidaa allowed partial actuation of Safety Igection logic. while operanors recognised on Si aceandon occurrence, no Pirst out alarm indkaned the cause. Igection aluipment actussed as exposed. other equipment failed to respond as the operators expected when solid sense praesetion system (SSPS) train B did not accesse as described in Section 3 of tids repost. Emergency Operadag Procedures (BOPS) account for SI actuation failures by directing operators to align individual components to the SI position. Ten valves required manual repositioning during sheet 1 of BOP-TRIP.1, the applicable EOP. operators made one minor error in that they missed one letdown isolanon valve during the initial valve alignments. During this time high head safety injection was filling the pressunzer. Prior to reset of safety injecnon and realignment of charging and letdown, more than thirty minutes had passed, the pressunzer filled solid, and the power operated relief valves had ac+nnead repeatedly.
I 26 Operators took approximate 4y .5 minutes to realign valves. Four mom minutes were aquired to maata EOP steps that included control of auxillary feedwater ind lealmelan of main steam isolanon valves (MSIVs). 'Ibe operators took about seventeen minutes (resst at 11:05 a.m.) to reset from the initial safety injection. In addition, operators needed seventeen more minutes to establish pressure control with letdown and charging. PSEAG had recognized that afety injection train S=r - were possible occurrences and operator training included diagnosis of train dissgreement anadieiana Bowever, no procedural actions were speciand when train dissgreement occuned. During the transient, the operators considered that train B of SSPS did not anarvaatically acennes and took action to manually align the components as specified in the BOPS. Some dine ===laa took pisos that train B should be declared inoperable due to the failure to'actusse. At 11:26 a.m., train B manual actunde was used to insert a safety insecdon actuadon signal during ths.soud piant cooldown, althuur automatic actuation occurred prior to the manual aca=*ian Because train A safiety injection h:. actuated without any apparent aaineidaae logic (as would have been indicated by the "First Out alarm) in the control room, the operators could not be assmed that either train was fully Operable. , Solid Pressure Control The coadinan of the solid pressurizer should have best anticipstod by the operators. 'Ihe pre-trip cooldown below the ..Y .. .. temperature had caused a shrink of preensrimer level due to contracnon of coolant. 'Ihe presariser level control system assempted to maintain level by _ l limiting letdown and increasing charging into the reactor. 'Ibn pressudser level had contracted i to less than 17 percent and the pressurizer heaters had cutout as expected on low pressurizer 1 level. The subsequent safety injection added inventory to the rescear coolant system. In addition, the rapid nnesor bestup aber the fint safety injection caused a swelling of reactor coolam making the pressuriar solid. Apparently, none of the oggyears had predicted the result of the operating sequenwu although all were trained to do so. ,,, . . l Following the inMal safety izqjection, as they had been trained, tbs reactor control operator assumed the raaliaanihility for stating the requimd initial acaions of the BOPS. 'Ihs BOP operator j anadacead the initial acdons as rend by the reactor operator. 'Ihs initial acaions were completed l in appr=immealy five minness. Becauss he was involved in the numerous manual valve ) alignments needed in this event, the naaandary plant operssor did not adequessly manhor and maintain a stabis senem ganarasor possue, and the autommeic insano (sesam generator atmospheric sesam denpa or MS10's) used to control RCS emaparanno did not thacalon because of the charactedsdes of the contreuer. Secdon 5 of this report describes this characteristic. Also, the operators not recovering the use of that fenano led to the lifting of tbs steam generator code safety valve.
'Ihe operators did not anticipate the e5ect of the liAed steam generator code safety valve on the solid plant pressure and no anempt was made to control pressure prior to the rapid pressure decrease-that led to automeAc and manual actuanons of the safety injection system.
_ . _ . _ _ . _ _ _ _ . _ . _ _ _ _ _ _ . _ _ _ _ _ . _ . _ _ _ _ _ _ . _ _ _ _ - _ = _ _ _ _ __ i
- 27 i
, Although the command and contal funcaos daring EOP-TRIP-1 was as pracdcod, the operators j j neither diagnosed that the poor-SI sequence would usult in a solid pressuriser nor developed an <
- adeguate plan of action for control of solid pint pressure when maliand. De ear =lary plant j operator did not establish adequate heat removal usmg the atmospherte steam dumps.
i Snoond Safety iniection and ".ontinued Sand Plant Pmssum Control l il l Afuir a siens generator code afety liftsd, cooldown of the solid plant *Juased a second, aJtomatic afety injection on low pressurs, The opentors initiated a manusi sfety iniection l about the time when RCS pressure reached the SI seapoint. De second safety injecebe caused l i nutuercus PORY actuadons. De PRT ruptare disa failed as would be e during this time. a l De rapid pressure reduction was not anticipated by the operators. De operators did not have j char guidance on solid plant pressure contrv4. Dey did not consider thei establishing a bubble j l in the pressurimer was within the scope of the EOPs. De youow path for high pressuriae level l was not rh=8 nor used as ginidaare in drawing a bubble. Although in the W=riaM*= l system of EOPs, a yellow path represents and optional approach to the event, the licensee did I ! not provide for procedurally-coutrolled altematives to it. Thus, the AIT's view is that the l l correct path would have been identification of coolant inventory yellow path, then use procedure, i Fur.ctional Recovery Coolant Inventory,(FRCI-1) to establish a bubble, i
- Rest 4 ration of Normal Plant Preanne Control i Stable plant conditions were esaibushed prior to starung the pressuriser bestup. EOP guidance l was adequate in maintaining plant control and although there were numerous eachaical discussions and distractions in the control room during and subsequent to the safety insections, j
- the operefors controlled the plant to a safe Wat- Event declarations were in accordance with
! station procedures. De operators reset the second SI at 11:41 a.m. Operators were controuing RCS ^ .pture by manual control of the MS10a. Earlier, duskg the response to the opening of t's a steam i j generator code safety valve (s), the operators experienced diWy with the controle for 11MS 10 j and, as a result, malata:nad this valve in a manuel and closed condition. Abast an hour after i reset, at 12:54 p.m., the 11MS10 opened to about 50% open position, but was i=-6'aly ! closed with no noticeable cooldown. De plant presume and tempera me were then mala *=iaad i using the other three MS10s with no further dif&ndelas. 1 i Following reset of the second afety injection and establishmane of solid plant pressure control l using charging and letdown, the operators determined that the action statement of Technical ] Specificanon 3.5.2, which required two operable ECCS injection systems (or cooldorm to below j 350*F within six hours) could not be met. By design, the automatic ECCS actoshon capability j was not available fonowing the safety injection achiatina md would ac4 be re instated unless j reactor trip breakers were cycled after the safety injection was reset. Salera procedures did not include a provision of restoring the automatac functions of the safety injection system from these i t i i l__ ___
/ ? } 28 l conditions. In addition, the operators were not sure if either protection trains were operable i based on prriennance duaing the pr% evtsts. Slace Salan operators had no procedumi l saldaana for nMetablishing automatic safety injection capability, and since it was not char that ! the automatic logic was operable, and due to the estimated six hours required to re<etablish a l pressurizer steam bubble, the operators could not c@ a reactor cooldown in the time l reqdred by the Tachnical Speci6 cation. PSE&G rnanagement considmed the use of 10 CFR l 50.54(x) while the EOPs were in effect. However, later, aAer restoring normal pressure contml and completing the BOPS, PSE40 requested and was gntneat anfoe:ement discretion by the l NRC for the additional thnet uecessary to allow a reactor co:ddows in a contmiled manner, in accordams with normal cocidown procedures without automatic misty leketion capability. i Een Declaradans a ! Declarathm of the NotiScation of the Unusual Event was timely and in accordance with Sabm ! E a Action Levels. 'Ihe decisian of the emergency coordinsbor e declare an Alert to i obtain urhairm! ===iw=ar* when EOP: did not provide clear guidance was pr@nt_, l . ! Summant s l Opuseor response to the teacear trip and safety LW was per the emergency operanns ! proce4ves. Operators ==iarmined =*== sutMooling margin tigPA the evern. Operator j control of angineered safeguards equipment was appropriate throughout the event. He post-trip j phase of the event revealed wamu== in operator knowledge, y A---- =, agi procedural
- guidance for
- solid plant pnesse contml; ma of funcdond recovery procedme " yellow paths;"
handling of SI train dingmements; and, contml of MS10 contrdiers. 4.3 Procedere Adequacy and Use li j ' Prior to the Reactor Trip t i Prior so the reactor trip, direction to the opambors for clogging and Ian of t*:e cia:ulating wear l svstem was provided by procedme, SI OP-AB.CW 0001(Q), Orculating Water System l unuhection. nis procedue direceed adecenna ofload and nanovel of the imhine from service i when a minimma aa=h3==st= of tfem cireviators was not met. De power reduction was j aa-* =-i ndag the diseados provided by processe, si,OP-Io.2ze004(Q, Power Opendou.
! Neither procedme provided management expectadoes a m wtm opennors abreid cean the l enbet to mainada plant operadoes and instood, stabilise plant Mians by either tettine or reactor trip. As a result of the lack cf guidanca, operators went so an atypical rate of power ! reduction (8 percent per minute) in an attempt to adame main anadaaear and turbine operation.
1 l De inspectors did not identify pmcedural =panadame for operator action if the plant l temperstme is not controlled above timninimum too,y for critical operatkus, except tha Technical Specincations require recovery within 15 .=.C
29 The team identified that the Senior Nuclear Shift Supervisor, instead of directing contml room activi:ics during the transient, ignomd operations directives for equipment control and manually defeatext a circulator start seeM located in the tutbine budding while attempting to ensure centinced plant operation. Fo110wmr Reactor Trio At the time of reactor trip, operators correctly iWied procedure,' I-BOP-TRIP-1, Reactor Trip or Safety himtion. The EOP directs that awapanaa*= not aligned by the m*wn=He actuation be individually aligned to the safety isiection position. Manual actuation of safety injection is directed if safety h$ection it. requined but not indicated on the control panet indication. In this case, actuados was iadiamand, but not mquired, hence no =n==I actuation was insertad. It was not clear to the AIT, that the operators could speci5cally associale the failure of the large number of components to respond to the safety lehetion =**= with a failure of SSPS train B logic. De team noted that no guidance had been provided to the operators on proper response to ECCS train disagreement, which was idennnad to the operators during the transient by fla*hia: lights ce status panel RP-4, on the main control board. The operators cornetly transitioned to pmcedure,1 EOP-TRIP-3, Safety Injection Termination, when appropriate plant conditions were estahlished. Following the initial trip and safety injection, operators anempted e establish stable plant conditions but were unable due to the steam generator safety valve actuadon and cooldown that resulted in a second safety injection. Quasi-stable conditions were established upon recovery and runtry into procedme, I-EOP-TRIP-3, following the second safety le#ction. At this time, the plant was is solid plant pressire control. Specisc contml guidance for solid plant control is not provided by the SI termination procedure. l ( l Guidance for rewst1tblishing presses contml with a steam space in the pressuizar was available to the operators by Critical Safety Function; Coolant Inventory Status Tree, yellow path dinctive,1-EOP-FRCI-1, Response to High Pressurimer Level. However, this option was not i used. Instead, the operators contmund through 1-EOP-TRIP-3, and with technical support from the Salem Tachnical Support Center, re*=*=hliehad the steun space in the pressurizer outside of direct EOP g@~ As mentioned previously, given the resultant == Hema of the transient, and absent procedural guidance to restore the mana=natie safety isiection capability froen those aaadi*iana operators could not achieve the shutdown requirements of the plant technical apardAcatiren within the time allowed. A Notice of Enforcernant Discretion was issued by the NRC to allow the operators to prooecd with a normal cooldown. l l l l I
30 4.4 Event Classincation & Notineations Event Classificariaan and Notifications were per procedure. The Alert darimeiaa was particularly prudent, given that the operators felt they wanted or needed additional resources. During the initial notification of the Unusual Event, NRC expecutions were not met regardmg the level of detad of the telephone reports to the NRC and the ability to discuss the event and i answer questions that would enable the NRC to quickly assess the event to decennine the ! appropriate NRC stoponse posture. The initial notification to the NRC did not convey to the l NRC information that eamidic=*iana were assoriated with the event. It was determined that the licensee's Emergency Plan and Event N=inea*ian Guide required the licensee's conunnaicaene to fill la a data shnet (NRC Data Sheet - Anachenmar 8 of the ECO) that, if properly completed, would have given the NRC aneimat detail within ths required notification time. These problemas with level of detail and knowledge of the event were due to the physical locadon and the preevent activitiez of the communicator, combined with the limited background and experience level, in general, of communicators at Salem; and, an apparent lack of oversight by the senior nuclear shiR supervisor in approving the information h@ for transmismon to the NRC. , 4J Simulator thaa=*adsa On Apil 12, 1994, the Salem training % ;.t provided a dannnnstration of the event of April 7,1994 to AIT team members. The damanarration included an avgdanasiaa of plant response, indiariana available to the opmaeors, associased emergency _gperasor procedures, and a walk &Taigh of the EOP accens. The demonstration provided the inspectoss with a good understanding of the eveet dynamics, man-machine inesface, and relevant procedures. The demonstration was valuable in fostenng the team's understanding of the event and araar'ad operator response, The team acknowledges the cooperation of site management and the Salem training depanment in facilitating the sicaulator damaaserasina 4.6 Rameter Vesent Level radscaelam Systen (RVIJS) haamanadog On April 12,1994, the NRC Senior Resident inspector noted that the RVIJS I e in the control rcom were at 935 (indicating that the reactor vessel was not completely-fhll of water) and quaarianad the operssors about the ladicariaae The SRI was told that operators at Salem are not required to monitor RVIJS iadie=*iaaa while in cold shutdown. The team reviewed training material associated with RVIJS. ' Ibis training material indicanes that RVIJS provides accurase bdication while in cold shutdown. Assessment of the Gas Bubble in the Reactor Veasel Upper Hand The Salem RVLIS indicanons are readily visible on a back panel from the normal operator station at the control board. Further, the indicanon can be displayed on a control board monitor, i although, this was not in use when discovered.by the SRI. The Senior Resident inspector
r 31 discovered that each of the two RVLIS readings were showing - 935 on Apnl 12,1994. When ; this was ideriti6ed to the operators, they were not aware of the indiariaa and initially judged the instrumentation to be inconect. As a result, the AIT was concerned with the e5ectiveness of operator training on this system. In this case, RVUS was speci6cally installed to provide an indarand=t indication of water level for events initiating from power operation. A Adi understanding of shutdown operation would instill the insight that RVUS is important to shutdown operation as well. Appaready, the licensee did not expect that a gas bubble would fann during its shutdown operating anadiriaan Ultimanely, aher mud dia==laa with the NRC, tbs licenses took the following actions: {
- a. A sample of the gas bubble was drawn in a carend, well planned meaner. ;
- b. Operanns plans were changed to avoid plant perturbations until the gas bubble and its ;
implicanons were understood. For example, the licensee typically switches residual heat ! rarnaval (RHR) pumps from time to time to equalias use. A planned switch was po.q, cad haranea the tiaaneaa had not yet investigated whether gas bubbles asisted at other locations that could impact RHR system operation if the switch were made,
- c. An investigation was initiated to identify the source of the bubbis. 'Ihe investigation showed that the reactor analaat system (RCS) letdown, volume control tank (VCT) naadiriana, and charging were ananissant with generadog a bubble in the n! actor vessel by introducing nitrogen frorn the VCr via the charging system. (NOI11: Dunng shutdown operations a nitrogen " blanket" is =miataiand in the VCr to ensure proper pansure for the charging system and =iaimian the aman =t of oxygen in the system.)
