IR 05000272/1994013
| ML18100B194 | |
| Person / Time | |
|---|---|
| Site: | Salem, Hope Creek  |
| Issue date: | 07/01/1994 |
| From: | Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18100B193 | List: |
| References | |
| 50-272-94-13, 50-311-94-13, 50-354-94-11, NUDOCS 9407130035 | |
| Download: ML18100B194 (24) | |
Text
,.
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos. 50-272/94-13 50-311/94-13 50-354/94-11 License Nos. DPR-70 DPR-75 NPF-57 Licensee:
Facilities:
Dates:
Inspectors:
Approved:
In Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, New Jersey 08038 Salem Nuclear Generating Station Hope Creek Nuclear Generating Station May 1, 1994 - June 25, 1994 C. S. Marschall, Senior Resident Inspector S. T. Barr, Resident Inspector J. G. Schoppy, Resident Inspector T. H. Fish, Resident Inspector J. Laughlin, Emergency Preparedness Specialist R. K. Lorson, Resident Inspector S. M. Pindale, Resident Inspector B. C. Westreich, Resident Inspector N. S. Perry, Senior Resident Inspector T. Y. Liu, Project Engineer.....,.......___
B. J. McDermott, R ctor ngin r P. F. Bo
, Res* ent s
J. This inspection report documents inspections to assure public health and safety during day and backshift hours of station activities, including: operations, radiological controls, maintenance and surveillance testing, emergency preparedness, security, engineering/technical support, and safety assessment/quality verification. The Executive Summary delineates the inspection findings and conclusion ~riR7130035 940701 a
ADOCK 05000272 PDR i
EXECUTIVE SUMMARY Salem Inspection Reports 50-272/94-13; 50-311/94-13 Hope Creek Inspection Report 50-354/94-11 May 1, 1994 - June 25, 1994 OPERATIONS (Modules 71707, 71715, 92901)
Salem: Overall, the licensee operated Salem Units 1 and 2 safely. Plant staff performed a methodical, controlled, safe Unit 1 startup following the April 7 trip. Startup was accomplished on June 4. Operators demonstrated appropriate command and control in response to a Unit 1 plant trip on June 10. Salem management acted appropriately in taking the units off line for dredging in front of the circulating water intake structure. The licensee has established plans for engineering modifications to the circulating water intake system to mitigate grass intrusion problems. Operations demonstrated improved control of troubleshooting when compared to past performance in addressing a leaking relief valve; however, the operability determination process for the relief valve appears weak in that an engineering basis for reasonable assurance of operability was not apparent. This is unresolved pending completion of the engineering analysis to support operability and for inspector review of the response to the leakage identified in March 1994. Inspectors identified some operations staff acceptance of repeated entries into Technical Specification (TS) Limiting Conditions for Operation (LCO) action statements regarding the head vent flow path and a service air containment isolation valve. This did not result in violation of the TS for the head vent flow path, but is unresolved for the service air containment isolation valve. The practice, which demonstrated poor appreciation of risk associated with TS LCO action statement entries, was immediately and adequately addressed by licensee managemen Hope Creek: Overall, plant staff operated the unit safely. A reactor trip occurred due to low reactor water level. It was caused by an automatic swap over of feedwater pump control to manual. The inspectors concluded that inadequate engineering oversight of implementation of a modification of the feedwater control system contributed to inadequate operator training relative to the expected response of the new digitally controlled feedwater system that was installed during the last outage. As a result, operators were not aware of the swap over to manual and were not familiar with pump response in manual control. This matter will be addressed in a future NRC inspection report. During a reactor startup on May 20, the inspector observed weaknesses in implementation of the procedure for operation of the control rod drive (CRD) system. Operators were unaware of the procedure limit on pressure, and did not have the procedure in use. The inspector also observed that plant staff did not monitor CRD performance to identify adverse trends. No unsafe conditions resulte The cause of Safety Auxiliary Cooling System pump trips is unresolved pending review of the licensee's root cause determination. A Safety Review Group member identified an operability question concerning the high pressure coolant injection alternate suction valv ll
The licensee appropriately determined that the valve was capable of performing its intended functions. However, resolution of current licensing basis commitments is unresolved pending further NRC revie MAINTENANCE/SURVEil..LANCE (Modules 61726, 62703, 92902)
Salem: Planning for troubleshooting an emergency diesel generator turbo air boost control circuit was poorly planned in that the appropriate parts were not readily available, which extended the inoperability of the affected diesel. Elective maintenance on a service water butterfly valve caused the licensee to unnecessarily enter a Technical Specification action statement for approximately 45 hours5.208333e-4 days <br />0.0125 hours <br />7.440476e-5 weeks <br />1.71225e-5 months <br />. Although this did not result in an unsafe condition and is permitted by Technical Specifications, it represented a condition of unnecessary increased risk resulting from unavailability of safety-related equipm.ent. The plant manager previously recognized the need for improvement in the Salem planning process, and initiated measures for improvement. These measures included reorganization, increased staffing, and clarification of the standards for planning performance. These improvements are not yet fully effectiv Hope Creek: The inspector observed an industrial safety enhancement to the process for replacing service water traveling screen baskets. However, during CRD conductivity analyzer maintenance, the inspector observed that personnel worked on energized circuitry without adequate guidance on de-energizing the equipmen ENGINEERING (Modules 37700, 71707, 92903)
Salem: During the 1993 Salem Unit 2 refueling outage, the licensee inoorrectly replaced the power operated relief valve internals with materials different than intended. In March 1977, the licensee removed components from the MS-10 control circuits, resulting in the valves inability to perform their intended function. The licensee-did not identify and correct this condition until after the April 7, 1994 Unit 1 transient. In addition, information developed during review of the event revealed that the licensee failed to correct spurious operation of the main steam flow bistables identified on three occasions prior to the even Hope Creek: Inspectors found that the spent fuel pool criticality analysis, calculations, and the associated 10 CFR 50.59 evaluation were thorough, conclusive, and accurately concluded that the minimum temperature limit was acceptable for safe spent fuel storage. The unresolved item associated with this issue is closed.
