IR 05000272/1994035
| ML18101A566 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 02/21/1995 |
| From: | Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18101A565 | List: |
| References | |
| 50-272-94-35, 50-311-94-35, NUDOCS 9503010081 | |
| Download: ML18101A566 (16) | |
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Report No License No Licensee:
Facility:
Dates:
Inspectors:
Approved:
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
50-272/94-35 50-311/94-35 DPR-70 DPR-75 Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, New Jersey 08038 Salem Nuclear Generating Station December 18, 1994 - January 28, 1995 c. J. T. L. Inspection Summary:
Date This inspection report documents inspections to assure public health and safety during day and back shift hours of station activities, including:
operations, maintenance and surveillance, engineering, and plant support. The Executive Summary delineates the inspection findings and conclusion.. *
EXECUTIVE SUMMARY NRC Inspection Reports 50-272/94-35; 50-311/94-35 December 18, 1994 - January 28, 1995 OPERATIONS (Module 71707, 92901) Failure to unblock the high steam line flow safety injection signal prior to exceeding 545°F is a violation of Technical Specification 3.3.2.1. However, the violation is not cited since the criteria of 10CFR2, Appendix C, Section VII were met relative to NRC enforcement discretio Operations exhibited good control and communication in safely controlling the Unit 2 power reduction following a safeguard equipment control (SEC) proble Controls troubleshooting was thorough and focused on the root cause of the SEC fault. However, it appears that more aggressive pursuit of the cause of previous SEC test faults may have led the resolution of recurring SEC problems in a more timely manne Operations contributed significantly to the safe, uneventful reactor coolant pump seal and pressurizer code safety valve wor Operations demonstrated improved attention to detail, good focus on safety and thorough pre-job plannin MAINTENANCE/SURVEILLANCE (Modules 61726, 62703)
Licensee corrective actions in response to a reactor coolant pump seal water return valve solenoid failure were comprehensive and appropriat The licensee did not initially provide the appropriate level of management review of a reactor coolant pump seal maintenance procedure. However, when workers implemented the procedure after management review, the procedure provided very effective control of the work process and the work proceeded as planne The licensee's process for assessing the overall safety impact of removing a system from service for on-line scheduled maintenance is effectiv PSE&G incorporated the risk defined by the Salem Individual Plant Examination and properly integrated scheduling, planning, engineering, maintenance and operations input into the proces ENGINEERING (Module 37551, 71707) Licensee's planned action to reduce reactor coolant pump oil leakage, closely monitor motor performance and oil leakage, and further evaluate motor structures for possible modification were appropriat System engineering, together with planning and operations organizations, continue to pursue control air system performance deficiencies that have the potential to challenge plant operation Operations took timely action to address turbine-driven auxiliary feedwater pump operability concerns following discovery of locked closed vent panel System engineering discovered inappropriately locked vent panels in the turbine building and initiated effective and timely resolution of the proble Security, radiation protection, and operations coordinated well with the engineering organization to resolve the vent panel problem.
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System engineering's thorough inspection of service water p1p1ng revealed a degraded condition on the no. II service water header. Operations responded promptly to resolve the problem and address potential service water operability concern Engineering personnel worked closely and effectively with maintenance and operations staff to determine the cause of pressurizer relief valve seat leakage in Unit 2. Safety consciousness and conservatism was demonstrated by management's decision to effectively resolve the safety valve leakage problems before returning the unit to servic PLANT SUPPORT (Module 71707, 71750)
The inspectors concluded that the radiation protection, maintenance, and engineering staff continued to effectively control and limit worker exposure to radiation.Licensee response to a contaminated wrench used outside the radiologically controlled area was appropriate.
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SUMMARY OF OPERATIONS Unit I was on line throughout the inspection period. Operators maintained the unit at 100% power except for minor power reductions to support turbine testing, and a reduction to 25% on January 6 due to a safeguard equipment control power supply failur Unit 2 began the period in Cold Shutdown (Mode 5).