'Ibe AIT judged that the gas bubble was 20 small to be ofi==ad ana i sa fety concern alh t ough it would have been a concern if signi5contly larger. Imporandy though, the AIT concluded that the bubble was slowly incnnsing when discovered. For the bubble to potentially perturb RCS cooling during nonnal RHR operation, it would have to aspend into the hot leg. 'Ibe most likely cKPansion process would result in draining au steam generator (SG) tubes, perbeps followed by lowering too pnnsuriser level, before a loss of RER would occur dus h. ortening et the RHR inlet. Imes of RER due to the bubble was judged very unlDaly based upon the bubble volume l
and pnmaars at abs time it was discovered. In addi'iaa to being concerned about the apparent lack of operator awareness about the formation of the gas bubble, the AIT was also concerned, however unlihaly based on other indicators, whether the gas bubble uculd have been an ladiantian of fuel damage. ' Ins licenses reported an iodine spike followmr the reactor trip that was expected frorn its knowledge that one or two fuel j pins were leaking. Ne indications of fuel damage due to the event were evident at the time of di.eewy of the bWu, nor were any found at any time by the AIT. 'Ibe licenses obtained a gas sample at approximstely 5:30 p.m. on April 13. Analysis showed it to consist of about 96 l nitrogen, 3% hydrogen, and minor amounts of other gases. No sign 16 cant radioactive nw rm n~- r- n n . , _ , _
1 32 components were found. De analysis was as expected for a gas bubtde at that location due to nitrogen being intmduced from the VCT. De sample was consiment with a conclusion of no fuel damage since no signi5 cant quantines of fission product gases were found. 1 Based on the system operations since the plant skuedown and the evidence gathered through the linmanan's sample analysis, the AIT desennined that the most likely conse of the bubble is gas transport from the VCT. De composition of the gas sample is consistent with an origin in the VCT. Shortly aAer discovery of the biabble, the VCr pnesse was 33 peig at a temperstme of 64 'F, in contrast to ====minHy atmospheric preAsus in the pressuriner gas spoos (and a higher i pressure in the hot leg due to the head of water in the pressuriner) and an RCS temperatme of 170 *F. Conditions existed for absorbing nitrogen in the VCr and alsasing it in the RCS. ucensee calculations con 5nned the plausddlity of this behavior. De licensee reduced VCT pressure to 15 peig during the evening of April 12 to educe gas transport into the RCS. ,
]
1 4.7 Operations Ca=eh i The event revailed a number of waakaa=== in plant systems, procedures, operator actions and management controls that are nonnally maintained to assue plant safety: e Extensive response efforts brui been established by plant and crew management for rapid response to grass intrusions, including placing maia*===aa* and operanons apervisors in the 4cH=; water structure during periods when grass intrusions occuned, streamlining of work contmis including use clea-the spot tegouts and asiminarian of individual component work ontera, and the ass of dhus, continual -=ie='iem between an SRO at the circulating water semctus and the contal room. However, even the streamlined work contmis were not Adly adhered as during the April 7 evart. Also, CW equipment control was still maintaiand by the control recen opuntors without neeistnace, even though the rannte==t transist conditions wet expected, e De contml mon operaton had not been pnwided adequaes guidanos on management expectations for connel room activities during gram inamsions. During the rapid power mductions'that had tiecome abnost unmina, cdmuladag weer somens, cheuladng water Pumps, main turbins load, sessa plant equipment coments, and amoeur controls requhed quick, c; i g- ^ =aalr=Imlaa= to imaet an of the guideliams for power reduction. De lack of management guidance was aggravated when red commel was placed in manual inmend of the nonnel =*===*ie condition, reqdrin6 dhoct rescear control and oversight as power was redmood. In spite of the daily power reductions and amealasiana and the inoperabic auunnotic feature of rod control, management had not provided additional mensmes to ensus that the control recen operators could successAdly respond to a rapid tunsient condition. e Pre-trip command and contml of operator activities were week as evidenced by: a poorly controlled rapid downpower with multiple reactivity changes; vague directions from the NSS to the renc:or controls operator to " pull rods" to restore T., above minimum I temperature for enticality; an excessive rod pull; an operator being directed to leave the reactor conals mate to tunsfer electncal loads while reactivity was not stable; and, l l the fact uct supervisors did not obtain additional W.Kw(s) in anticipation of the i l
33 transient to mmpan=* for having rod control in manual. Additionally, the on-duty Senior Nuclear Shift Supervisor (SNSS) was outside the control room, manually defeating a cirWa: water protective permissive interlock, when his pneance in the control room would have bener served nuclear safety, e The operators had not been puided direction on actions required for operanon with I reactor ternperature below the minimum temperature for critical operations. e Although the number of CW pumps sed screens was below the minimum required for tabine operations, operations enorts were directed toward plant recovery without a trip. '
'Ihis -===8ul eNort resulted in the a-Heiana leading to the safety iq)ections and subsequent loss of the pressuriser steam space.
Post trip operator performance and command and control were generauy good, aw) in accordance with applicable procedures, although some wealmesses were noted.
- Operators imptamanted and appropriately fouowed BOP TRIP-1 and EOP-TRIP-3; with one minor exception, i.e., one needown isolation valve was missed during the initial valve ,
i
=H a-ts.
e 'Ihe MS10 contreuer characterisnes inhibited the control of atmosphenc steam dumps. Ineffective direction had been provided to the operators to ensure adequate control of plant temperature fouowing reactor trips without ~=dansar_bypes empebGity. While training included discussion and simulator modeling of the MS10 conaal problems, the condition ramminad uncorrected for yeam. 'Ine inabGity to contml the memaapharic dump valves contributed to a steam generosor safety valve lifting and the neocod safety injection l during solid plant pressure consol. I e The operasors had not anticipstod that the cooldown and subsequent bestup would fill the pressuriser. No diagnosis of the eNect of the open safety valve on the solid plant had been made by the operances until pressure rapidly fell. e Use and knowledge of th=*== recovery procedem "youow paths" was weak. In particular, the availabGity and applicability of a yeuow pedi to establish a pressunzer bubble was not known by to the operaeors.
- The operators had not been pmided sufBeient direction agarding safety injecdon train logic dungreement, to minimim the recovery actions and possible avoidance of loss of the pressurizer steam space.
e Event Classifications and Notifications were per procedure. The Alert declaration was particularly prudent, given that the operators fek they needed additional resources. NRC
34 expectations were not met regarding the doenption of the eveat with the -:-:=;"=_sns that occurred. F . y Plan proceduas for 1:':C necessary infonnstion to be transminad to the NRC were not fully ? -;'--
- Operators knowledge and use of RVIJS during cold shutdown conditions was weak.
S.0 EVALUATION OF 11tOUBIESILOO11NG ACTIVITIES lhe AIT reviewed the licensse's troutneshooting plans to ensure that the causes of the "pamad plant equipment suspense would be deemnained. Also, the zeview assured that the onuse of any id==ind malfunadon would be conoceed. The AFT observed ponions of the troubleshooting activities to verify that the amivities were approprisesty = ," . -- Eh Solid Stare Protection Syneem 00 Followmg the safety injection on April 7,1994, PSE&G personnel perfonned extensive tesang of the SSPS to desennine the root cause of the event and to datannine if the system performed as designed. These efforts included visual inspeedons, perfonmence of ==*=Miahad survaillaar* tests and event specific tests and troubleshooting. Ibene activities included the following: A visual inepartian of the SSPS components, including the high sesam line flow input relays was parfanned. Disooloration of the relay cases,was noted and some relays had a powdery residue on the boteam of the casa. The naponse times of the high sesam line flow input relays were essend to doesnnine the time from actuating the bisabie to input relay commet clooms. AH relays operated and the drop out times varied from 4.2 to 14.8 =im nand. us co
- Surveillanos easts St.IC-ST. SSP 0000(Q)(0009Q), %stNState Protection System Train A(B) Fi=rvianal Test," were y A._- 1hs N for both trains were entiefar$nry. Mf nr =
- Portions of surveillance test St.OP ST. SSP 0009(G, "Begineered Safety'Penames SSPS
. Slave Raisy Test Traia 'A'," were paribnned to test the operados of slave seisys K616 and K621. These relays control the closing of the MSIVs, the feedwater lealmdan valves and the tripping of the seems generator feed pump turbines and the main turbine. All relay tests wem sensestscry. theirmity disoks of the reisess ooils for the MSIV cannot auxiliary ndays was also found to be sidsenceory..
- Survedlance test St.IC-TR. SSP 0004(Q), ' Response Thne of SSPS Ingic - Safety injection Train B,' was perfonned with ==tinenceary results.
9 35
- " Mini SI Test" was c@ and p-Lc. .sd on each of dt- SEPS trains to determme how long a safety insection signal must be present to muse abs, MSIV close circuit latching relays to energiae. For this test, one main sesam line high flow inn:rument was pisad in a trip condition and a pulse generator was aaaaaread to the input of a second. !
l The plant was in a cold shutdown condition resulting in all of the low T , instrun.ents being in the inpped condition. With these conditions, a pulse signal input to the second I high steam line flow instrument completed the trip logic necessary to generate a MSIV l isolation and Si protective signal. l ne asults of these insts desermined that all of the lanching misys operated as designed. : However, this tesdag damaamated that -aimw pudiolabis behavior could not be achieved unless the input signal lasted longer than about 50 =ami=aa=8a Purthennore, the as found condition of the relays associnand with Train A accessed faster than those maeimead with Train B; and therefore, a shorter input pulse duration on Train A would effect valve closure.
- A similar time response test to that for the MSIVs was perfonned to decennine if the feedwater isolation signal would close the four feodwasst isolation valves and trip the main feedwater pump turbines. His testing also showed that the equipment actuation was dependent on the duration of the input signal. All components operated as designed.
PSE&G decided to replace the high steam flow input relays based on the results of their visual inspection. A difference in response times of tbs two trains could also have been caused by differences in the input relay performance. Following the relay . ,'= ^ . the " Mini SI Test" was reperformed forTrain B. De results of this testingdecennised that the response time for the MSIV closing relays had deenased and the overall response timas more closely approximated those for Train A. Aw_xod.c se=== Du=a Valve r%atmh The design function of the air-operated atmospheric dump valves (ADV) is to renove heat from the reactor plant when the main aaadanear is not available, and to prevent operation of the main steam safety valves (MSSVs) during operating transients. De main sesam system pressure is
=-* "y 850 peig at full normally approximately 1005 peig at aero power and decreases e power. De ADV connellers are set to open the valves at 1035 peig (whereas the MSSVs open at 1060 psig). His setting results in a damand signal (amuel sesam pressere vs. "open' seapoint) i j
that maintains the ADVs closed and charges capacitors in the ADV contadlers. When steam pressure rises above the controller setpoint, the capacitors must discharge before the controller can begin pnwiding signals to open the ADV. However, due to the actual pressure being below the controller setpoint for an ext-dad period of thne (850 peig vs 1035 peig), the controller output saturates low (a phenomenon called reset wind up) and causes a delay in opening the ADV. Switching the ADV controller to manual will bring it out of saturation in a few seconds.