iii
- SUMMARY OF OPERATIONS Salem Units 1 and 2 Unit 1 was in Mode 5 (Cold Shutdown) at the start of the report period to support maintenance activities related to the forced outage following the reactor trip of April 7. The operators commenced a plant startup on May 14. However, as reactor system pressure approached rated pressure (2235 psig) the reactor head vents and a pressurizer safety valve developed small leaks. The licensee decided to return the unit to mode 5 to repair the leak Once repairs were completed, operators achieved reactor criticality on June 2, and synchronized the main generator to the grid on June 4. On June 10, as operators were raising power to 100%, the reactor automatically tripped following failure of a main generator potential transformer. All systems functioned as designed in response to the trip and the operators placed the unit in mode 3 (hot standby). The licensee re-started the unit on June 13 and synchronized the generator to the grid on June 15. Following several days of operations, the licensee reduced power, placed the unit in mode 2 (startup) on June 24, to facilitate dredging in front of the circulating water intake structur Unit 2 began the report period at 28% power while I&C technicians made repairs to a reactor coolant loop flow channel. Technicians repaired the channel and operators restored the unit to 100% power on May 4. On May 20, operators reduced power to 50% to troubleshoot a steam generator feed pump control circuit. On May 22, operators increased power to 100%. On June 14, operators reduced power to 70% in response to grass intrusion at the circulating water inlet pump house (See Section 2.2.1.C). Following a period of increased monitoring at the circulating water intake structure, operators returned the unit to 100% power, approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the initial power reduction. On June 18, operators temporarily reduced power to 75 % to perform work on a turbine auxiliary cooling (TAC) heat exchanger. On June 22, operators commenced a load reduction to 55% power due to grass problems in the circulating water intakes. On June 24, operators reduced power to 29% to troubleshoot a turbine governor control valve. Later on June 24, operators further reduced power and entered mode 2 (startup) to facilitate circulating water inlet dredging operation Overall, the licensee operated both units safely throughout the inspection perio.2 Hope Creek The licensee operated Hope Creek at power from the beginning of the inspection period until May 15, 1994, when the unit experienced a low reactor water level scram. On May 20, 1994, the licensee performed a reactor startup and synchronized the main generator to the grid on May 21. On June 21, the station experienced a hydraulic control oil leak on turbine bypass valve No. 2. The plant was placed in Operational Condition 2 (Startup) and the main generator bypass valve was removed from service for repairs. After repairs were completed,
- the plant was returned to Operational Condition 1 (Power Operation) and on June 22, the main generator was synchronized to the grid. The reactor operated at power for the remainder of the period. Overall, the licensee operated the reactor safely throughout the inspection perio.0 OPERATIONS Inspection Activities The inspectors verified that Public Service Electric and Gas (PSE&G) operated the facilities safely and in conformance with regulatory requirement The inspectors evaluated PSE&G's management control by direct observation of activities, tours of the facilities, interviews and discussions with personnel, independent verification of safety system status and Technical Specification compliance, and review of facility records. The inspectors performed normal and back-shift inspections, including 120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br /> of deep back-shift inspections and sustained coverage of the Salem Unit 1 startu.2-Inspection Findings and Significant Plant Events 2.2.1 Salem Unit 1 Startup On May 14, operators commenced a plant startup. On May 22, with the plant in mode 3 (hot standby), one of the pressurizer safety relief valves, 1PR3, and the reactor head vent valves began to leak. The combined leak rate, approximately one-half gpm was well below the Technical Specification limit of 10 gpm. Nevertheless, the licensee decided to return the unit to mode 5 to repair the valves. The licensee recommenced the startup on May 25, taking the reactor critical on June 2, and synchronizing the main generator to the grid on June During the startup, inspectors observed that operations, maintenance and technical personnel performed a methodical, controlled, and safe startup. The inspectors also noted that the decision to repair the head vents and relief pressurizer valve was conservative relative to overall safet Automatic Plant Trip On June 10, 1994, while operating at 97% power, the Salem Unit 1 reactor automatically tripped following a main generator trip. All systems functioned as designed in response to the trip. The operators took immediate action to stabilize the plant, and placed the unit in mode 3. The inspector noted that the operators controlled and monitored key plant parameters, and performed the appropriate emergency and abnormal procedures. The inspector also noted that the Nuclear Shift Supervisor (NSS) followed the Emergency
Operating Procedures in directing the reactor operator (RO) actions. The ROs appropriately responded to the NSS orders by repeating the instructions back to the NSS. During the plant recovery, the Senior Nuclear Shift Supervisor (SNSS) maintained cognizance of the overall status of the unit and stood back from the controls area of the panels to maintain supervisory oversight. The inspector noted that crew performance on June 10 had improved in comparison to April Following the trip on June 10, the licensee performed a root cause evaluation of the generator trip. They concluded that a potential transformer (PT) failed, causing the main generator output breakers to open that caused the main turbine to trip, which in tum, caused the reactor to trip. The licensee sent the PT to an outside facility to determine the cause of the component failur Based on observations of the shift's improved post-trip actions and command and control, the inspector concluded that the licensee performed safely and appropriately in response to the transien Grass Fouling of Circulating Water (CW) Intakes At 6:30 a.m. on June 14, 1994, Salem Unit 2 experienced an unexpected intrusion of grass and river debris which caused an overload of the CW traveling screens. Reactor operators responded quickly to the sudden increase in differential pressure ( dp) across the CW travelling screens by reducing power from 100% to 70%. The Senior Shift Supervisor immediately took charge of the control room and dispatched additional personnel to the CW structure, condenser hotwells, and the condenser priming tank. Operators stabilized power at 70% and recovered the circulating water system fully without tripping any circulator. The licensee attributed the sudden grass/debris intrusion to a massive clump floating down river or debris dislodged from underwater build-up in front of the intake structur On June 24, 1994, Salem management took both units off-line to perform dredging operations in front of the CW intake structures. Unit 1 was reduced in power from 55 % to 2%, and Unit 2 was reduced in power from 29% to < 1 %. Plant management chose the power reduction to minimize the risk of any plant transients caused by the effects of dredging in front of C The inspector observed the operators response to the grass intake on June 14. The inspector noted that the operators took prompt and appropriate actions in response to this grass intrusion problem. The inspector noted that the licensee is evaluating engineering improvements to the circulating water intake system to mitigate the effect of grass/debris intrusion on the plant systems.