On December 25, 1994, operators placed the unit in Hot Standby (Mode 3) in preparation for plant startup following the units' eighth refueling outag However, on January 11, 1995, operators cooled down the plant to place the unit in Mode 5 due to leakage past the pressurizer safety valve On January 26, following repairs to the pressurizer safety valves, operators placed the unit in Mode The unit ended the period in Mode 3 as operators made final preparations for reactor startu.0 OPERATIONS The inspectors verified that Public Service Electric and Gas (PSE&G) operated the facilities safely and in general conformance with regulatory requirement A non-cited violation was identified (Section 2.1 pertains). 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 61 hours7.060185e-4 days <br />0.0169 hours <br />1.008598e-4 weeks <br />2.32105e-5 months <br /> of deep back-shift inspection.1 Blocked High Steam Line Flow Safety Injection Actuation Logic At 9:15 a.m. on December 26, 1994, a licensed senior reactor operator realized that the high steam line flow safety injection (SI) actuation logic was blocked while average coolant temperature was above 545°F. Technical Specification 3.3.2.1 requires that the high steam line flow SI signal is unblocked when RCS temperature is ~ 545° The operator immediately unblocked the SI signal and entered TS 3.0.3 for the 15 minutes that temperature was above 545°F with the SI signal blocke At the same time, the low pressurizer pressure SI was also blocked as RCS pressure was < 1915 psig. This condition provided no SI protection for a main steam line break downstream of the main steam isolation valves (MSIVs).
However, the licensee had the MSIVs closed at this point in the startu (A downstream break has no safety consequence with the MSIVs closed.)
Instrumentation and Controls (I&C) was conducting S2.IC-PT.RCP-0001, Reactor Coolant RTD Cross Calibration, at the time of the event. The procedure disables the automatic unblocking of the SI signal above 543° The control room operator was notified by I&C technicians, as required by the RTD cross calibration procedure, to manually unblock the SI signal if necessar In addition, Integrated Operating Procedure 2, Cold Shutdown to Hot Standby, stated that the operator was to manually unblock the SI signal if it did not automatically unblock at 543° *
The licensee initiated positive discipline with the involved operations personne The licensee briefed all operating shifts on the lessons learned from the above occurrence and included the occurrence in licensed operator requalification retraining. Operations made enhancements to their IOP-2 procedure to help preclude future similar occurrence The inspector noted that control room operator inattention to detail during a plant heatup contributed significantly to the above occurrenc The inspector concluded that the incident had minor safety significance since the MSIVS were closed at the tim In addition, the inspector found that the violation of Technical Specification 3.3.2.1.b was: (1) not a recurring problem, (2)
identified and adequately addressed by the licensee, and (3) not willful. The inspector determined that the violation satisfied the criteria in Section VII.8 of the Enforcement Policy and, consequently, will not be cite.2 Safeguard Equipment Control Power Supply Failure At 3:13 a.m. on January 6, 1995, Unit 1 control room operators received a trouble alarm for the No. lA safeguard equipment control (SEC) syste Operations declared the No. lA SEC inoperable and dispatched a technician to investigate. The technician recorded the indicating lights and reset the SEC; however, the SEC did not complete two Automatic Test Insertion (All) test cycles before faulting again. Technicians assumed that a clock problem existed in either the logic board or the All board. Technicians replaced the logic and All boards but the fault remaine Consequently, Maintenance Controls broadened their troubleshooting scop At 9:13 a.m. on January 6, Unit 1 operations conunenced a Technical Specification (TS 3.3.2.1) required shutdown due to the inoperable SE Maintenance troubleshooting, together with system engineering support, identified a degraded 24 volt power supply. Maintenance replaced the degraded power supply and satisfactorily completed the SEC functional surveillance. At 1:40 p.m. on January 6, operators stopped the power reduction at 24% power, and declared the lA SEC operable. Maintenance evaluated the 18 SEC and IC SEC power supplies and found no degradation in the voltage sourc The inspector noted that, following the licensee's initial efforts to resolve the SEC problem, the Instrumentation and Controls (I&C) troubleshooting was thorough and focused on the root cause of the All fault. The inspector observed that operations maintained good control and communication in safely effecting the unit power reductio The inspector noted that the licensee activated the ATI circuit since the SEC required shutdown of December 9, 1994 (see NRC Inspection Report 50-272/94-31), but failed to aggressively pursue SEC test faults generated prior to the January 6 alarm. A more thorough root cause approach may have avoided the SEC required plant power reduction of January 6. In addition, the inspector observed recurring All test faults on both the IA SEC and 18 SEC since the January 6 occurrence (three on lA SEC; one on 18 SEC). The licensee continues to investigate these spurious test faults and has contacted a specialist to evaluate the problem *