M : However, the specific time period required for the cootmikr to be in the manual mode to . discharge the internal capacitor, removing the rsset wind up, is not imown. l The team noted that the operators were trained to use the manual operating mode, however, the j emergency operating procedures did not address the use of the manual mode. 1 The response of the contreuers during the testing with a simulatad resup input pressure showed that the ADVs may begin to open before the peerure reaches the MSSV seapoints, but they may j not limit the pressure incanse to prevent opening tbs MSSVs. To miairmian the delay in the ADV controller response, PSEAG has instaued a clamping circuit i to decrease ties full power seapoint fresa 1035 pai to 1015 pai and decreased the contreuer gain from 12 to 3 and the reset time Anat ISO seconds to 2 seconda.1hese changes should improve the response time of the ADV contmuers to prevent a rapidly increasing paam pressure from nanarwaanrily opening the MSSVs. i 1he reset windup problem menacinead with ='=a=Paic steam dumps was the result of a plant j controls madi&arian implamannad in the late 1970's to prevent an inadvertent opening of the valves. Tbc ATT found that PSEAG had recognized this probian for many years, and had innanded 'to address it during a planned design change to the feedwater control system. ; i Licensee troubla=h~*ia: efforts also detennined that the problem that occurred with 11MS10 on Aprd 7, was due to a bed servo in the controls, which was then replaced. - Rod Control Synem The team reviewed the fouowing two issues related to the rod control systern operation: first, why the rod control system was being operated in the manual mode prior to the event; and second, whether the rod control system responded appropriately when it was momentarily switched to automatic control during the event. To address these queadons, the team reviewed the followmg: o maintenance history of the rod contml system prior to the event; e operation of the rod cannot system during the event; and e tmubleshoodng and tesdag of the md conemt symem aner the event. The team reviewed the recent mainaanmaan history of the rod contml system to determine why it was in manual control at the time of the event. This review indicanad that troubleshooting of the rod contml systsui had begun on February 25,1994, to investigate three separate inerna= of unexpected contml red insanion while the system was in autoematic control. The results of initial troubleshooting idaariAnd multiple grounds within the T,fr.,, recorder, which were w-wd. However, on Manh 14,1994, the rods again experienmd unexpected contml rod insertion. Troubleshootmg the same day identified notse at the T,,, input from isolator
g . 37 1TM505A. Noise was also identi6ed on the T input ham isolator ITM412N. Subsequently, both isolators were replaced and the noise was eliminated. AAer isolator 1DH12N was replaced, it was found to be driAing. De isolator was =cahh =a-i and PSEAG continued to monitor it to detennine if the driA was a problem. At the onset of the Apnl 7,1994 event, the rod control system was being operated in the manual mode. During the rapid load reduction the operator swieched red control to ==tamanic with the NSS' approval. De rod speed indientad seven steps per minnes and the rods seepped in approximately two steps then stopped. De opemear observed the T., recorder read noticed a five degree temperature error between T,., and T.,, and detennined that red speed should be 72 steps per minues. Dmesore, the operator thought that =aamarie rod connel had not responded approprisesty and switched back to manual control. PSEAG perfonned the troubleshooting to determine whether the rod control system responded w'" 'y in =aamarie during the event. His troubleshoodag included the ==rief=enary performance of procedme, SI.IC-CC.RCS 001 (Q), " Rod Control Syseum Automauc Speed Veriscarian," that veri 5ed proper rod control system operation at 6 and 72 steps per minute. De rod speed and direction dammad are based on a -+ -; --"" esaparature error signal. Temperature enor is denned as the difference between T., and T. and is compensated by a power mismatch signal. De magnitude of the aamp===*iaa sigan1is dependent on the power eriiummach between main turbine power and renceor power. Addieianal troubleshooang was perfonned to verify the proper operation of the rod control synessa by varying one input parameter while maintaining _the other input parameters constaat. De results of these tests indicated proper operation of rod control in the ausametic mode. PSE&G also performed a dynamic test to verify proper operation of auenmatic rod centrol. His test established initial conditior.: where nuclear power, turbine power and T., were set at 10%, , while T.,, was set at negadve Sve degree enor. Nuclear power was then ramped from 10% to 25 % over a one minute time interval. This test also indicated proper operados of =*===*ie rod ; control. PSE&G perfanned other troimbleshooting to con 8nn that the problems identi5ed prior to the i event were adequately remotved. Dese tests included a veriScotion that the systeen grounds were removed and that the isolator drift was within =pacine=siaa Additionally, PSEAG concluded that the T. reconter should not be used as an indicator of required rod speed during power changes and inaraded to conununicans this to the licensed operators and reinforce it in operator training. I.v._- _s ea n=aaa (Tm N=ela=e raserumane=+ian Sv=a== (NIS) l In addition to other functions, the IR instrumentation channels provide reactor trip capabdity and block both automatic and manual withdrawal of control rods (rod block) at 25 % reactor therma! I power (RTP) and 20% RTP, respectively. l l l l
- -----m --
4 38 This trip, Ivinich provides protection dunng reactor startup, can be inanually bypassed if two out of-four power range chanaale are above approvimately 10% of Adl power. Dunns the ! event, the reactor tripped at 255 RTP by the power range (PR) NIS low setpoint when the l reactor power inersoned fron 75 RTP to 255 RTP under manual control of the control rods. ! During this power aaratasiaa, the IR instrumentation chanamin 1.out-of-2 logic did not provide i either the red block or the reactor trip Amr*iana It was detenniaad that the IR instrunnents were indicating a lower power than the PR, instruments and never exceeded the IR sod block or ancear trip setpoints. The licenses stated that the IR sod block and trip function are for startup protection; but, the PR startup trip is used in the safety analysis (and the IR $=celaae are not credited). The liaaneaa's investigation found that the d:Nerence tietween the PR and IR instnunent's indicated power was due to the different locanons of these two detectors around the core. The IR detectors are in the ~' .cr. region of the core and thus -r.h more neutron shielding from the control rods in the core (rod shadowing) than the PR detectors. The PR detectors are located at the upper and lower regions of the core and are, therefore, less affected by the rod positions. For a given reactor power and control rod position, this phenomenon may result in a higher power indieneina on PR instrumanentian chanaala than on the IR instrumentation chmanale, as was observed dunng this event. PSEAG decennined that rod shadowing due to the control bank "D" rod position (operator pulled 35 steps, from step 55 to step 90 on control bank D) was responsible for the failure of the IR NIS to provide rod blocks at 205'RTP and reactor trip at 255 RTP. Westinghouse study of this phenomena found that detector IN35 would not initiate ] signals for rod block and reacsor trip until the RTP was 28.15 and 35.15 respectively, while , j its redundant detector IN36 would not initiate those signals until 25.3% RTP and 31.6% RTP l l respectively. This translates into a maximum error of 10.1% RTP on IN35 and 6.6% of RTP
- on IN36.
l j The existing,sespoints of the IR instrumentation chmanals are based on WCAP-12103, j " Westinghouse Setpoint Methodology for Picenction Systems, Salem Units 1 & 2." In this ! analysis the assumed "sespoint uncensinties" used percent span accmacies for various Rack i Parameters (RP), and Process Meassement (PM) that wue naaeimar with the standard Westinghouse methodology. This analysis used a combined uncertainty value in terms of percentage RTP for all PM components widch anaeminad allowances for power colorimetnc, downwoner temperstmo, radial power redistribution and rod shadowing. A subsec[uent Westinghouse analysis WCAP-13549 "Setpoint Uncertainties for IR NIS of Saleen Units 1&2" I separated the rod shadowing from the seat of the PM components and perfonned calcal=*iaan to i desermine the maximum value for rod shadowing that would preserve the total allowance. Total i allowance is the difference between the Safety Analysis I.imit and the nominal trip setpoint i assuming all uncenainties at their ===i=== values. The new eatentanian used an unoutaimy i of 1.8% RTP for rack drift which resubad in an increment of rod shadowing e5ect from 6.25 % l RTP to 11.875 RTP. This value is found to encompass the observed error in the seapoint of j the IR NIS channels d6ESo the rod shadowing phenomenon (10.1 % RTP on IN35 and 6.6% e s ms j em. l
c . 39 R17 on IN36) as long as the actual as-found IR NIS Rack DriA is less than 1.8% RTP. The post-incident as-found seapoints of both IN35 and IN36 instnunant channels were fo within this ===i=M Rack Drift value. The team observed that the md shadowing effect was used in the standant Westinghouse instrument setpoint c:^ +kyj and may have been reevaluated in the plant specific analyses (e.g WCAP-13549) for other Westinghouse Nuclear Power Plants. p;ah e"-- Flow * ' ' - &- cir=lery i I
' PSE&O performed testing to determine if the automatic change in the high steam flow following a reactor trip (P-4) was inducing electrical noise that may have caused mamane l steam low signals.
The results of this test indicated that mimmakw IPM5058 dropped its seapoint slightly below th ar=*d seapoint for a period of time following the renceor trip, while mammator IPM506B responded as ar=*d by ltoing directly to the new setpost. PSE&O ruled this out as a l cause of the event since high steam flows were received on both chanaale and this would req l that both summatars exhibit the same seapoint drop. l PSE&G continued tmublaahaaring the Ngh steam flow setpoint circuit to identify the cause Initially, PSE&G the summator IPM5058 seapoint dropping below the expected seapoet. thought thauhs mi==akr had faced, however, a raplaa====* module yielded the same tes results. Funber im _-9"=- by PSE&O revealed that both the replacement module and the module that was inenanM at the time of the ammt wese not the proper module.11ds modl the one used to replace it during the cuneet tmubleshooting wees of the proper part num did not contain the 'special" designation specided by the vendor. This "special' designado used to identily the incorporation of a capacitor in the mimmatar circuit. The test was Upon detennin! the wrong module was iammHM, the tirwaeaa ineenHM the proper module. l perfonned again, and tim man monits occaned. At the -heeiaa of this inspecti; was continuing no invesdsmas the reasca for the high seema Sow seapoint dropping expected setpoint following a reactor trip and how the inconect module was ins The AIT concluded that neither of these two concerns contributed directly to the Apr event; but, that the second imus was a potential leas of configuration control Conclusion The AIT closely monitored thelicensee's troubleshooting and testing activities. T
= of troubleshooting activities were very , good and that the planning, contml and y L--- -i+= Wiz" responses.
resulted in the thomugh validation of the root causes for the - The results indicated that the plant responded as designed for the conditions present on April 7,1994. ,dso, some equipment performed poorly, as a result of preexisting vulnerabilities or deficiencies such as the CW screen wash system, the high steam and the MS10 controllers. As described in Secaon 3.2, the licensee was initially p l
1
- l 1
40 accept the pressuriser PORVs without a visual "N l. . of the valve internals. While this ) activity was noted as weak by the AIT, this was not indicative of the liaaaaaa's generally very good troublaahaada efforts. 6.0 011IER FINDINGS Condenser Vacuum Alarms and Associated Pmendmes
'the team reviewed the alarm printouts and the SPDS printout of the aaads=== vacuum values j for the April 7,1994 event. 'this review revealed the following:
e 'Ihe vacuum sensed on the west side of the condenser was aaaalan=ady 2*- 3" Hg lower than that of the east side as recorded by the SPDS;
.m e '!he vaduum sensed on the west side of the aandaaaar dropped below 23' Hg at 10:40 a.m. and zwaniaad below 23' Hg for approxhnstely three mianwa, with the lowest value being 21.67* Hg for over one minute during that time; and e 'Ihe condeawr vacuum low-low alarm came in at 11:23 a.m., while the condenser vacuum low alarm did not come in during the ennt.
"Ihe anadmser vacuum sensed on both the east and west sides of the aandanen are used to provide indicatian. AMidaantly, the a h vacuum sensed on the east side is used to provide alarm functions. 'Ibese alarm functions are a aaadaaa- vacumn low alarm with a seapoint of 25' Hg, and a aaadaaan vacuum low-low alarm with a seapoint of 23" Hg.
Diannanians with PSEAG staff revealed that the aandanew is a single pass aandanmar, with the cira-Mag water entering on the east side. 'Ihis design explains the variations between the sensed vacuum for the east and west side.
'Ibe team reviewed the alarm response procedure for the aandanear vacumn low-low alarm.
'this procedme described the alarm setpoint, the conse, anaamade actions associated with the alarm and operator actions requhed in response to the alarm. 'the Ma==ade actions descrity.sd in the procedme were a tubine trip and rencour trip if power is senter than 495, and just a turbine trip if power is less than 49%. 'Ihe esas deturndeed tids senesmaat is incorrect sirxs the device that trips the turbine is a marhanie=1 devios not related to the device acconting the alarm. AMidanally, review of the last calibration of the turbine trip device indkated that it was set within its aparinad range of 18" - 22' Hg, at 18.4* Hg, and would not have actuated at the ,
same time as the alarm. To addnes this issue PSB&O developed a procedme revision request l to revise the alarm response procedme so that it properly reflects that the turbine trip is not an automatic faaedaa menaciaead with the candansar vacumn low-low alarm. : l l
41 SSPS Confonnance with IEEE-279 Code of Federal Reguladoes in 10 CFR 50.55a(h) requires the nuclear power plant protection system to most the requirements of IEEE Standard 279, " Criteria for Protection Systems for Nuclear Power Generating Stations." As a result of the equipment nuponses experienced during this event the team renewed the SSPS design relative to two sections of IEEE-279. Seedon 4.16 ofIEEE-279, " Completion of Protomive Action Once it is Initiated," states that the protection system shall be so designed that, once initiated, a protective action at the system level shall y to completion and return to operadon shall require subsequent deliberate operator action. Seedon 4.12, " operating Bypass," which smens that whee operadog requirements necesiste automatic or manual bypass of a protoceive fhaceton, the design shall be such that the bypam will , be removed automatically whenever permissive aaadi*iana are not met. The team found that there were kehiag relays or seal-in features in all of the component control circuitry such that if there were actual maditiane requiring an MSIV isolation and safety injection, all actions are designed to go to completion. Also, the team determined that the manual bypass of SI (Auto SI block following reert) in response to an EOP step is not an operating bypass. The blocking of automatic SI following a system reset, permits the operators to take manual control of equipment as necessary to recover from a plant transient or accident. l The period of time that the auto SI may be blocked is controlled by plant Technical
- S ? " = > =.
The team concluded that the SSPS at Salem was in compliance with IEEE 279. i SSPS Modification History The team reviewed the madineneina history associated with the SSPS, including changes to the steam flow transmitters. It was determined that the changes made to the system did not have , any efliscs on the April 7,1994, event. Addada==Hy, the team also reviewed the design sparincarian for the SSPS, and faded, no sparderneian related to the minimum pulse length required for actuation of the SSPS/ ESP synesens. Input Relav Chatter lhe eens found that the main steam line flow ladicattaan have experienced drifting during the operating cycle. The drifting resulted in the instrumentation output naching the high steam line flow trip setpoint and caused momentary drop out and pick up ("chassering") of the associated input relays. To eliralamme the relay chatner the flow insern==earian was periodically recalibrated. As discussed in Section 5 of this report, a visual inspection of the relays indicated some discoloration of the relay cases and the endence of a powdery residue in the cases. The input relays were subsequently replaced. The response time of the Train B of the SSPS appeared to improve following the installation of new relays, however the team could not
.. - - - . - - . - . - . - - - - _ ~ . . . - - - - - - - - . - . . - . - . _ . , 42 !
deternune if the relays had been degraded by the chattering. De cause of the insmunentation ; drift had not been identified prior to completing the ATT inspection. De AIT judged that the relay chattering did not play a key role in this event and should be reviewed by NRC as part of routine inepartian NRC inspection in this area was continuing aher the ATT effort, as part of l the NRC Region I effort to review and assess licensee actions prior to restart. His effort will be dacumannad in a future inspection report. 7.0 SAFETY SIGNIFICANCE AND AIT CONCLUSIONS 4 7.1 Safety Signifiennee De AIT found that the event was not a signiacant thrust to the reactor fuel, the fuel cladding ) or the conesiamant 'Ibe RCS pressee boundary was maintained within its design throughout 1 the event; however, the pressuriser PORVs and piping upstream of the PORVs were r*allanged by frequent cycling of the valves to maintain RCS pressure. De PORVs functiaaad as designed to prevent an RCS overpressure although they were damaged in the process. His damage did not appent to affect PORY f=+- "h during or following i the event. De lirJensee did not -:-:- -( evaluation of piping upstream of the PORVs prior to I the AITexiting the site, and ceewi 3y the AIT was unable to complete its ========t of that i
)
piping. De PRT rupture disk relieved to containmant as designed during the event. De amount of l ] ' coolant released to containment was minimal and undily cleaned up following the event. De containmant pressee boulMitry was not challenged. De most likely complication with =ignikaat consequaanan if further failures had occuned during the event is a small break LOCA. Multiple eq4--- failures would have been necessary for this to occur, such as: coincident failures to cloes both a pansuriser PORV and i its block valve; or, aaaaaidaat fhilures to open both PORVs and a resultant opening of the paesurizer safety valve (s) and a subsequent fhilure of one or more valves to class. However, initiatlan of the IDCA would be whida the design basis for the plant, and equipment necessary to mitigate such anadifiana responded as designed to the inadvertent safety is(ection actuation and hence, would have been available to respond m any fhntur degradadon had it M. De Salem April 7 event unutted in no protective barrier failunn. However, the event led to a loss of the pansuriser steam space and significantly challenged RCS pressee boundary ' aan'Paaaaa while, as described above, the safety consequences of tim event were minimal, the AIT - considered the equipment, personnai performanca and procedural problems to be may and in warrant addnesal by the 1i<== . 4 4 l 1 4
o 43 7.2 AIT Caaeh==laas ;
- No absonnel releases of radiation to the envireement occurred during the event.