- 4 Safety Injection Pump Discharge Relief Valve Leakage On June 22, 1994, operators conducted a 92 day surveillance test on the No. 21 safety injection (SI) pump. During the test, operators noted what appeared to be leakage through one of three relief valves (21SJ39, 22SJ39, and 2SJ169) which are subject to the SI pump discharge pressure (see figure 1). The relief valves lift at 1750 psig and discharge to the pressurizer relief tank (PRT). Increasing level in the PRT provided operators with an indication that one or more of the relief valves were leaking. Operators quantified this leakage as approximately 17 gpm. The relief valves protect the SI system from potential overpressure from reactor coolant system leakage back through discharge line check valves (i.e., interfacing system Loss of Coolant Accident [LOCA]).
2SJ167
,__ __
__.__ __._ to cold leg to ;fn Figure 1 This valve leakage previously occurred on March 31, 1994, during the performance of the same SI surveillance test. The licensee ran the pump three days later, on April 3, in an attempt to identify the source, but the problem did not recur. The licensee considered the system operable since they did not observe leakage when the pump was run on April 3. The licensee did not perform a detailed root cause analysis of the leakage path to the PRT, nor did they perform engineering calculations to evaluate the impact of a possible diversion of some portion of SI flow to the PRT in the event SI was required.
J
At 1:41 a.m. on June 23, 1994, the licensee attempted to identify the leaking relief valve through the use of an approved troubleshooting plan. However, upon running the No. 21 SI pump again, the operators did not observe any increase in leakage to the PRT. On June 24,.
the inspectors asked the acting plant manager and the acting operations manager whether the SI system was operable, and the basis for operability. Later during that day, the individuals indicated their determination that the SI system was operable, since the relief valve had stopped leaking upon restarting the No. 21 SI pump after completing the pump surveillanc In addition, previous experience (in March 1994) demonstrated that after the relief valve leaked, shutting the SI pump off and restarting the pump appeared to cause elimination of the leakage problem. As a result, the licensee was confident that the SI system would operate without the relief valve leaking. In addition, system engineering expected that the amount of identified leakage would not result in less than the design basis SI flow being delivered to the cold leg under accident condition The inspectors reviewed the licensee response and considered that the operability determination was not very thorough prior to the inspectors requesting the basis for the determination. In addition, the inspectors found that no definitive guidance existed for operability determinations. The inspectors concluded that, during this inspection period, the licensee appropriately identified the relief valve leakage and took action to identify which relief valve was leaking. The inspectors also concluded that the licensee's process for operability determinations relies on individual performance and capability as opposed to a formalized process. In addition, it lacks clear guidance and does not result in a documented basis for the operability determination. The inspector considers this to be an open item pending resolution of continued valve operability and evaluation of the licensee's root cause investigation and engineering evaluation following the March 31 initial problem identification. (URI 50-311/94-13-01) Repeated Entry into Technical Specification Limiting Conditions for Operation During the Salem Unit 1 startup initiated on May 14, plant staff experienced problems with leakage from one of the pressurizer code safety valves (1PR3) and with two of the head vent valves (1RC40 and 1RC42). Leakage past the code safety valve and head vent valves had very little safety significance, and the licensee ultimately decided to replace the code safety and repair the head vent valve Prior to the decision to cool down and depressurize, the licensee attempted to reseat 1PR3 by slowly varying reactor coolant system (RCS) pressur The licensee implemented this process at the recommendation of the valve manufacturer (Crosby). 1RC45 isolates all four reactor vessel head vent flow paths. Closing it places the plant in Technical Specification (I'S) 3.4.12 action statement, which requires that the licensee restore at least one vent flow path within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in hot standby within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. On May 22, an inspector noted that operators closed 1RC45 from 1 :45 p.m. on May 20, until 3:25 p.m. on May 22, a period of 26 hours3.009259e-4 days <br />0.00722 hours <br />4.298942e-5 weeks <br />9.893e-6 months <br /> and 40 minutes. At 3:45 p.m. on May 22, operators again closed 1RC45 until 12:49 a.m. on May 23, a period of 9
hours and 4 minutes. The inspector noted that, operators opened 1RC45 for 20 minutes on May 22, exiting the action statement, then reclosed the valve and made a new LCO log entr Operations management indicated that they did not intend to exceed the time allowed by the LCO action statement for 1RC45. The inspector noted tl:tat the licensee elected to depressurize the plant after less than 35 cumulative hours with 1RC45 close When the inspector questioned the new log entry, the Senior Nuclear Shift Supervisor (SNSS) indicated that he considered the practice of re-initializing the LCO action statement acceptable, and that this practice had been applied to the LCO action statement for TS 3.6.3.1, relative to containment integrity involving containment isolation valve SA-11 Plant staff entering containment to perform maintenance occasionally required an air supply for air operated tools. The SNSS indicated that, in the past, the SA-118 valve had been opened for several hours before lunch, closed during lunch, and re-opened after lunch while workers completed their activities. The TS 3.6.3.1 action statement permits SA-118 to be opened for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, then requires that the plant be shut dow In response to the inspector concerns, the licensee discontinued the practice of opening SA-118 during containment entries, and planned to use portable compressors in place of the air supplied through SA-11 The inspectors concluded that although the past practice of repeated entries into the TS 3.6.3.1 action statement did not represent a thorough awareness of the erosion of safety associated with the practice, licensee management took appropriate measures to correct the practice when identified by the inspectors. At the close of the inspection, operations management had not completed their review of the past practice associated with SA-11 This will remain unresolved pending inspector review of the details of previous SA-118 valve manipulations. (URI 50-272&311/94-13-02)
2.2.2 Hope Creek Unit Scram On May 15, 1994, the station experienced a reactor scram due to low reactor water leve The licensee had reduced reactor power to 95 % in preparation for removing *the "A" reactor feed pump (RFP) from service for planned maintenance. Operators commenced a power increase with "B" and "C" RFPs supplying feedwater. A reactor water low level alarm sounded followed by an intermediate runback on the "A" reactor recirculation pump which reduced reactor flow. Operators then noticed that the "B" and "C" RFPs had transferred to manual control. The "swell" effect from the runback caused indicated reactor water level to
- increase sharply. The operator reduced RFP speed in an unsuccessful effort to control leve Two reactor water level swings finally resulted in a low level scram at + 12.5 inches. The operators stabilized the plant in Operational Condition Licensee investigation revealed that the "B" and "C" RFPs had transferred to manual control at 96% power, but that the transfer was not recognized or expected by the operators. The alarm for this condition was received on annunciator B3-Fl, DFCS ALARM/TRBL, instead of B3-F3, RFP TURBINE AUTO XFR TO MANUAL. The licensee identified this as a design inadequacy. The "A" recirculation pump intermediate run back occurred due to faulty logic circuitry. The licensee's investigation also noted that the operators had not received adequate training on RFP operation in manual contro Operators took appropriate action to control event consequences and put the plant in a safe condition. An assessment of DFCS design deficiencies and associated inadequate operator training will be reviewed in a subsequent inspectio Reactor Startup On May 20, 1994, the licensee commenced a reactor startup in accordance with HC.OP-IO.ZZ-0003(Q), Startup From Co'/d Shutdown to Rated Power, following the May 15 low level reactor scra The inspector noted that numerous control rods (CR) were sticking in the 00 position during the startup. As a result, Nuclear Control Operators (NCOs) were routinely alternating quickly between the insert and withdraw pushbuttons for the CR hydraulic control units (HCUs) and raising CRD differential pressure (dp) to the procedure limit of 400 psid to effect rod movement. Two operators raised the drive pressure to levels approaching the procedure limit. Neither of the operators was aware of the correct limit specified in procedure HC.OP-AB.ZZ-104(Q), Stuck Control Rod. In addition, the inspector noted that the procedure did not clearly specify whether the limit applied to static or dynamic system conditions. In response to these concerns, operations staff planned to review training effectiveness with respect to the Stuck Control Rod procedure, and initiated a review of the procedure to clarify management expectations for use of maximum CRD pressur The inspector noted that the licensee had a problem with sticking control rods during the April 25 startup as well. The CRD system engineer did not have trending data on stuck control rods, i.e. which rods stuck, for how long, how were they freed, how long at elevated CRD dp, etc. Based on GE recommendations, the licensee subsequently changed the Stuck Control Rod procedure to allow up to a 500 psid d The inspector concluded that, although no unsafe conditions existed, the NCOs demonstrated weak performance in their lack of awareness of the pressure limit established in the CRD procedure. Further, the lack of trending stuck control rods for adverse trends demonstrates a weakness in assurance of qualit *
8 "A" and "C" Safety Auxiliary Cooling System (SACS) Pump Trips On May 30, 1994, the" A" and "C" SACS pumps ("A" Loop) tripped. At the time of the event, the "A" loop was supplying cooling water to the Turbine Auxiliary Cooling System (TACS), while the "D" SACS pump was running in the "B" loop supplying safety load Valves closed automatically to isolate TACS from the "A" Loop, and the "B" SACS pump started automatically. Operators restored SACS in accordance with Abnormal Procedure HC.OP-AB.ZZ-0124(Q), Safety Auxiliaries Cooling System Malfunction, which included manually opening the "D" SACS pump isolation valves to TACS, since the "D" pump was operating in manual, and manually opening the common header isolation valves to TACS, allowing the "B" SACS loop to supply TACS. SACS/TACS loads were swapped or secured to support the new lineup. The "A" SACS pump was restarted when conditions stabilized to supply safety loads. The licensee initiated an investigation to determine the cause of the pump trip The inspector concluded that operator actions to restore SACS/TACS to service were adequate. However, the "A" SACS pump was restarted before the cause of the trip was known. Further, the licensee declared the "A" and "C" SACS pumps operable without determining the cause of the trips, stating that the probable cause was pump runout resulting in low pump differential pressure. However, the low differential pressure alarm was not received for either of the "A" loop pumps. The licensee investigation and root cause analysis were still in progress at the end of the inspection perio ffigb Presmre Coolant Injection (HPCU Alternate Suction Valve On June 9, the licensee discovered that the HPCI alternate suction valve did not meet the commitments stated in the current licensing basis (CLB). A member of the Hope Creek Safety Review Group (SRG) determined that PSE&G had committed to meet NUREG 0737 requirement Il.E.4.2 for automatic containment isolation valves. The NUREG requires that automatic containment isolation valves do not re-open as a result of resetting the isolation signal. The NUREG requires that, in addition to resetting the isolation, deliberate operator action must be required to open containment isolation valves. In the case of the HPCI alternate suction valves, the SRG found that the valve would automatically reopen upon resetting the isolation if a low condensate storage tank water level or high suppression pool water level existe The licensee performed an operability determination, and concluded that the valve was operable, since the valve would remain closed for a valid HPCI isolation signal, and would open to permit HPCI suction from the suppression pool under design conditions. The licensee documented the basis for their determination in a 10 CFR 50.59 evaluation. In addition, the licensee planned to review the CLB commitments documented in the Safety Evaluation Report, and to make licensing submittals to correct the CLB, as appropriate.