The Arr developed an indTandant sequence of events and perfonned an anaapsmaat of key operadas parameters that would indicate a failure to a primary barrier such as fuel cladding, reactor coolant pressure boundary or =*ala==at. The AIT decennined that the primary boundaries remained intact throughout the event. The pressunser PORVs Ametianad properly on amnerous occasions to maintain the RCS pressure boundary within the pnwiously analysed envelope. As a result of these operations, the presariser relief tank (PRI) rupture disk rupesad, as would be espected, to prevent destruction of the tank. As a result, a few gallons of rummor coolant fme the PRT were released to the containment floor. The AIT reviewed the radiological surveys of the area near the PRT and concluded that the level of contaminarian was minor and aaneismaat with the normal activity contained in the PRT.
- Event challenged RCS pressere boundary resulting in undtiple, sucesssful ei,s.&w.;;
l of pressuriser PORVS and no operations of the possuriner safety valves. As stated earlier, the ATT findings diertamad that the event sequence ymyided a challenge to the RCS pressure boundary. As a result of the initial safety irdection, the RCS filled with water.. Without the normal pressurizar steam space to dampen pnasme excursions, the continued injection, both from the initial and second automatic safety hiection ach=*iaa5 resulted in repeated, ==~===ful aernatiaan of the pressuriser PORVs to limit the RCS presses within the analyzed envelope. The AIT concluded that the event did in fact pose a significant challenge to the pressure boundary by challenging the PORVs; that the passes boundary protective devices (PORVs and safety valves) fimetianad properly thmughout the event; that no lindes were exceeded during the event; and that some equipeunt degradation reenhed.
- Operator errors occurred widch ea=ymaatad the event.
The AIT reviewed plant event data and interviewed the operators involved in the event. It was l concluded that operator errors occurred throughout the event sequence. However, it was noted j l that operator 94- - -= was better aAer the reactor trip than prior to the trip. l l The operators responded appropriately to the poteadal lons of aandaaear circulating water by decreasing reactor and turbine power, ultimately with the intent to remove the LAL. 7- -W unit from service. Power was reduced, using a an=hianeian of control rods and boration, to a point that the operators began to switch onsite electrical loads to offsite power supplies in anticipation of removing the turbine from service. The shift supervisor directed the vpieler on the reactor controls to perform the electrical load swaps. At that time, neither the shift l l
44 supervisor nor the reactor operator recogruzed that the reactivity change, due to borations, was incomplete. In fact, when this was complete, the reactor power was less than the turbine power so that T began to decrease. Bis decreasing T was not immadiately identified; however, upon discovery the shift supervisor r-nadad to this condition by pulling rods in manual. Rus, the shiA supervisor was no longer in a position to properly direct the activities of the reactor operators. De RO completed the electrical load swap, isturned to the reactor controls without adequase commi=leatiaag hoe the shift supervisor regarding the shiA supervisor's acnons and commenced to raise reactor power. De RO noted that T., had gone below ' e Technical SMW minimum temperature for criticality, but failed to effectively communicate such to the senior reactor operator. Also, the shiA supervisor directed the RO to raise power, but, was not explicit regarding how far or, fast to raise power. Absent such direction, the RO continued to raise reactor power while monitoring T., for an indientiaa that temperature was swa.tg and failed to idastify that a reactor trip on low power-high flux naadition would occur. As a result of the above v.E cerors, a reactor trip occurred an high flux (25%) and the low T., condition was still present. 'ITe low T condition in coincidence with an indicated high steam flow signal initiated the first automatic safety injection. After the reactor trip and afety injecuan,' the operators appropriately entered the EOPs and aw-dully completed the required actions. As a result of the unusual equipment response to the initial safety injection system actuation, desenbed previously; numerous valves were not in the expected or required position per the EOPs. De operator responded to these conditions per the EOPs. One letdown isolation valve that was inispositioned was not initially identified and corrected by the operator. His was subsequently discovered by the operators during the termination / recovery actions aher idamtifying that the safety iajaa'taa was not needed. It is noted by the ATT that a rwhmdaat valve for this same isolation line did close. At about this time in the event sequence at least one steam generator code safety valve lifted causing a rapid aaanadary and primary cooldown. n' cooldown, from*the solid RCS condition, induced a very rapid depressurization of the RC md ultimateJy the second safety injection. De AIT enachiad that the operators were not i erly monitoring the RCS bestup resulting from decay best and the running Reactor Cook . Pumps, aAer the initial safety injection. De AIT noted that the automanc steam generator atmospheric relief valves should have lifted before the steam generator code safety valve set point was reached, but due to a characteristic of the controller for the relief valves (reset windup), widch the cy..icas were trained to handle, the valves did not open suf5ciently to limit the main seena pressure rise. Following the code safety liR, operators properly r-aadad by taking manual control of the steam generator at=ad~ic relief valves in order to lower pressme to re-seat the safety (s). De . resulting rapid RCS 4 ywL.iks was observed by the operators and they decided to manually reinitiate safety injection. A second automatic SI occurred prior to the manual operation; however, the operators continued with the manual ar*=tian De operators then agavydately re entered their EOPs at this time without further error. 1 i
i 45 .I In addition to the above, the AIT also identified the following two concerns regarding operator j actions: 1 During the down power transient, the senior shlA supervisor, also SRO<gualined and the senior i j managemen' representative in the control room, lea the control room aren to bypass a condenser i vacuum permissive switch in an attempt to restart one of the inoperable circulating water pumps, j hoping to restore adequate cv-lanear cooling. 'Ibe ATT concluded that this was an inappropnate l work activity and alao, poor judgement on the senior shiA supervisor's part to leave the control i room during the transient. " AAer the initial safety injection, the unior shiA supervisor leR the control room proper in order to classity the event and initiate aasiacania== per the emergency plan implemandas procedures. l While this activity was timely, the initial ansiacanian message developed for a - .. ..'- r j j pewided sninimal infornction to the NRC in that it failed to describe the naagdicariaan that had MusM. i
- Management allowed %=6 " probleen to adst that made .i # r-- difttcult for l plant operstors.
- 1. 'Ite AIT found that during this event and for about a month prior to the event, that the automade rod control system was not in service. ' Ibis led to the operators having to i
manually control reactor power to maintain RCS T., within program. 1, j During the event of April 7,1994 the operators initially decreased turbine power at 1%/ minute, but quicidy inciensed that rate change to a mavi=== of 85/ minute. At this rate of change, even the autamane rod control system would not have been able to maintain T in program without operator action to assist by bosation. With the rods in l manual, as was the case, operator action in response to the 85/ minute rate of change i was very dif6 cult. l ' ! 'Ihe AIT noted that PSB&O management was addressing the ==ta==*ic rod control sysaan problem and that, in fact, the control system was available at the time of the l l event. However, operadoes management had not yet natond the system to service since l j a Snal survediscos test had not been completed. 'that test had been Mtant for the j day of the event.
- 2. 'rhe AIT found that the short duradon, high steam now signal, nautting Ace the turbine
- l trip, had been previously identiSed by the licenses following prior post-trip reviews conducted aAer similar turbine trips in the past. Inforandon gewided the Art indicated 4
this condition had been recognized as enriy as 1989. 'Ihe high steam flow signal was of j j very short duration, on the order of 20 to 30 millineennda, and appeared about I seco aner the turbine trip. While this condition had been recognized previously, the licensee l attributed the cause to be a combination of the logic (the reactor trip automatically i reduas the high steam flow setpoint from about 110% to about 40% of rated steam flow) l
} }
l 5 4 4
[ 4 i j 46 1 { and the actual decay in steam flow following a reactor trip-turbine trip. Upon closer analysis following this event, the licensee identified that the actual cause of the indicated high steam flow signal following a turbine trip cuis@ to a pressure wave initiated i by the turbine stop valve closure. De Arr concluded that this pressure wave did cause the indicated high steam flow, and, aaiaridaar with the low T,. condition induced by operator error, resulted in the initial mammaatic safety le#ction accussion. De Arr further concluded that earlier licensee
- ! manaaemant ofindie=aad high steam flow .dber tubine trips was inadequate in that it faded i j to identify this machmaiam and therefore the problem remained uncorrected.
1 i 3. De Arr found that the ma*=aatic controls for steam generator atmosphes relief valves j were not malan=ia=d Dis, raineidant with the operators failure to recogniae that RCS l and steam generator temperature and pressures were increasing after the initial safety 1 injection, led to the steam generator code safety (s) actuation and resultant second safety injection actuation. The atmosphenc relief valves (MS10s) control system had been l madinad in the late 1970's, which resulted in the controls not responding properly in i automatic without operator action. Plant operators had been trained to make up for this i dam 7 y placing b the system in manual for a few seconds and then restoring the i system to automatic. His would result in the control system then working properly. During the events of April 7,1994, the opeestors failed to take adequate manual control l of this system prior to pressure iiw.A to the lift setpoint of the steam generator code 4 safety (s). De Arr determined that the control system for the MS10s was known to be deficient. 1 Madineatiana had been planned, but never i=i' to correct these conditions and ; operators had been =aaa=d, through training, to mais up for the control deficiencies i by manual actions. 1 1
- 4. De Air found that the cireid=*ian wata symern was vulandde e periodic grass intrusicas. His had been daen=anand by the licenses for a number of years. Records indicating that this condition was especially aggravated in the spring of 1994 were provided the to Arr. However, tbs r' -7 had 7been previously recognised by the r licensee and madinarians had been planned to make the synne less macepuble to grass ;
intrusions. Dame madinatiana had not been implamanand prior to the event. During i the spring of 1994, as the river grass conditions worsened, the licensee began to initiate special work teens and work controls at the circulating water structure in response to the predicialde grass intrusions that occurred coincident whk daily tide changes. Dese special practices were edes effective at mapanding to the degrading circuladag water conditions and usually resulted in restoring inoperable traveling acreens and circulating water pumps without the need for control reorn operators trippmg the turbine or reactor. The Air noted that on one occasion prior to the April 7 event, opersso:s had been forced to remove the turbine from service as a result of a grams intrumon; but, the remetor was maintained in low power operation. No further camplicanaan had aM on that
S 47 l event. It was also noted by the AIT that the event of April 7 was apparently more severe ! than enriier events, resulting in operators decnnsing power at a maximum of 815/ minute. l This was done to reduce turbine power fast enough to minimize the increasing back pressure in the aandanear. The prior grass intrusion events did result in operators frequently reducing power to maiatmia aarvianear vacuum, while the special work activities at the circulating water structure restored inoperable circulators. However, no f prior event required such a high rate of change in power to compensate for the loss of circulating water. [ The AIT determined that the grass intrusion event of April 7 was very severe; however, the vulnerability of the design was previously recognized and modi 6 cations to improve
- the system had not yet been i=F" e same equipment was degraded by the event, but overall, the plant perfonned as designed.
1he AIT observed the licanmaa's troubleshooting efforts. It was noted by the team that certain valves for the safety iq)ection systems, containmant isolation systems, feedwater isolation system, and steam line inalmeiaa system did not respond in the usual manner to the initial automanc safety injection armadasi. This was a result of the short duration of the initiating signal, which was only of sufficient duration for parts of the protection logic to respond, resulting in the unexpected behavior. However, functional testing of the protection logic clearly indicated that it would have performed properly in response to real accident canditiane had they l l been present. 'Ibe AIT further concluded that licenses troubleshooting awehade clearly ' damanstrated the logic responded as would be expected to the short duration signals. The AIT determined that the plant neponse to the event was as expected for the naadidans that occurred. The troubleshooting enorts clearly damaa=*'ated that the proescalon logic response, as well as the response of the main steam and feedwater isolation systems, were a direct result of instrument sensitivity and response behavior to short duration signals. Test %g demonstrated tha consistaat, predictable behavior could not be achieved unless the input signal lasted longer about 50 miniennnada The vulnerability of the protection system to short duration signals had not been y.My idantiflad or evaluated by the licenses prior to the April 7 event. Due to the repeated operation of the pressuriser PORVs, the AIT requesend, and the limnsee completed an assessment of the PORVs, pnesuriner code afety valves and manaan'en supports.1he licenses and NRC inspected the PORY laternals, which exhibited wear r further evaluation and corrective action prior to restart. I As a result of the troubleshooting activities, other equipment naadidaan restuiring repairs were also identified, including the PRT rupture disk, main steam high steam flow input relays various MS10 control components. l
48 e Operator use of emergency procedens was good. The AIT determined that the operators' use of the BOPS in maponse to the multiple automatic safety injecnon actuatens was good; however, some errors happened after entry into the EOPs.
'Ihe AIT found that operators were not yacine=Hy knowledgeable in the use of EOP ' Yellow Path" procedures for solid plant recovery. "Youow Path" symem fimcdon ressoration procedures are opdonal in the Malem EOP eriwsaa; but, for this event and the solid plant condition, no ahernative procedures had been provided. Knowledge, training and practice in the use of "Yeuow Path" procedures could have aided the operators earlier in the recovery of the pressuriser nanam space fonowing the multiple SI aca=*ia==
Operator actions to manually initiate SI on rapidly decessing RCS pressure and in declaring the Alert to ensure appropriate engineering support for plant recovery from the solid RCS condition were considered appropriate by the AIT. Prior to entry into the EOPs, the operators committed a number of errors dealing with command control and coordianhaa of the downpower transient. Most of these errors could have been avoided if appropriate guidance had been developed and implemented in the normal integrated operating procedures and in the abnormal or alarm response procedures. e um-ana investigations and troubleshoottag eEasts were good The AIT closely monitored the limaea*'s troubleshooting activities' pad, to a lesser extent, the licensee's indT=daat investigation. Based on the direct observation of the logic testing and other troubleshooting activities, the Art determined that the licensee approach was clearly to ascertain the root causes of the events of April 7, idendfy necessary corrective actions and then implement such measures. However, it was noted by the AIT that the lia=== was prepared to accept the operability of the presariser PORVs without a visual inspeedon of the components. The AIT asked for the necessary engineering evaluation of the PORVs upon which the licensee was to base their operability a*aaaamaat Prior to developing this evalension, the limanae then elected to open the components for a visual lamparolaa '11ds led to the Sadings of the degraded PORV internals resulting from the event. While this speciSc activity was not pursued rigorously by the tit-meae without NRC prompting, this was not indicative of the other troubleshootmg activities observed by the AIT.
'Ihe AIT met with members of the licensee's investigation anun to discuss pediminary findings, and, reviceed the operations post trip report and the itivestigation report. Information gathered from these repons was useful to ttm Art ==- Purther, the licensee's sequence of events and facts supporting the event sequence war; found to be consiseent with the AIT's. 'Ibe Arf concluded that there was evidence of noteworthy management oversight and conaal weaknesses due to the coincidence of equipment issues, both recent and historical, operator errors and procedural guidance deficmocies that all contributed significantly to the April 7 event. In contrast, the licensee westigations placed.a greater *mahaaia on the vyweior errors in contributing to the e. The AIT noted that the liceawe's investigation did not attempt to
l l 49 ! ascertain why the operator errors occuned, but identified the errors as root cause. However, it was also noted by the AIT that licensee's recomnaled corrective actions clearly addressed the equipment and procedural deficiences that contributed to the event. g.0 EXIT MEETING On April 26,1994, the AIT conducted a public exit meeting at the site discussing the inspec scope and preliminary findings. ne exit meeting slides were pewided so the public and m an omeial record under asparase w,Cas to the licensee, dated April 26,1994. De attendees at the exit meeting me listed in Attachment 6. Following the public meeting, the AIT me with and responded to questions from the public and media representatives in anemiarx:e.
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i 4 ATTACHMENT I AIT CHARTER i
- April 8,1994 i
i j MEMORANDUM FOR: Marym W. Hodges, Director, Division of Reactor Safety 1
]
i j FROM: Domas T. Martin, Regional Adminierrator l
SUBJECT:
AUGMENTED TEAM INSPECTION CHARTER POR THE i REVIEW OF THE SALEM UNIT NO.1 REACTOR SCRAM , AND I4SS OF PRESSURIZER STEAM BUBBLE i ! ] On April 7,1994, Salem Unit No. I reactor scrammed from 255 power during maneuvers to ' ! shut the plant down. Subsequent to the reactor scram, the plant experianced a series of safery injections which resulted in loss of the pressuruer steam bubble and normal pressure control. il In addition > the reactor trip and safety injection, certain valves that are required to operate, j failed to close. Rarmuw of multiple failures in safety related systems during the event and
- possible operator errors, per M.C. 325, Paragraph 05.02, Item a, I have determined that an j Augmented Inspection Team (AIT) should be initiated to review the causes and safety
- implications associated with these malfunctions.
The Division of Reactor Safety (DRS) is assigned the responsibility for the overall conduct of this augmented inspection. ' Robert Summers is appointed as the AIT leader. Other AIT members are identified in Enclosure 2. De Division of Reactor Projects is assigned the responsibility for resident and clerical support as necesary; and the coordination with other - NRC offices, as appropriate. Further, the Division of Reactor Safety, in coordinatian with DRP is responsible for the timely issuance of the law report, the identification and processing of potentially generic issues, and the identification and completion of any enforcement action warranted as a result of the team's review. Enclosure 1 represents the charter for the AIT and details the scope of the inspection. De inspection shall be conducted in accordance with NRC Management Duective 8.3, NRC - iaWon Manual 0325, inspection Procedure 93800, Regional OfHoe Instruction 1010.1 and this memorandum. ORIGINAL SIGhD BY: William F. Kane for Domas T. Martin Regional Adminierrator Feinwnres: ~
- 1. Augmented vaWon Team Charter l
- 2. Team Composition I Al-1
- ATTACHMENT 1 AIT CHARTER ENCLOSURE 1 AUGMENTED INSPECTION TEAM CHARTER 1he general objecdves of this AIT are to:
- 1. Conduct a thorough and symmarie review of the circuane=== surrounding the mactor scram at Salem Unit No.1 on April 7,1994 and the resuldag loss of the pressuruer steam bubble.
- 2. Assess the operators' actions preceding and subsequent to the reactor scram. Develop a sequence of events and events causal factor analysis for the plant and operators' responses and human factors associated with the event. Compare the expected plant response to the actual plant responses.
- 3. Review the licensees event classification and notifications for .yyivyriate responses.
- 4. Assess the safety significance, of the event and communicate to the regional and headquarters management the facts and safety concerns related to problem identified.
- 5. Examine the equipment failures and identify anacintad root causes.
- 6. Determme if any design vulnerabilities or deficiencies exist that warrant prompt action.
- 7. Prepare a report documenting the results of this review for the Regional Administrator within thirty days of the completion of the ia@.
Schedule:
'Ihe AIT shall be diPM to Salem so as to arrive and commenen the inspeedon on April 8, 1994. During the site ponion of the inspection resident and clerical support is available.
i Al-2
I ATTACHMENT 1 ! AIT CHARTER ENCLOSURE 2 TEAM COMPOSITION The assigned team members are as follows: Team Manager: Wayne Hodges, DRS Onsite Team Lander: Robert Summers, DRP Onsite Team Members: Steve Barr, DRP Scott Stewart, DRS Larry Scholl, DRS Warren Lyon, NRR ( Iqbal Ahmed, NRR John Kauffman, AEOD Richard Skokowski, DRS
- Howard Rathbun, NRR ;
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1 ATTACHMENT 3 CONFIRMATORY ACTION LETTER April 8,1994 1 Docket No. 50-272 Ucense No. DPR-70 CAL No.1-94-005 Mr. Steven E. MilAgg Vice President and Chief Nuclear Officer Public Service Electric and Gas Company P.O. Box 236 Hancock's Bridge, New Jersey 08038
Dear Mr. Miltenberger:
SUBIECT: CONFIRMATORY ACTION LEITER 1-94405 On April 7 and 8,1994, in telephone discussions, WHliam Kane, Deputy Regional Administrator, informed Mr. Joseph Hagan, Acting General Maa=r, Salem Nuclear Generating Station, of our han to diana'eh an Augmented Inspection Team (AIT) to review and evaluate the circumstances and safety significance of the Unit I reactor' trip and safety LaWa that occuned on April 7,1994. The event was a~aak and snay have inv51ved personnel error, equipment failure, or a combination of both. The AIT was initiated because of the complexity of the event, the uncertainty of the root causes of some of the enaditions and equipment problems encountered durmg the event, concerns relative to the proper # -Wag of enAt safety features, and possible generic implications. The AIT, led by Mr. Robert Summers of our officz, is araa-w to commence their activities at the Salem Nuclear Generating Station on April 8, 1994. In response to our request, Mr. Hagan agreed to place Salem Unit 1 in a cold shutdown condition and maintain that condition until the AIT acquired all the information needed for their muermement and was rtisfied that any necessary conective mensmes have or would be taken; and that your staff would take actions to:
- 1. Assure that the AIT Imader is cognizant of, and agrees to, any resumption of activities that involve the operation, testing, mainwanana, spair, and surveulance of any equipment, including protection logic or =aciad components, which failed to properly actuate in response to the reactor trip and safety insection(s) of April 7,1994.
- 2. Assemble or otherwise make available for review by the AIT, all documentation l
i A3-1 l l l
ATTACHMENT 3 CONHRMA10RY ACTION LETTER 0-'ui g analyses, assessments, reports, procedures, drawings, Persormel trammg and qualification records, and correspondence) that have pertmence to the equipment problems leading up to the reactor trip and safety isljection(s), and subsequent operator response and recovery actions.
- 3. Assemble or otherwise make available for swiew by the AIT, all equipment, assemblies, and components that were associated with the problems encountered during the events lendmg up to, and subsequent to the reecear trip and safety inliection(s).
- 4. Make available for interview by the AIT, all personnel that were associated with, or have information or knowledge that pertains to the problems encountand during the events leading up to, and subsequent to the reactor trip and safety isljection(s).
- 5. Gain my agreement prior to commencies any plant startup.
Pursuant to Section 182 of the Atomic Energy Act,42 U.S.C. 2232, and 10 CFR 2.204, you are hereby required to:
- 1. Notify me immediately if your understandmg differs from that set forth above.
- 2. Notify me, if for any reason, you requite modification of any of these agreements.
Issuance of this Confirmatory Action Letter does not preclude leenaana of an Order for'=alMag the above commitments or requiring other actions on the part of the liaaneae, nor does it preclude the NRC from taking enforcement action if vialadame of NRC regulatory requirements are identified through the actions of the AIT. In addition, failure to take the actions addressed in the Confirmatory Action Letter may result in enformment action.
'Ihe responses directed by this letter are not subject to the clearance procedures of the Office o Management and Budget as Jequired by the Paperwork Reduction Act of 1980, Pub. L. 96 511.
In accordance with 10 CPR 2.790 of the NRC's " Rules of Practice,' a copy of this letter will be placed in the NRC Public Document Room. We appreciate your cooperation in this matter. Sincerely, ORIGINAL SIGNED BY: William F. Kane for:
'Ihomas T. Martin Regional Administrator A3-2
3 ATTACHMENT 3 CONFIRMATORY ACTION L1:a am ec: J.J.Hagan. Acting General Manager - Salem Operatiom l C. Schaefer, External Oprations - Nuclear, Delmarva Power & light Ca l S. IaBruna, Vice President - Engineering R. Hovey, General Manager - Hope Croth Operations ' F. Thomson, Manager, I haia = and Regulation R. Swanson, General Manager - QA and Nuclear Safety Review J. Robb, Director, Joint Owner Affairs A. Tapert, Program Adminierator l R. Pryling, Jr., Esquire ,,, l M. Wenerbahn, Esquire l P. J. Curham, Manager, Joint Generation Department, l Atlantic Electric Company ah ! Consumer Advocate, Omoe of r== mar Advocate < i William C Wa, Public Safety Consulkit, Imer A9oways Creek Township l K. Abraham, PAO (2) . Public Document Room (PDR) l 1.ocal Public Docun'!cnt Room (LPDR) Nuclear Safety Infonnation Center (NSIC) NRC Resident Inspector State of New Jersey l .__ 9 l I i
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( ATTACHMENT 4 ] _ SEQUENCE OF EVENTS 1 DETAILED SEQUENCE OF EVEN'IS i i Anr2 7 199( j Pre-transient initial ocnditions: Unit 1 power at 73%, rod QJntrol in manual. 0730 12A circulator out of service for waterbox cleaning. l l- 1016 13B cirM-de water pump emergency trip on travelling screen differential pressure; 13A,13B and 12B travelling screens all clog and eventually go out of service. ] 1027 13A circulating water pump trips on high screen differential pressure. ) 5 1032 Unit 1 operating crew initiated a plant power reduction from approximately 650 MWe - at 1% power per minute initially (up to thir point, plant powefhad decreased from 800 MWe due to an increase in condenser back pressure). Subsequently, operators increased ) - the reduction rate to as high as 8% per minute. i ..- l 1034 Operators attempt to restart 12A ciMad5 water p::sp; pump immediately trips due to - pump circuit breaker not being fully racked in.
- 1039 P-8 permissive (nactor trip on low coolant flow in a single loop) neet @ locked) at 36%
-l reactor power. j By this time, all circulating water pumps except 128 have tripped, 13A and 13B are , l j restarted, but by 10:44,they have tripped again, leaving 12B as the only circulator in l service. 1043 P-10 pennissive (power range low setpoint renceor trip and intermadimw range reactor trip and rod stop) reset (rda=*=11ad) at 10% reactor power. j i At about this time, the Nuclear ShiA Supervisor (NSS) directs the Ranctor Operator (RO) at the rod control panel to go to the elecuical distribution panel to perfcfm group bus
- transfers.
1044 Turbine load at 80 MWe, RCS 6 .g.s at 531 degrees F. Low-low T bistable actpoint Tech Spec allowable value 2:,541 degrees F, therefore low-low T , bistables trip. 1 . i A4-1
)
4
W ATTACHMENT 4 SEQUENCE OF EVENTS 1045 The NSS begins to withdraw mds, and then the RO is directed by the NSS to return to ! the rod control panel and withdraws rods to restore RCS temperature - rods pulled 35 steps, from step 55 to step 90 on control rod bank D. . 1047 Reactor power increases frorn 7% to 25% due to the outward rod monon - reactor trips at 255 power range low setpoint. This is a " reactor startup" nuclear instrument (NI) trip. 'Ihe NI " intermediate range" 205 power rod stop and 255 power reactor trip did not actuate. ! 1047 Autarnatic safWy La, Won (SI) on high steam flow aaiarWs* with low-low T . All ECCS pumps start, ECCS flow paths inacrian=I, main feedwater regulating valves close. l i No "first out" alarm was received for the St. SI signal received on SSPS logic channel l "A" only. I 1049 Operators enter EOP-Trip 1 procedure. n 1053 Operators manually initiate main feedwater isolation. 1058 Operators manually initiate main steam isolation (only 2 of 4 main steam isolation valves closed at the time of the auto-initiation of SIX - ' " - Operators manually trip main feed pumps. 1100 Ucensee declared an Unusual Event, based on: " Manual or Auto ECCS actuation with l dieharge to vessel" . ; I 1105 EOP exit-step 36 directs operators to reset SI; operator notices SIlogic chmanal "B" was already reset (indicatad that "B" chmanal had not auto-initiated) and a flashing light on the RP4 panel (indicatai SI logic chanaal disagreement). 1118 Pressurizer PORVs (PR-1 and PR-2) subsespently periodically auto open on high pressurizar preenne (indicated pressuriser was fil&q to solid condition). A4-2
. - . - - . - - . - . - . - ~ . - _ . _ - _ - - - - - - . - - -
~
j l ATTACHMENT 4 SEQUENCE OF EVENTS 1 During Ecacy, steam generator atma akaric relief valves open several times to control l
- secondary temperature and pressure.
} Number 11 and/or Number 13 steam generator safety valves open, causms RCS
- j. cooldown (by this dme T had increased to about 552 degrees F). This ladic=*ad that i the steam generator atmospheric relief valws were not properly controlling pressure.
I t 1126 Second actual automatic safety injection - initiated by low presariser preamre (Iow i.
- pressurizer pressure trip setpoint= >1765 psig, allowable > =1755 psig). I.ow j pressurizer pressure due to RCS cooldown (due to steam generator code safety valve j going open).
1 i Second auto SI received on SSPS logic channel "B" only. Operators initiate a manual SI j just after auto SI, in response to the rapidly decreasing RCS pressure. i 1141 While resetting the second SI, operator notices ti.at RP4 panel lights indicate SI logic channels in kgreement (i.e., light no longer flashing). i l Technical Specification Action Statement (TSAS) 3.0.3 entered due to two blocked auto
- SI trains. -
! 1149 Pressuruer relief tank (PRTumture disk rug.i (pressuriser was either solid or nearly _ ! solid after the first auto-initiated SI at 1047, and the second auto-initiated SI resulted in i sufficient relief of RCS to the PRT to raise level and pressure until rupture disk blew). 1316 Alert declared. This was done to ensure proper eachnient staff was available. Licensee staffI-id hat TSAS t 3.0.3 could not be met for inoperable SI logic channele lhe
- operators were also concerned about how to properly restore the pressuriser to normal pressure and level control from solid RCS conditions and wanted sufficient engineering support.