- The inspectors noted that, when the licensee identified the discrepancy, PSE&G staff took immediate action to resolve the operability question. The inspectors also noted that NRC Generic Letter 91-18 states that licensees must consider the CLB when performing operability determinations. Pending further guidance on NRC requirements for considering CLB commitments in operability determinations, this item will remain unresolved. (URI 50-354/94-11-01) MAINTENANCE/SURVEILLANCE TESTING Maintenance Inspection Activity The inspectors observed selected maintenance activities on safety-related equipment to ascertain that the licensee conducted these activities in accordance with approved procedures, Technical Specifications, and appropriate industrial codes and standard The inspector observed portions of the following activities:
Work Order(WO) or Design Unit Chan~e Pacwe <PCP>
Description Salem 1 WO 940502154 Excessive Cooldown Design Change Package Salem 1 WO 940610164 Correct Low Demand Signal for Feedwater Regulating Valve Salem 1 WO 940516188 Correct poor Auto Control of Atmosphere Steam Dump Salem 1 WO 940719005 Replace Internal Components to Air Start Motor Air Regulator Salem 1 WO 940521119 Replace Reactor Head Vents Salem 1 WO 940520130 Replace Pressurizer Code Safety Valve Salem 1 WO 940606166 Replace Service Water Pump Salem 1 WO 940429243 Replace Power Operated Relief Valve Internals Salem 1 WO 940531085 Repair Shutdown Bank C Indicator Salem 2 WO 940516204 Turbo Air Boost Test Button Repair
Salem 2 WO 940614077 Salem 2 WO 940607168 Salem 2 WO 940531127 Hope Creek WO 930120104 Hope Creek WO 940201166 Hope Creek WO 940202091 Hope Creek WO 940525159 Hope Creek WO 940615012 Hope Creek WO 940509174 Hope Creek WO 930821021 Hope Creek WO 940601174 Hope Creek WO 940329037 Hope Creek WO 940602118
Steam Dump Control Valve Linkage Repair CFCU Service Water Outlet Valve Modification Replace 22SW76 Valve Operator
"D" Service Water Traveling Screen Basket Replacement
"D" Service Water Pump Discharge Check Valve Replacement
"D" Service Water Strainer Backwash Arm Replacement
"A" Control Room Chiller Freon Leak CRD In-Line Conductivity Analyzer Calibration Repair CRD In-Line Conductivity Meter
"A" Service Water Strainer 18-month PM Inspection Replace "A" Service Water Strainer Vessel Cover
"D" EDG Relay Maintenance
"D" EOG Protective Relays Alarm and Function Verification The maintenance activities inspected were effective with respect to meeting the safety objectives of the maintenance progra.2 Surveillance Testing Inspection Activity The inspectors performed detailed technical procedure reviews, witnessed in-progress surveillance testing, and reviewed completed surveillance packages. The inspectors verified that the surveillance tests were performed in accordance with Technical Specifications, approved procedures, and NRC regulation,.