1336 The NRC entered the monitoring phase of the Normal Response Mode of the NRC i facidaat Response Plan. NRC Region I activated and staffed their Incident Pa=aaa** . Center, with support provided by NRC headquarters personnel. 4 1410 '!)e Technical Support Center was staffed to assist control room operators with recovery l j of normal RCS pressure and level control. l 1511 Operators restore pressurizer bubble. i 1630 Pressunzer level restored to 50%, level control returned to auto. EOPs exited,10P-6 i 1 A4-3 1 1 1 1
I ATTACHMENT 4 SEQUENCE OF EVEN% (Hot Standby to Cold Shutdown) procedure entered 1715 Plant cooldown initiated. 2020 Alert terrninstad. Anril S.1994 0106 Mode 4 (Hot shutdown) entered. G .. 1124 Mode 5 (Cold shutdown) entered. - fI i n e G w
/6 a r- .S ?
On Cf W" A4-4
ATTACIDIENT 5 LIST OF ACRONYMS i AIT Augmented faWon Team i CDF core damage frequency CETPS core exit thermocouple processing system CW cimitadag water j DNBR departure from nuclease boiling ratio EPRI Elecaic Power Research Institute ESF =pW safety features actuation FSAR Final Safety Analysis Report GL generic letter IPE Individual Plant Evaluation LOCA loss of coolant accident MPA multi-plant action NRC Nuclear Regulatory Commission NRR NRC's Office of Nuclear Reactor Regulation . PRA probabilistic risk assessment PRT pressurizer relief tank PORV pressure operated relief valve i PR. . . PRI, PR2 are pressurizer PORVs; PR3 - PR5 are pressurizer safety valves . RCP reactor coolant pump RCS reactor coolast system ' RHR residual heat removal _ RVLIS Reactor Vessel Level Indication System RV reactor vessel SCM subcooling margin SER safety evaluation report SG steam generator l SI safety issection actuation l SIS safety iqjection system ) SSPS solid state protection system l I SW service water VCT volume control tank A5-1
ATTACHMENT 6 (. EXIT MEETING ATTENDEES NAME TITLE Nuclear Regulatory Commission (NRC) Iqbal Ahmed Senior Electrical Engineer, NRR Stephen Barr AIT Assistant Team Leader, Division of Reactor Projects (DRP) M. Wayne Hodges Director, Division of Reactor Safety (DRS) John Kauffman Senior Reactor Systems r nf , ABOD Wanen Lyon Senior Reactor Systems Fmp , NRR larry Scholl Reactor Emp=, DRS
- Richnd Skokowski Reactor Engineer, DRS J. Scott Stewart Reactor Engmeer - Fmaminer, DRS
, Robert Summers AIT Team Leader, DRP Edward Wenzinger Chief, Projects Branch No. 2, DRP
.e.
i Public Service Electric and Gn Comnany /PSFAG) R. Dougherty Senior Vice President - Electrical l J. Hagan Vice President, Nuclear Operations & General Manager, Salem Operations . S. LaBruna Vice President, Nuclear Engineering l S. Miltenberger Vice President and Chief NuclearTHficer j l F. "Ihomas Manager, Nuclear licensing . A6-1
ATTACHMENT 7 MGURES MGURE1 - PORY Design Drawing MGURE 2 - RCS Pressure Response MGURE3 - Salem and Hope Creek CW and SW Layout MGURE4 - Salern CW Drawing MGURE5 - Salern SW Drawing MGURE 6 - Hope Creek SW Drawing i l . 4 erm I s-A7-1
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1.7 - 3.0 1.5 11:30:18 12:20:18 13:10:18 14:60:18 14:50:16 15:40:18 Time Figure 2. Reactor Coolant System Pressure
i i . 2 l ATTACHMENT 7 i i } - SALEM CW A / J aw . .. l - 2,.. g t.x
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A'ITACHMENT 7 s
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~
ENCLOSURE 2 State of New Jersey Department of Environssental Procedian and Energy Division of Environmental Saesty, Health and Analytscal Programs pobert C. SNnn. Jr. Radistson M Programm ( C. ...i ' = L' CN 415 Trentnn, N.J. 08625-0415 Tel (609) 987-6389
- Fax (609) 987-6390 I
l May 20, 1994 Mr. James T. Wiggins, Acting Director Division of Reactor Safety U.8. Nuclear Regulatory Commission 475 A11enda3a Road King of Prussia, PA 19406
Dear Mr. Wiggins:
Subject:
Salem Unit 1 Augmented Inspection Team In accordance with the provisions of the July 1987 Memorandum
- of Understandir.g between the Nuclear Regulatory Commission (NRC) and and the New Jersey Department of Environmental protection Energy (DEPE), the DEPE is providing feedback regarding the April 7, 1994 Alert at Salem Unit 1 and the subsequent NRC Augmented Inspection Team (AIT). As youobserved know, the New Jersey DEPE's Bureau part of the performance of of Nuclear Engineering (BNE) the AIT. In keeping with the spirit of the agreement between the DEPE and the NRC, the DEPE will not disclose its inspection observations to t.he public until the Natc releases its final AIT report.
This participation was especially valuable for our nuclear It allowed us to gain immediate understanding engineering staff. of the actual events andThj,s plant conditions leading to the Alert declaration on April 7. information has been shared with DEPE management. Our representatives were impressed with the diligence of the AIT members and their ability to expeditiously sift through
' a complex series of events. ourThe AIT Team Leader was extramely representatives
- questions and cooperative and open to concerns. All tetos members had inquisitive attitudes, allcwing for effective information gathering from PSE&G and analysis within the team.
Y hWW h, . J}Ll090%6S] hp . . . . . .
Page 2 We are continuing to review all concerning the Alert. available information consistent with our observations of the AIT.Overall, the information we have seen is The May 10, 1994 internal Mr. memorandum from Mr. Martin, NRC Regional Administrator, to Taylor, NRC Executive Director of Operations, clearly described interviews. the chain of events and the results of the operator We have two specific subjects we have not seen addressed. general in the information made available to date and we have one concern. flow signals have been experienced before at Salem Units 1 and 2.F We understand problem as well.that other Westinghouse units have experienced this We are concerned that these past spurious signals have not been shared within the industry or if it was shared, there may be a weakness in PSE&G's ability to evaluate industry experience. follow-up through the inspection Frocess.If the AIT is not assessing this matter, we re Second, following the first safety injection on April 7, operators reported that trouble alarms were received on all three diesel of the generators and an urgent trouble alars was received on one diesel-generators. generators. An SRO was dispatched to the diesel-alarm which was He found all diesels operating properly and reset the attributed to low starting air pressure. We reocquise of declaration this theisAlert. unrelated to the events that led to the existswith, cope with the diesel-generators that operators have learned toHowever, it may in certainly, responding to an urgent trouble alarm in an emergency situation is a distraction that should be avoided. in statements nade by NRC senior management and the results of theT previous two SALP periods. standing cultural and equipment problems at salem Units 1 and 2.NRc has expresse The theseresults of the previous SALp reports are not consistent with observations. improvement. In fact the latest SALP tt indicates some process to reflect concerned We are over the off the true assessment of this of utility's veness the SALP performance. time. Perhaps we could discuss this issue at an appropriate
. l
. . l l
Page 3
- If you have any questions, please contact me at (609) 987-2189.
j ly,
.i f
1 Anthon J. McMahon Acting Assistant D or, ! Radiation Protection Element, DEPE i c Kent Tosch, Manager, DEPE
- Dave C21awaga, SI4, NRC Attachment DEPE/NRC MOU 1
i l
I
~ .
j A T rIAC M m s m E ft4 87 15311 NRC KING OF PRUSSIA-2 P02 i -
/ess ee ,,**e usersp aTAtes i 5* **,.
1 1 NUCLEAM REGULATOMY COMM18310N
- naGION 8 e, f est*Anaavsmus g e .e . */ me=e er enuassa. resvevevt.vania ie.ee i
i Afchard T. Dowling. Pn.0. 4 P.E. Cometastener i Department of Ent'ironmental
- Protection i
a01 East State Street i CN 402 j Trenton. New Jersey 08625 e
Dear Commissioner Dowling:
j This letter is to confirm the general agreement reached as the result of our
- meetings with Dr. Serkowitz and his staff regarding the surveillance of the i
nuclear power plants operating in New Jersey. During those meetings we agreed that there was a need to have a more formal way of coordinating NRC and State activities related to plant operations and that the Department of Environmental Protection's Bureau of Nuclear Engf recering (SNE) will be the int'erface with .the NRC on a day-to-day basis. 1 I l The areas addressed by this letter are: - I
- 1. State attendence at NAC meetings with licensees relative to licensee performance, including; enforcement conferences.
, plant inspections and 11 censing actions.
- 2. NRC and $NE exchanges of information regarding plant con-ditions or events that have the potential for o- are of
- safaty significance.
We agree that New Jersey officials may attend, as observers. NRC enforcement l , conferences and MAC meeti 5 with Itcensees, including Systematic Assessment of Licensee Performance ($ ALP reviews, with respect to nuclear power plants ; } operating in New Jersey ( E44. GPUN). We shall give timely notification to i i the SNE of such meetings, including the issues expected to be addressed. j Although I de not espect such cases to arise frequently, we must reserve the
- right to close any enforcement conference that deals wtth highly sensitive
- safeguards material or information that is the subject of an ongoing investi-i gation by the NAC Office of Investigation (01) where the premature disclosure >
- of information could jeopardite effective regulatory action. In such cases, we j would brief you or your staff after the enforcement conference and would j
1 expect the State te maintain the confidentiality of the briefing. l With regard to NRC inspections at nuclear power plants in New Jersey, we agree j that the SNE staf f may accompany NRC inspectors to observe inspections. To the
- extent practicable, NRC will advise the. State sufficiently in advance of our i inspections such that State inspectors can make arrangements to attend. In j
order to assure that those inspections are effective and meet our mutual needs. j ! suggest the following guidelines: 1 1 h 4 u. 1 4 J
. _ . . _ . _ . ~ . . _ _ _ _ . _ _ _ _ . _ . _ . . _ _ _ . . _ _ _ _ . . _ _ . _ P03 14 '87 15811 HRC KING OF PRUSSIA-2 2 a
- 1. The State of New Jersey will make arrangements with the IIconsee to have New Jersey participants in NSC inspec-tions trained and badged at each nuclear plant for unescorted access in accordance with utility reevirements.
- 2. The State will give NWC adequate prior notification ween planning to accompany NRC inspectors on inspections.
- 3. Prior to the release of MMC inspection reports, the State will exercise discretion in disclosing to the public its observations during inspections. When the conclusions or observations made by the New Jersey participants are sub-stantially different free these of the MAC inspectors,
.New Jersey will make their observattens available in writing to the NRC and the Itcensee. It is understood that these cosseunications will become publicly available along with the NRC inspection reports.
With regard to communications, we agree to the following: ,
- 1. The NRC shall transmit technical information to SNE relative to plants within New Jersey concerning operations, design, external events, etc.; for issues that either have the potential for or are of safety significance, ,
- 2. The NRC shall transmit all Preliminary Notifications related to nuclear plant operations for New Jersey facilities to the 1 8NG routinely.
- 3. The SNE shall communicate to the NRC atty concern or question regarding plant conditions or events, and any State information about nuclear power plante.
Please let me know if these agreements are satisfactory to you.
~
5iacere1y', 676 at William T. Russell Regional Administrator
1 s e a%
*, UMTED STATES ENCt.05URE **
[ g NUCLEAR REGULATO2Y COMMISSION a nEo oN
- s i
- 475 ALLENDALE ROAD KING oF PRUSSIA. PENN$YLVAMA 13e061415 l
j " ..... Docket No. 50-272 g 2 41994 i j Mr. Anthony J. McMahon j Acting Assistant Director i Raaannn Protection Element i State of New Jersey Department ! of Environmental Protection and' Energy l CN 415 ) Trenton, N.J. 08625-0415 1 I
Dear Mr. McMahon:
SUBJECT:
CORRESPONDENCE DATED MAY 20,1994 REGARDING SALEM f J ] UNIT 1 AUGMENTED INSPECTION TEAM 1 i j 'Ihe purpose of this letter is to thank you for forwarding the menamenwne of the AIT activities that l were observed by your representatives and to address the concerns you raise in the subject letter. j We were pleased with the generally favorable remarks you made regarding the conduct of the l AIT. 1 ) Your letter provided three issues for our consideration, which you did not believe were being addressed at the time of the AIT. You are correct in that the AIT did not address these issues. Our plans are outlined below. Your first issue addressed past industry e@nce related to spurious high steam flow signals and raised a concern about PSE&G's abihty to evaluate such industry experience. In reply, the AIT did not assess this issue directly. Also, while the PSB&O 1%* investigation did ! address operatmg experience f=tharir no assessment of this specific issue was made.