The inspector reviewed the following surveillance tests with portions witnessed by the inspector:
Unit Procedure N Test Salem 1 SC.MD-ST.MS-0001 Main Steam Safety In-Place Testing Salem 1 S l.IC-ST.SSP-0006(7)
Train A (B) RTB and P-4 Permissive Prior to Startup Salem 1 Sl.OP-ST.AF-0003 Inservice Testing - 13 Auxiliary Feedwater Pump Salem 1 Sl.IC-ST.SSP-0010(11)
SSPS Train A (B) - RTB UV Coil and Auto Shunt Trip Salem 1 Sl.OP-PT.TRB-0001 Turbine Auto Trip Mechanisms Operational Test Salem 1 S 1. OP-ST.MS-0003 Steam Line Isolation and Response
Time Testing Salem 1 Sl.RE-RA.ZZ-0013 Increase Count Rate Ratio During Reactor Coolant System Boron Dilution Salem 1 Sl.RE-RA. ZZ-0002 Increase Count Rate Ratio During Control Rod Withdrawal Salem 2 TS2.0P-ST.RC-0002 Reactor Coolant System Flow Path Calculation Hope Creek HC.OP-IS.BE-0002(Q)
"B" and "D" Core Spray Pumps Inservice Test Hope Creek BC.OP-ST.KJ-0003
"Emergency Diesel Generator CG400 Operability Test - Monthly" Hope Creek HC.OP-ST.BJ-0001
"HPCI System Piping and Flow Path Verification" Hope Creek HC.OP-ST.BD-0001
"RCIC Piping and Flow Path Verification"
The surveillance testing activities inspected were effective with respect to meeting the safety objectives of the surveillance testing progra.3 Inspection Findings 3.3.1 Salem Control of Maintenance On May 25, Salem unit 2 day shift operators were scheduled to perform pump surveillances for the no. 21 residual heat removal (RHR) pump and the no. 21 auxiliary feedwater (AFW)
pump. During night shift on May 24, the no. 2A emergency diesel generator (EDG) was out of service for planned maintenance. The maintenance included troubleshooting a turbo air boost solenoid and testing the unit in accordance with work order (WO) 94051620 Maintenance personnel suspected a failed solenoid and discovered a failed switc Operations personnel held support staff onsite to expedite the process for upgrading a commercially obtained replacement switch so that the 2A EDG could be returned to servic The NRC learned that no spares were available to replace the suspected faulty solenoid. In addition, inspectors questioned the need to dedicate the replacement switch, since the test circuit did not affect EDG operability. The inspectors concluded that, although the licensee did not exceed the Technical Specification 3.8.1. relative to the allowed outage time for the 2A EDG, plant staff unnecessarily extended the 2A EDG outage time due to inadequate preparation for the trouble-shooting activity. Specifically, management oversight insured that sufficient resources were available to assure timeliness commensurate with safety, but the planning process did not focus on safety sufficiently to insure that the required parts were available in advanc * Service Water (SW) Butterfly Valve Replacement On June 2, 1994, the licensee cross-tied the two safety-related SW headers in order to perform maintenance on a SW valve on the discharge of No. 22 containment fan cooler unit (CFCU). Technical Specification 3.7.4 requires two independent loops of SW and has a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement for the return of an inoperable loop. Valve 22SW76 is a manually operated butterfly valve located just downstream of the SW flow control valve. Its intended function. is to. provide the capability to isolate SW to the CFCU for maintenance. Turbulent flow into the butterfly valve causes vibration that degrades the manual operator. The vibration resulted in repair of the operator three times in 1994. The licensee's long term corrective action was to relocate 22SW76 away from the flow control valve to reduce vibration. This modification was planned for implementation during the next refueling outag *
---
On June 2 the licensee attempted an interim action to replace the valve and actuator under work order (WO) 940531127. The licensee expected that replacement of the valve would reduce vibration and ensure that the actuator would not require additional maintenance prior to the outage. The operators could not successfully isolate 22SW76 and drain the connected SW piping due to the leakage past various SW system butterfly valves being used for isolation. Consequently, maintenance chose to replace only the manual actuator for 22SW7 The two safety-related SW headers were returned to their normal alignment on June 4, approximately 45 hours5.208333e-4 days <br />0.0125 hours <br />7.440476e-5 weeks <br />1.71225e-5 months <br /> after being cross-tie The system engineer and senior plant managers stated that replacement of the valve was not necessary to insure continued safe operation of the CFCU or the SW system. They indicated that they had discussed the safety benefit of voluntarily entering the Technical Specification Limiting Condition for Operation action statement to replace the valve. The system engineer based his judgement on recent observations of valve condition, inspection of the valve internals during the last refueling outage, and engineering judgement. The inspector determined that plant staff could have repaired the manual operator for 22SW76 without cross-tieing the SW headers. Operating the plant with the two headers cross-tied constituted an increase in risk and the licensee did not adequately consider this information when they elected to perform the non-essential maintenanc The inspectors concluded that, for the EOG and SW maintenance discussed above, the work planning process did not include sufficient consideration of net safety benefit compared with the increased risk associated with unavailable safety-related equipment. The plant manager stated that consideration of the increased risk contrasted to the safety benefit was an area for improvement in the Salem work planning process. The inspectors noted that the work described above did not constitute unacceptable risk, since the activities were conducted within the confines of Technical Specification limitations for safety-related equipment outages. The inspectors also noted that the plant manager had previously recognized the need for improvement in the Salem planning process, and had initiated measures for improvement. These measures included reorganii.ation, increased staffing, and clarification of the standards for planning performanc.3.2 Hope Creek "D" Service Water Traveling Screen Basket Replacement On May 23, 1994, the inspector observed the replacement of "D" Service Water traveling screen baskets. The procedure covering basket replacement, HC.MD-CM.EP-0003(Q),
Service Water Traveling Screens Overhaul and Repair, did not contain step-by-step actions to do the maintenance, although the maintenance was within the skill level of mechanics. This posed a potential personnel safety concern, since the operation required the rigging and movement of heavy components and parts. Though the licensee used a unique method of moving the traveling screens for basket replacement to enhance personnel safety, the method was not proceduralized.