'Iberefore, NRC will follow up on this issus during a futme inspection and will ensure that the
- findings are documented in an inspection report. More generally, the AIT finding regarding the
! vulnerability of the high steam flow instruments is being reviewed by NRC management for j possible generic communications to the is sy. j Your second issue addressed the trouble and urgest trouble alarms received on the emergency i diesel generasar (EDG) following the first safety insection actuation ce Aprd 7,1994, and raised two concerns regarding: operators learning to cope with existing problems; sad, distraction of operators by nuitmar* alarms during emergency sia=* lane In reply, the AIT did not a-**"y review the causes of the EDG alarms. 'the alarms were investigated by the licensee and the findings of that investigation v-e discussed with the NRC. The cause of the urgent trouble alarm was a defective air receiver outlet low pressure switch, which was replaced. The cause(s) of the other trouble alarms was not identified; but, additional future monitoring of these alarms during EDG starts is planned. Future NRC inspections will evaluate the licensee efforts to identify the specific cause(s) of the trouble alarms. Regarding your concern about operators
JUN 2 4 Gd Mr. Anthony J. McMahon 2 learning to cope with existing problems, the AIT does address this issue for different examples of pre-isting equipment problems. This matter will be followed up as a result of the AIT findmgs. Regarding your other concern about the potential distraction of operators during emergency conditions, NRC agrees that this should be avoided, if posable. Our view is that all indicators, including alarms, should be assumed to be cormet and appropriately responded to. If the alarming condition is subsequently found to be defective, then appropriate corrective acions should be taken. In this case, corrective actions have been taken for the urgent trouble alarm. If future testing identifies the cause(s) of the other trouble alarms, we will ensure appropriate corrective accons by the licensee are taken. Your final issue addressed a percephon involving an apparent incarinistency in erntements made by NRC senior management regardag "long-standing cultural and equipment problems at Salem Units 1 and 2," and the results of the previous two SALPs. The NRC reviews licensee performance on a continual basis. This is accomplished through SALP, through routine assessments in support of NRC Senior Management Meetings and through inspections. 'the SALP, by its nature is a very broad and pdvsssce-based assessment, but is focused on performance observed during the SALP period. The conclusions drawn in the SALPs were based on information gathered during their respective SALP prviods. Recent NRC fiWings, including the AIT findings, and discussions by NRC management are factors that are considered in our curant assanament- 'Ihese findings, as well as other information that NRC management gathers through inspection and licensing activities and management reviews that occur periodically, are all piavr'dy considered in the continual NRC =====maat of performa. :e. We would expect to include the results of our current annennment in the next SALP report. We understand how your review of the past SALP mports can lead to the partspti6ii you developed. Although infrequent, it is not uncommon that we would also see diffenoces between past SALP assessments and current performaann of licensees. "Ihose differences have typically resulted either from significant changes in the licensee's processes or organization, or from more defined insights gained by us through our ongoing programs. In the case of Salem, I suggest both circumstances were at work. If you would like to discuss this process further, we would be glad l W M M. Both this letter and your letter, dated May 20,1994, will be ancia==t with the transmittal letter fvwving the results of the AIT inspection to PSEAG. In accordance with the provision of the MOU between NRC and the State of New Jersey, both these letters will be placed in the Public Documant Room. Once again, thank you for your assessment and observations. If you have any q=atiana, please contact me at (610) 337-5080 or Mr. Edward Wenzinger at (610) 337-5225. Sincerely,
~
Ja T. Wi r , Acting Director l Division of Reactor Safety l ! l
Mr. Anthony J. McMahon 3 cc: Public Document Room (PDR) W Public Document Room (LPDR) Nuclear Safety Information Center (NSIC) l NRC Resident InW_ar State of New Jersey l
l 4
^
I BILL BRtDLEY '0Vu'"i:
. tw atasty siNANCE ENERGY AND NATURAL RESOURCES 1dnited States Etnatt s
- gr" >-
WASHINGTON DC 20510-3001 l l June 14, 1994 TO: Mr. Richard L. Bangart Director . Nuclear Regulatory Commission Office of Congressional Affairs 1717 H Street, N.W. Washington, D.C. 20555 l RE: Marie Weller I forward the attached for your consideration. I would appreciate receiving a written reply with regard to this matter as soon as possible. Please direct your response to the attention of the member of my staff listed below. Thank you very much for your time and assistance in this matter. l l l Sincerely, Bill Bradley United States Senat r PLEASE DIRECT REPLY TO: Senator Bill Bradley 1 Greentree Centre Suite 303 , Marlton, New Jersey 08053 l Attention: Gloria Robertson l i l AWUMV 4pp !
. .- . . - _ .__ - .. - = _ . . . -
I {
- i l ,
RECElVED MAY 31594
~
139 Somerset Drive -/---- llingboro, NJ 08066' ffay P7, 1094 Governor Christine Whitman State of New Jersey ! Department of State l Trenton, NJ 08060
Dear Governor Whitman:
Enclosed for your review is an article which appeared in the Philadelphia Inquirer on May 2,1994, concerning the Salem I and II reactors in Lower Alloways Creek, New Jersey. Af ter reading the material you can understand the horror of what might result in the event of a nuclear disaster! It is reported the reactor is being reopened af ter this latest shutdown. What is unbelievable is the Nuclear Regulatory Commission administers " fines" for violations too numerous to mention and allows the reactors to continue operating. Why haven' t all the people been replaced wi th competent personnel? Why has Public Service had no accountability for the problems and not been forced to immediately correct any and all dama6e? Is New Jersey 6oing to be the site of another Chernoble disaster? Can we believe the NRC who say public safety was never directly threatened? Does nnybody care??? I would appreciate a response as to who is accountable for operating safe nuclear reactors and what can be done in Alloways Creek, Thank you for your anticipated attention regarding this Yours truly, En v z. Yl W. t ' Marie Weller (Mrs. Edward Weller) . cc: . Congressman H. James Saxton Senator Bill Bradley Senator Frank Lautenberr l
e e f I - i ! , A, ., 4r6 vie.w of Salem plan..--t da_ta~ l showspatternofbreakdowns l ' SALgM from At
! eroded the reactor's safety systems, l
?
and that continued problems at Sa- } j lem could put the public at risk. 2. . 1 And Salem's mediocre lifetime per- #I formance - the plant has produced - gMS mg - power at less than 57 percent of its :i - ' capacity-is one raason that electric . MMd NNb M'MM ~ l W. 'M - i j rates in the Philadelphia region are f,,the among the nation's highest. N #dm Q . [
" Dr M .y,#,".e.2 ^ - Nems - '
/would be h(, d'" #' ;' .' ' ( W, Y%./ 8i N.
i NRC officials say the Salem Gener- .. i ating Station, whieb is partowned by .. i d.[b.a, 3 j l Peco Energy Co. and serves four mal- '- '.
!- \.
I lion customers in and around Phila- ( o' delphia, is the most troublesome nu- "\ ' '* J t- M .,,'***"#8
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- A.
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clear facility in a region heavily C"'(' e W' "
- camoen '-
) dependent on nuclear power. - s
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(-' , . . West Chester e t e 't Salem I and 11 are ranked among I l j the worst of the nation's 109 commer-PENNSYLVANIA N
, p.nn, org sho^ ,
t cial reactors. The units have spent 22 percent of their lives shut down for ',.' . . O'80'd '
- I unplanned repairs. Only 10 other ~~N'.,"'
- pm S., . w -
i reactors have spent more time idled -
- S*" -
for that reason. . s nussans r '" 1 . A. , . . . . I
" Stuff just keeps happening at Sa- f, ,/
- lem." said Edward C. Wenzinger, an - Acero n . 7 [ . ., Cdy (-, k*
NRC branch chief. "We're all sort of , MARYLAND \ ,y,-- *7. l puzzled about it."
- .( - f- Dw
- y- M 3-i The NRC's theory is that Salem * / -
l j suffers from an ingrained culture of complacency passive management . ;.'.' g .
'/ /
/
/ DELAWARE r-
"r *
(D' and an indifferent workforce. 'f I
? , -'
) "These kinds of problems you can't M. ,- - i fix overnight by putting a wire some- [' F,' -> \ ; i ! wherc " said Stephen Barr, an NRC , ouncr PSE& I a*4sas essed6 I inspector who has been involved ,- ' 4 . l l with investigations at Salem for four 4
*"" ,, l*, '% f5
! years "They're mind-sets you're t dealing with - attitudes, and a cul- takes on the Delaware River. Power "We'd prefer it if they were a little
- ture." surged. Temperatures dropped. more aggressive." Thomas Muricy.
) PSE&G officials say they, too, are Faulty equipment sent false signals. the regional NRC administrator, said dieniea=ad wim cal *** *"ad * ""- I J 1 i i l 1 4 4 i
.(-
u ek n tw y- ~~ y O 1 l At Salem reactors, l V V - e (w p . t'roublmgproblems l
'. M
' Repairs unmade. Darkened warning lights unnoticed.
Q.' Stuff just keeps happening," one regulator Said.
.. By Andrew hisykuth inspection team reprimanded the j.. and Pam Belluck plant's manager last week for trig. ,
isocinEn STAFF W RITERs gering the Cascade of events on April l I 'Inside one of the bullet shaped Sa- 7. The ins tors said Salem I's man- '
;f hlem nuclear reactors last summer, ager, Pub Service Electric & Gas jg . crucial control rods that tame the Co had failed to fix several long.
, atomic reaction - or halt it in an standing problems and had inade-i,
{w emergency - misfired again and quately trained reactor operators. ' y again. Salem hae heard it all before.
* , .Last fall, the men in Salem's con. An inquirer review of NRC docu.
'd trol roore. were caught listening to ments shows that the April'7. Incl. I to ,the .World Series instead of paying dent fits,into a pottern of break.
1
> t.o fg!! attention to the reactor, downs at the twin Salem reactors in
.c In 1992, a bank of alarm !!ghts in Lower Alloways Creek, NJ. ,
'that same room went dark - and Just a month before the alert, the
,NRC fined Salem.550,000 for mainte-G' .
k,' e + nobody noticed. yAnd the year before, a long unre-; nance violations.it blamed on " con- {P, paired valve set off an explosion that/ tinued demonstrated weaknesses ** of
.i / caused $75 million in damage.. , the plant's management. .
I/A!! those foul-ups, and more, oc.s. '. Federal ~ . investigators say public , (,r. *c hrred in the 'ast' three years safety was'neverliirectly threatened a tiefore the April 7 shutdown of the- by those violations, or by any of the Y JSilem I reactor that led to a.seven ; other' incidents at Salem in recent i hour emergency alert. years. But they say the April 7 event' j3e :.43 Nuclear Regulatory Commis4 ton
, -, ;. See SALEM on A16 O _ _
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psM% L) l g y 4 UNITED STATES i a NUCLEAR REGULATORY COMMISSION U f WASHINGTON, D.C. 2066dHM01
***** August 24, 1994 The Honorable Bill Bradley United States Senate Washington, DC 20510
Dear Senator Bradley:
IamrespondingtotheletteryousenttoRichardL.BangartonJuly2L1994, asking the Nuclear Regulatory Commission to address concerns raised by M. Jody 1 Whitehouse,N .D., one of your constituents, regarding problems that have l occurred at the Salem Nuclear Generating Station. I understand your constituent's concern and thank you for giving us the opportunity to respond. Icanassureyouand@.WhitehouseNattheNRChasconductedathorough review of the events that have occurred at the Salem Nuclear Generating l Station. In the case of the recent events at the Salem station, before allowing the reactor to resume operation, the NRC staff reviewed the Public Service Electric and Gas Company's (PSEgr's) corrective actions to ensure that resumed operation of the Salem station ,- id be safe. In response to those events, PSE&G has acted to restore, replat.e, redesign, or repair equipment and hardware that contributed to, or was a factor in, station performance and to correct operating practices that needed improvement. To further improve station performance, PSE&G has reassigned or replaced supervisory and technical personnel that were found to be ineffective in their assigned 4 positions. PSE&G is continuing to review personnel effectiveness and is l expected to make other personnel changes as necessary The NRC Augmented Inspection Team's independent review of the April 7, 1994, , event indicates that the public health and safety was not impacted. The NRC continues to hold PSE&G management accountable for the performance of the Salem station and has taken enforcement action on several occasions to emphasize the importance that the NRC places on effective and safe operating practices, and the proper adherence to regulatory requirements. However, because of the series of occurrences at the Salem station, the NRC is directing increased regulatory attention on PSE&G's management, operation, and maintenance of the Salem station. The NRC staff will continue to closely monitor plant operations and will not hesitate to take any necessary regulatory actions. The apparent violations of suae
The Honorable Bill Bradley l l l the regulations related to the April 7,1994, event are currently being assessed by the NRC staff. The NRC enforcement policy will then be applied, as appropriate. On June 24, 1994, the NRC issued the inspection report on the ' April 7, 1994, event. A copy of the inspection report is enclosed. ! Itrustthisletterwillsatisfy~Dr.Whitehouse'7 concerns. Sincerely,
/
& l nes M. Ta r xecutive Director for Operations
Enclosure:
Inspection Report l l l l l
1 -
, 1
'3]Cnifeb Stafes Senafe j W ASMINGTCN O C. 20$f0 July 29, 1994
} l , Mr. Richard L. Bangart, Director Director Nuclear Regulatory Commission l Office of Congressional Affairs sig n [C b555 i
Dear Mr. Bangart:
4
- I forward the attached for your consideration and would j appreciate receiving information in regard to this inquiry as i soon as possible. Please direct your reply to the attention of 1
the member of my staff listed below. I ! Thank you very much for your time and assistance in this matter. Sincerely, d Bill Bradley United States Senator BB/sr Attention: Shannon Richter Office of Senator Bill Bradley 731 Hart Senate Office Building Washington, DC 20510
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Dear Sir / Madam:
i l l l I was outraged by the recent article in the Philadelphia Inquirer i describing the Salem Nuclear Power Plant as one of the worst in the country. I feel strongly that there should be a full investigation and all problems should be corrected immediately if these problems cannot be corrected, the plant should not I be operatingt This is a concem which affects all of us. I appreciate your prompt response to this important matter. Sincerely,
. ( $w lx M qcky (JL&lwa A.b l
l t I i
l l At Salem reactors, , troublingproblemsl
" Stuff just keeps happening," one re .
By Andrew \taykuth i and Pam Belluck inspection team reprimanded the ! INQ c!Ap.R .4 r o r u a.7EAd plant's manager last week for trig !
'nside one of the builet shaped sa. gertng the cascade of events on April
- em nuclear reactors last ummer. ' The inspectura said suicm l's man.
cructai control rods that ame the ager Puntic Service Electric & Gas: atomic reaction - or hait it tu an Co. had tailed to fix several long-emergency - mtstired agala and standing problems and had inade-again. quately tratned reactor cperators, L;ist fall. the men in Salern s con. Salem nas beard it all before. trol room were caught listening to An Inquirer revtew of NRC docu-the World Sertet instcac d rnents shows that the \prt! 7 inci-fu". ai:.ntion to the rex' - earng dent .ts into a pattern .if break-
- n 109. a bank of a6rm :.ghts in downs at tne twin salem reactors in that >ame room went ;vk - and Lower Alloway* Crsek N J.
cv,dy not2ced. Just a montb uri the alert, the And the year before. a 'on NRC ficed Salem 350 000 for mainte-paired valve set off an exp:.x:untc. in that cance notations ;t biomed on con-caused 5*5 million in d:. mas tinued demonstrated weaknesses" of All those roul ups and more oc- the plant's management. curred in the last three years - Federal investigators say pubhc before the Aprti ~ snti'dcu n of the safety was never directly threatened 3alem ! reactor that led to 4 seven- by those wolations or by any of thes hour emergency alert other inc: dents at Salern in recent!
\ Nuclear Regulatory Cortmission years But they say the April 7 event See SALEM en A t6 l
I 1
I W i j i - ) e --. ._. as . .._ w .. m .- . j 4 A review of Salem 41
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; among tas naconi highest ..p - ,, , ,. _m s f3RC ofScsakusythe Salem Cener ' '? - '
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j ". comp! ara *~ passso enmaagemeesI . .E stated Jis cuararns agamO* lo M. g.. ; - . and aa mdifferemi vornsorta e. .