The licensee revised procedure HC.MD-CM.EP-0003(Q) to provide step-by-step guidance on basket replacement including the technique used to improve personnel safety. The inspector concluded that the procedure revision was adequate and had no further personnel safety concern Control Rod Drive (CRD) In Line Conductivity Analyzer Calibration On May 26, 1994, the inspector observed two chemistry technicians performing maintenance on the CRD In Line Conductivity Analyzer. The technicians stated that they were replacing faulty circuit cards in the analyzer and that the power to the associated electrical panel had not been secured prior to beginning the work. The inspector noted that taped power leads extending from the electrical panel were a potential safety hazard.* When questioned, the technicians stated that this type of work was routinely done without de-energizing the equipmen Upon further investigation, the inspector found that the PSE&G Safety Manual,Section XV (Electrical). paragraph 2.2, states that work may be performed on energized equipment rated 100-600 volts using approved insulating tools and protective equipment. The licensee stated that de-energizing electrical equipment with these voltage levels was left to the technician's discretion. In this case, the technician had taken adequate safety precautions. However, the procedure used by the technician for troubleshooting, HC.CH-EU.ZZ-0035(Q), Leeds and Northrup In Line Conductivity Analyzer, did not contain adequate guidance for de-energizing circuitry. The licensee revised the procedure to provide this guidance. The inspector concluded that this electrical maintenance was safely performed and that the procedure revision was adequat.0 ENGINEERING Salem NRC Followup To Unit 2 Power Operated Relief Valves (PORVs) Materials In response to the licensee's discovery that incorrect internals for the 2PR1 and 2PR2 had potentially been installed during the last Unit 2 refueling outage (2R7), the inspectors investigated the history of the materials that had been used by PSE&G for the internals of 2PR1 and 2PR2 and reviewed the work process that had been used by the licensee to install the valves during 2R The inspectors determined that the original material used for the Unit 2 PORVs when the unit went in service in 1981 was 17-4 PH stainless steel. As a result of industry experience with seat leakage and susceptibility to galling, and in response to TMI Action Item II.D. l, PSE&G implemented a design change in 1982 and installed PORV internals (plug and stem)
made with 304 stainless steel with a stellited plug. Previously, the licensee removed loop
seals from the PORV installations. Based on vendor recommendations, the licensee intended to upgrade this material during 2R7 with 420 stainless steel to accommodate the different environment with loop seals remove The licensee prepared two work orders (WOs) for the Unit 2 PORVs to be accomplished during 2R7: one for the repetitive task of inspecting the valve internals and replacing them with 304 stainless components if necessary, which is routinely done at every refueling outage; and another WO for the installation of 420 stainless steel internals to be accomplished per the approved design change package. As part of the WO for the routine inspection of the valves, the licensee pre-staged a new set of internals in case the parts needed to be replaced. Licensee records indicated that the pre-staged set of internals was made of 17-4 PH stainless steel; the licensee could not explain why 17-4 PH and not 304 stainless steel had been pre-staged other than the recognition that 17-4 PH parts had still been in the PSE&G inventory. Warehouse material issue tickets indicated that it was this set of pre-staged parts that was mistakenly issued for the performance of the WO that was to accomplish the upgrade to 420 stainless stee While the licensee recognizes that the 17-4 PH parts were not intended to be installed in the Unit 2 PORVs, their evaluation concluded that use of the parts was not unsafe, even though other material was considered better for this application. The licensee's conclusion was based on: the acceptability of 17-4 PH material performance supported by the analysis of test results as presented in the Salem FSAR for original licensing; the continued supply of the material by the vendor for other licensees' use; and the fact that, while 17-4 PH stainless steel is more susceptible to long term wear, the current internals will only be used for one fuel cycle (PSE&G plans to replace the internals at the next Unit 2 refueling outage). The licensee performed a 10 CFR 50.59 Safety Evaluation to justify the continued use of the current installed valve internals for the remainder of the current fuel cycle. The Safety Evaluation was approved by the Station Operations Review Committe The inspectors reviewed the licensee records for the procurement and disposition of the 17-4 PH valve materials and for the performance of the two applicable WOs, and discussed the results of the licensee's investigation into the matter with licensee management. The inspectors determined that the 17-4 PH stainless steel valve internals manufactured by Copes Vulcan had been issued by the PSE&G warehouse for the material upgrade WO, as evidenced by component tagging and warehouse receipts. The inspectors also identified that the component tags for the 17-4 PH parts had been included in the paperwork that had accompanied the WO for the material upgrade design change. The inspectors were unable to positively determine if it had been those components that had been installed into the PORV valve bodies during the performance of the WO, although the inspectors did identify three separate sets of hand-written notes that indicated that the internals that had been removed were separately removed from the work area. All parts that were removed as part of that WO had been disposed of by the licensee, and the inspectors concluded that it will not be until the next outage when the valve is opened for examination that the identity of the valve internals will be positively determine **
In addition, the inspectors determined that the licensee had procured a total of six sets of 420 stainless steel internals. The inspectors determined that the accounting of those six sets supported the belief that 420 stainless steel parts had not been installed in the Unit 2 PORV The inspectors noted that only two quality control hold points had been required for the installation of the valve internals: one to witness a blue contact check of the internals and one for a cleanliness inspection of the valve prior to valve closur By examination of available 17-4 PH and 420 stainless steel valve internals in the PSE&G warehouse, the inspectors determined that there was no readily identifiable means of distinguishing the two different materials and that the licensee explanation of the events of 2R7 was plausible. The inspectors determined through their review of the available records (including the 10 CFR 50.59 Safety Evaluation) and discussion with licensee personnel that there was a reasonable level of assurance that the current internals of the Unit 2 PORVs are made of 17-4 PH stainless steel and that these internals do not compromise the ability of the valves to perform their design function. However, the inspectors also noted that the licensee failed to prevent the use of incorrect parts (i.e., parts other than those specified by the specifications of the modification). Atmospheric Steam Relief Valves (MS-10s) and Steam Flow Transmitters The effect of the atmospheric steam relief valves (MS-lOs) on the Salem Unit 1 event of April 7, 1994 is documented in NRC Inspection Report 50-272&311/94-80. Licensee action to correct the "reset windup" (inability to respond to steam pressure increases) was documented in NRC Inspection Report 50-272&311/94-11. As documented in that report, the MS-10 valves were designed to prevent challenges to the main steam code safety valve In March 1977, the licensee modified the control circuits for the MS-lOs to prevent undesired and inadvertent opening of the MS-lOs. That modification contributed to the failure of the MS-lOs to function appropriately by remaining closed in a condition (on April 7, 1994) which required the valve to open automatically. Consequently, a main steam code safety opened, resulting in a Safety Injectio The licensee corrected the circuit by restoring the control circuits to their 1977 configuration and making adjustments to insure that the valves operated to control steam pressure as originally intended. The inspectors noted that, in response to the June 10 Unit 1 trip, the MS-lOs worked as designe The licensee found that their analysis for the 1977 modification did not identify the potential that the MS-lOs would not respond properly to increasing steam pressure. The licensee subsequently identified the lack of MS-10 response to pressure increases. An approved digital feedwater modification (scheduled for implementation in 1993 at Unit l) was intended to resolve the deficiency. However, the licensee delayed the implementation of the modification. Consequently, the licensee allowed the MS-lOs to function in a degraded
condition from March 1977, until April 7, 1994. The inspectors noted that the licensee failed to promptly identify and correct the mis-operation of the MS-lOs from March 1977, until April 7, 199 During the April 7th transient, the first safety injection (SI) signal was caused by low RCS temperature coincident with a spurious high steam flow signal of short duration. The resultant SI signal, also of short duration (about 15 milliseconds), actuated one train of equipment that injected water into the vessel, complicating the event. The inspectors noted that event sequence records for reactor and turbine trips on June 10, 1989, July 11, 1993, and February 10, 1994, also show that a spurious high steam flow signal had been presen As noted above, the licensee failed to promptly identify and correct the spurious signal on, at least, those three previous occasion.2 Hope Creek Spent Fuel Pool Minimum Temperature Analysis (Closed) Unresolved Item (50-354/94-01-01); This item identified a potential concern with the analyzed minimum temperature required in the spent fuel pool (SFP). The item remained open pending Nuclear Fuel's evaluation of the minimum SFP temperature for fuel racks designed and built by Pa Nuclear Fuel personnel performed a criticality analysis for the spent fuel racks designed and
.built by Par. The analysis accounted for dimensional tolerances, variations in materials, and credible abnormal occurrences such as a dropped assembly next to a rack. Nuclear Fuel's analysis showed that the Par racks at 40°F, allow for a worse-case final kcir of.9434. This kctr is less than the.9500 design limit. The licensee performed a 10 CFR 50.59 review to make the changes to the Hope Creek FSAR concerning the qualified temperature of the Par rack The inspector reviewed the SFP criticality analysis and calculations, FSAR requirements, and the licensee's 10 CFR 50.59 review. The inspector determined that the analysis was thorough and conclusive, the calculations were technically accurate, and the 50.59 review appropriate for the FSAR change. In addition, the inspector noted that reactor engineering used sound engineering judgement in allowing fuel handling operations to continue with SFP temperature less then 68°F on February 16. Reactor engineering had made the decision to continue based upon a newer approved analysis used on the new Holtec fuel racks, reactivity of the bundles in the Par racks, and movement of new non-irradiated fuel bundles containing reactivity poisons. This item is close.0 LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS, AND OPEN ITEM FOLLOWUP LERs and Reports The Salem and Hope Creek Monthly Operating Reports for March and April were reviewed for accuracy and content, and were determined to be acceptable. The inspectors also reviewed the following LERs to determine whether the licensee took the corrective actions stated in the report, and to determine if licensee responses to the events were adequate, met regulatory requirements conditions, and commitments:
Salem LERs Unit 1 Number LER 93-20 LER 94-007 LER 94-007-01 Unit 2 LER 94-001 LER 94-004 LER 94-005 Event Date January 23, 1993 April 7, 1994 April 7, 1994 January 15, 1994 March 3, 1994 April 3, 1994 Description Reactor Coolant System Accumulator Upper Range Level Indication Inaccuracies Reactor Trip from 25 % Power/Two Safety Injections Reactor Trip from 25 % Power/Two Safety Injections - Supplement to Correct Editorial Error in Original Entry into TS 3.0.3 to Support Maintenance on the Analog Rod Position Indication System
-
Late Performance of Offsite Power Availability Surveillance Due to Untimely Determination of Diesel Generator Inoperability Late Surveillance Testing of Reactor Trip System Power Range Instrument Channel
l}
LER 94-006 LER 94-007 Hqpe Creek LER 94-003
March 25, 1994 April 11, 1994 April 5, 1994 Failure to Declare pressurizer Relief Valves Inoperable After Closure of Pressurizer Block Valves Blackout Signal Loading of 4kv Vital Buses Due to Personnel Error During Surveillance Test Loss of Shutdown Cooling Due to Nuclear Steam Supply Shutoff System Actuation on False High Pressure Signal For the LERs listed above, the inspectors determined that there were no violations or deviations, and considered the LERs close.2 Open Items The inspector reviewed the following previous inspection items during this inspection. These items are tabulated below for cross reference purpose Rewrt Section Hope Creek 50-354/94-01-01 4. Closed EXIT INTERVIEWS/MEETINGS Resident Exit Meeting The inspectors. met with Mr. J. Hagan and Mr. J. Clancey and other PSE&G personnel periodically and at the end of the inspection report period to summarize the scope and findings of their inspection activitie Based on NRC Region I review and discussions with PSE&G, it was determined that this report does not contain information subject to 10 CFR 2 restrictions.
. ~ }
. '
20 Specialist Entrance and Exit Meetings Inspection Reporting Date(s)
Subject Report N Inspector 5/31 - 6/3/94 Operator Licensing 50-354/94-12 Caruso 6/13-17/94 Security 50-272 and 311/94-16; 50-354/94-15 Albert