,,e.'- - assia.w - , . . w. no on i
"Nue k1Dds of problanLs vos can'tD -~ --
1 .' in Decembehtpp2, se #cpeattor 'u1S *' f t
'in evern24bt De pe:nns a wtre soms#-
wttere* said Stipptien Barr ac NRC ' G:. {14., . . [* m
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ryped some commanos on his com. poter saysoerc -- sad taenowtat:r
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.nsnecmr who As trdt :.c s on ed D - -."'f*f ,I .*,egn { disconnected the contros ~x>m S to ge 3 wt3 aavestgsconsat Sa.em for four _.' panet of ournaad alarm lignts Ost yeart.e"Dev rw-'manoeen you re kalr ". [ shd ** flash when any reactor componest .
dsaung etta - attundas,and a :.. taaas on t$s'Detsw' ver" . "Wed prefer 11If Ylittie Jaut . O dy nonced for M maam $g}y' ,,
** C - %43r < entre W ATasaperatures SimppaL more aggreamve? Thames tierter t;2a2 handads of !!ghts had gona cet ma'
*p5EAC omculs ary ther; too. an Fanarretsspoent setr ' gnam the regionalffRC amammelbr I'~ m "- - M*-- *
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disp ===1 with Sales a reqirtL Os neSpermuwt assr. ds fell.J 1994 *
. d.' $4f , - If thefd known of this breasdowe. ,3
== pan, am saim d to,maag,. onricomed <n. mio contreuer N.-- tax - "T -~- andaged us wRc ins wiors =>d. inn wenie '
I mass and commanad 20 maDics to . vanes did apruussa. artttng offJetv~plantin 199t'wben 5else "JaSural han lahead it a naclear a ert . years o. rettanze ins reactors it v.im- notner enaan a(ansa saat farced .a maman rausre-.-a.*turtnaeaver No one told the NRC umul ts Bours W But prenng training proc =dares and salen io d ciarem mean noir aart. -. speed ennt. in the grgan oro, er. ne stan 424 noi teu Saam: ,on et amdware j j- -- . jam;tae snartmos ariougof garJrag;p-,- u x c--1 rsenior manasement anni the nut .' taae n, , ~ . G me stas.c=.rsy
- PST.ac cent -.meriency casaricainwg----- % % e a nris manamsn "*- _.;- - -- am e
OsddlLt2ve T. JamasiTerLand C he NRC send Gum s decado er weam1tr'theTuriptne locaad Dpen -- _-Ptve montaa lever, et Sejem !L a n ,, j q stacanosden on Aprti tt.*taar Salem"-Manhav to fLa the devtes was typecal ? 4sesing the turbm(s giantToters e contro4. roam operster nonced that a t'StaC' { 8d
- vetatImb
?o we hmBas fornot that the(Ligt ournina- p. ;erpectar S ,,,,,1 TtW 13,g,,t the plaars .tt, w treeDial
, ,od Lhistoryaessnag E.C,fyla taro sn em ontinca Cauntrol bevins.The N rodstur$Las *'f'T.tuster
#=nemato me r* of enta -
control IM the Sn!2ty'I efE1E $8 kase etent 11 and oar opererort cas - thack sient*mW. showertag gdacar's core whaa apmaners ased to door 'o : purnmant s las 4 ares arsersaa. get art,ane it .se ' enc 3 astr sats.,3at me fase.andunanas a h p a2tnamoa. /. e. *. . /.* inn oest
=
- memmase ci saiam ha, m -waros roe c. set aroandatin non t 5.am dacia,ed o aart weciaarn m opentar ined agan and avato mv WGeset Caatige." said ybogas T , -cases Det morevery casa. tirtB2s W **
cums.]glerts art rare L eaght weredardargte gEQha CQatFQ1 rodr1D opetata.la rest ot : the NRC_ demwrats rE> , it bit tLam.* i ,g.g - nat3eBwide 1AN FWK. "W Lanaana. Otica. s cinstar el rtwas went hasEsve j sw for h - - L stazaa taiam has Dean bittee art *' had kasvaof the ve 4 suynang y a - g,g,gg ,-N, as ter a year and had %,--An *rRC tem blas#the prMn .t-whe e* l j l' La l 8 'k E msnelto sae Salent M -strimonths before the ftre.%BTrRC. tem a wrongly poeconed altart carLFe*n. smaD deh 4610 gt wene cost fadun of themet mad.5everal supervtsassisenjumad. tr rs cot Os agency.cLtad personnel lass int.~tressac j mostrot esacLW . . - sauceynes ad to satt dews l, in have tenored tasm shownst their j'estag the probtem than for what; Bat of t g !!s joe and close valves the ruector g emergesc7, == w - vaner daieca i in the pipes that carry h:ta pressure -r 7 L asppened neh = - - + a2tre et N go,.aa%t sareportes EGN NRC sund it was comerned* C"Nv tryt trytag to retasert tDe
- nov j staam from a aseteer reac1or to the-hrie aarv % emsers nout e 6 that woam per, rods rather than fLgure out what and a2 bass rurotaae thangegetate power . fausd again. They hadal boa prop a4 sect a beec Caw in perfofinance **'E wron8. the NRC's Weassager snoert Al Salem. the hS10 and been mak edy intricatedme VRC. d.tstresusd t's pervece through malapaa lesens og nctuad 1 art weet. PSE4C promued a,cc::.
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, 'Mana<ement et taast knew andto years did te it not fix haarn of theemruer Is;.::*e Inned Mrment and contrnL' *- to retrain Lts woc &aca. - no Lt.,
tse olan said oook. a record for tne Stut the PrRC decidas not t/fina } Last October.theNRC!onnd Sales "tt - Oversiors a musuv compensied Dy,operatins. NRC. ne asance,esued it themerm Setem w *m esptoston - Agai" *or*er' i"P'uneregarn Empi"- ~2ese e Untu Apru
- Lacideos slaca The Wale LsisadL a reenas from US Sea.Josep Baden } ees Sad repest@ pur me met mcc i ;,, . PSE4C promisedto do better h (D. del. whoconad aos tae jates t , labe.s and directons oa suaoment. ne
; On enat marriet operatore strN4 WRC beneved tae taase was partly Hope C ees reactor trotn B apart. De tapeesebhaed one iscanician NO tied 'o retain Ocent of '.Se reactor grow'es pains - Salem l as only sta ment ac oss the Delaware 1 verv to i.ap from a induer to avote 6e't".*.a uu af:64 a narry et even s tai beast vaars o.d wst T'here waa :9ticanisy ccecer-ec that otaer di ters. also smacsed di a woippict stasir :ose Pe N
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and agal:L 130.000for wens saperrtmary meth- l t Martta.the mtC's top n' conal in Decerc>rr W se toermior od&* 18 nores Inar nmliar maste0eb ' clat nato r2nonth before 'De ser l
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, uter s.ai noata 1.sccatec:cc le
.r.s .:s:u n'ng,iv "r ~ 9 mom 3 to do bet'er '
Once again the cotopacy pledged proMaa was iurainer.
~* - -w--
*shaldows '.l'.ar % eat r . .r ; -
misuremm wa y s
~ - - - - -
N A l" "*6asse-pasea ut earna Aa- its tat . g *- as dou au the can Naas 3e n w"ere things ' sow tase cave to .
**-~ ~ Casa eteo atv -eec*:,r .t a ponenr. ~;NRC officaa4s who have observed M .v. * <
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"' ."t . on ;be hard tasaar *.
= J.11r- aaweryE*We'd prefer t:.f"iry were a ut*f
/ts** :r rped. more aggresane. !%r.aa Wur:sl; r
.'8hat Budn.s if'" ants had gona Salem..
." cnnftmndetL for yeen are
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. . .al.w nasala.'. .the raw,r.4. NPC .c=::.:.n stor sai .
*na n.s reaza
~** * ""' Nv han Jan.s.dl -
n te:r sanar in11. a L9e( .erse rte age of tne re d. ate rankegggtf,,n.,M actors f5aarm 11917 ~ ~ Attne ==mema 5 q ,dnrumans. Lbmamm-oecetreuer The - Las ma.ntenance encanaered ar "*" '**#U "
- 8 ear asert ?'yean old. Salem IF tsN
- s. 'e't:ct oif ver piant in acet .bes .a..m C st!en1 N8 'sne to64 :Be NPC . : .1 :8 honn
<ec's rnat totted a masswe rawn - a 'arbine ou '-
1** en sour asert. rpeed evenC* -o :he . argon of de : ster Ibe staff .1d not t:11 Sales t tors of tas same vin ",' Senior aansgement actt! :te next [tage have. better r,. W But otner US - On S Mruc.. r
. .' tennoa .W0r$t menttacartaAnac.
repairs ciste. ONh
.ns J four .tRC andu.rtry
' tarner- for. tsar en s zur- ~-".9-'rtar Mov
- t. a ralve: controty g Mti8 8 /.... . ',: Ocords dw - , ,-l 'COttttflerC1&[ 'M :g:-
be3T decace of .staast to tne f ar3tze lottad open e.
- e 30Eds !aMr st Mm 1 rN Np have lontad ag ' - tDrt.'"-
ecce was tvpicak caanns :ne rutane s c. ant rotoriao con.rol-room opemor nonces tne' *),P5DCr tsunagement - ~ s '.'erJLUi Fas manneement-
' ec htstory rpta coraf coctm *te nreine e 4a causter of contros roos ens noe ta' A tne ammenuary op- AMd : 1*M"a" bara ny twoom wr
- havas, ne roos metam tne ae , antaa taa Hope Creet reactor
- .next;;,tbo uurrer ane reeAizasthat 4t. " Welt we placed. biaants crenga its :ca r door to 5a6em. Hope Crees has one DC you're acruauy dans ts semag .ve
( .t 'versers can taacs stent cas.u. .nowering san , actors con =nem openwrv naec t* - utC's Barr saga. net 300 'est ana :g:uttag e stre. j nu unon. y- { ne poet recoros in the tianos .4 overstars sp;'said Barr . 8"Hd 't in 8Doek. . Saiern dec.ared an a4ert 1 scia r N coarstar ried assat and seman .Nr have looted et tne 1stoEnd .' N .'worters ' aren t brama.t
- = :n =a c==. Taisets are ran - eacnt em daca, a to sei tna contro6 roos o operam in Fram or Salem i earir y,anararmar _ rsere an apar.wes wn ha.e n.
j anison. Once. tclus'er of *ome went .has g3ven wey to wha (a4 eldesas tr 'thart for tisarty E rears 73nrr sa . -~ % *;, naconwide last tear - . op waan tr snosaa nam geen M . -nty Eherget a!mla.ystCM En f ggy.c.w j een seforv. t P5E6C had known of tas oed v v An NRC team blamed es profHeu iThe. Mtc conadarst seinEasers.'- betimr. ther can detids_wessia '.- i ".:t 'aressers de- for a year and had premassa to tLa Lt ers' comptaants taas easy were aus. equ2pment* :=t m::p a j wemi,aamed- sts moatha bclara tse fire. tne $ on a wrong.y pannonaa ctrcut cartL g
.re of the auto- sand Several rapervuors were Sast The agency cated personnes taas tor tresset fes' rusung-susser concerns .!tRCoracialaimidthe besmo l
rec :imabut nowtl to nave ignored tasm 850 wing tp canng tne proessai 7an !or what But afnral* cancandes tnat person-- Radias dent underscorus- art hamaadhom thattheenct? ;:c" j oergtacYu valves aefects f.ra g happened nazt q$* .(:.;" .. auty cJannes war, gyrMamat , ,_ Thev even wonaered stoet drugs roust Bar daring_tas pase s "Thef kept "yltsto " Tin 8m the "t n.reportaa. The NRC ta6e at was concerned roda retner enas fitt.re etrr waar. and tacomet Last year tarse Salem World Sarums. sm, coan mm
' wh Bressers apout a sortoisce that wouid ::ari sent wrong. ne NRC's Wenzanger , esporvisors fanied rencas crug and restors rtaged a speau' phone ac: ? seus prom mit such e easic P.4 La pardertcance l 1
e s PC :. stressed to Pernoe ttrnata maanpas teweis og recawe ast *eet N'DGno;remised , acunot toets But NRC Ltnt to ens reactori problems olfacsaas saw itsres sor nuesseuratesar ,, e the gna, q er auure 'Ined outrant anc :octna ':- g to mrain .ts worsers ". ~ N 'h'8 * **r *- g tr may be a comescanc'a of .ij )
- . eurd Mr taa StG te VPC Jec.4ed not 'n fine worsers Cast Octooer ne sRC 'ana Smem ne tsoesst ho , cone a tmprovt:E assa E.mpioe- taeur tnants Wetustger sand 'ast tmose am;counse# mm 1
I t to it ne .nrst Sa.orn or se e 3 osion - prorepcas *ee *ad novant u .se wrong mostJL *! wtsn ! could ugure it out - l l
~ We lancL =; a reouse ' rem 3 ato .onept tiidan woroca.s ams~
4 me, n.. m x n o. ~ a - sean ac.n. .aoe~no m=&s wem no ,rooiens 2,e a coccarn is
~PPople who ar/opr9- e f e *as : art.y Hope ce,a enc of ma has 3part- The ames cDoreo 're ecanac:an PSMC Steven E wenaeraer tne acar m-ce pracn* inic + -
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- De NRC .n .u.y anal :e aam siuati 4 mo o :av st'e tna e' . ns . - cim , mater ec . . sare ~ Jo macreo , a s u o s een Luna. a*
prvecc .e s - *: e Mc=e .: 2 es- ' noir er -r e er aw..: a . .kea .netaer :cv conunonaat:aa nau <2ev e coicep., f i, ha. l 1
~
The Honorable Bill Bradley .
- l. '
the regulations related to the April 7,1994, event are currently being assessed by the NRC staff. The NRC enforcement policy will then be applied, as appropriate. On June 24, 1994, the NRC issued the inspection report on the April 7, 1994, event. A copy of the inspection :eport is enclosed. I trust this let^er will satisfy Dr. Whitehnuse's concerns. Sincerely, Originalsigned by James M. Taylor James M. Taylor Executive Director for Operations
Enclosure:
Inspection Report DISTRIBUTION: Docket File 50-272/311 (w/ incoming) N. Olson, Secy, ADP 012G18 NRC & Local PDRs (w/ incoming) C. Norsworthy, Secy, D/DRPE ED0#0010349 ADRI Secy EDO Reading J. Stone (w/ incoming) J. Taylor M. O'Brien E. Wenzinger, RGN-I J. White, RGN-I T. Mart'in, RI W. Russell /F. Miraglia R. Zimmeraan A. Thadani D. Crutchfield F. Gillespie PDI-2 Reading (w/ incoming) S. Varga C. Miller (A) M. Th:dani(A) OCA SECY# CRC-94-0783 NRR Mailroom (EDO# 0010349) (w/ incoming) 012G 8
*Previously Concurred n .O /YM [/
OFFICE PDI-2;LAf , PDI-2:PMh PbD TECH ED* (A)ADRI* NAME M0k[frk JStone:t1 MThadani RSanders - 4 Miller DATE
// /94 [/JN 7,//f/ 08/12/9[ 08/12/94 0FFICE DRPE V % RRb h , .y ED0 \[ OCA a NAME V ga ier r Ri/ssb JMT;hlor i N j
DATE
/ /h 1
I /l{' / ~ V/ [, /h [//[// 1 0FFICIAL RECORB COPY C) FILENAME: SA10349.GT}}