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3 Operations Oversight of Plant Activities During the inspection period, plant operators actively participated in insuring that activities with the potential for effecting plant operation occurred safely and without incident. For example, operators questioned the completeness of a 10 CFR 50.59 review drafted in preparation for Reactor Coolant Pump (RCP) seal wor As a result, the evaluation improved significantly. The operators helped to facilitate a thorough pre-job brief conducted by system engineering personne In addition, operators insured that plant staff provided expectations and limits for RCP leakage during preparation for the seal work, and an SRO monitored the maintenance activity with the authority to terminate the maintenance in the event that leakage exceeded expected, manageable level Operators also contributed to effective performance of the pressurizer code safety valve wor The operators facilitated a thorough pre-job briefing, and contributed to the quality of operability determinations through interaction with engineering. Operations endorsed the decision to not operate the plant with the leakage past the seats, and to determine the cause of the leakage and correct i PSE&G senior management supported the operations positio For both of the activities, operations performed detailed reviews of work packages and procedures developed by maintenance engineering personnel and identified a number of improvements and clarifications. The inspectors concluded that Operations' contribution to safe uneventful RCP seal and pressurizer code safety valve work demonstrated improved attention to detail, good focus on safety, and thorough pre-job plannin.0 MAINTENANCE AND SURVEILLANCE MAINTENANCE The inspectors observed portions of the following safety-related maintenance to determine if the licensee conducted the activities in accordance with approved procedures, Technical Specifications, and appropriate industrial codes and standard The inspector observed portions of the following activities:
Salem 2 Salem 2 Work Order(WO) or Design Change Package CDCPl WO 950116062 WO 941121158 Description
- No. 21 Service Water Pump Strainer Repair 2A DG Low Starting Pressure Alarm DCP The inspectors observed that the plant staff performed the maintenance effectively within the requirements of the station maintenance program.
- 3.1.1 Failure of Air Solenoid Valve for No. 23 Reactor Coolant Pump (RCP) Seal Water Return Valve On January 11, with Unit 2 in Mode 4, the No. 23 RCP seal water injection return valve for the Number 1 seal closed, isolating seal flo Operators took the appropriate actions and secured the pum Operators continued the plant cooldown, in progress due to pressurizer safety valve leakage, and placed the plant in Cold Shutdown {Mode 5).
The licensee initiated a root cause investigation of the seal return valve
{23CV104) closur The seal return valve is normally open and is air operated to close. Licensee investigation determined that a degraded pressure diaphragm in solenoid valve 23SV441 allowed air to leak by the solenoid valve to the seal return valve operator. The leak permitted sufficient air pressure
{10-15 psig) to develop to close the seal return valv The licensee determined that the pressure diaphragm of the ASCO solenoid valve failed because of its extensive time-in-service (about 20 years) coupled with the continuous air pressure applied at the diaphragm (about 80 psig). This combination of time and pressure eventually caused the diaphragm material, buna-n, to lose its suppleness and allow air to leak by the disc. The investigation also revealed corrosion products in the air line. The corrosion was a product of the carbon steel piping and moisture in the air syste However, the licensee discounted the effects of corrosion on the failure because the solenoid valve internals were not clogged or foule In reviewing the maintenance history of similar air solenoid valves for the other RCPs, the licensee determined that from initial plant operation through January 1995, Maintenance had replaced each of the four solenoid valves on Unit 1 and one on Unit None of these replacement valves was a repeat failur PSE&G also noted that Engineering had decided, during initial installation of the valves, that no recommended maintenance schedule for these valves was necessar Licensee corrective actions included replacing the solenoid valve for each Unit 2 RCP, establishing a maintenance schedule for replacing the valves every 7.5 years, and conducting a station-wide review of all systems that use this type of solenoid valve to identify additional replacement candidates. The licensee plans to replace the Unit 1 RCP solenoid valves during its upcoming outage in Apri The inspector reviewed the root cause investigation and determined the cause was credible. The inspector also noted licensee corrective actions were comprehensive and appropriat.1.2 Reactor Coolant Pump (RCP) Seal Maintenance On January 11, with Salem Unit 2 in Mode 4, the No. 23 RCP seal water return valve for the number 1 seal closed, isolating seal flo As a result, Westinghouse reconvnended that PSE&G inspect the Number 1 seal for indications of damag Such activity would normally require reducing water inventory to mid-loo However, in order to effect better safety margin by reducing
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inventory less, Salem management, after consulting with Westinghouse and other licensees, elected to perform the maintenance by lowering the RCP onto the
"backseat" formed by resting the radial bearing on the thermal barrier heat exchanger. The existing Salem procedure, SC.MD-CM.RC-OOOl(Q), Reactor Coolant Pump Seal Disassembly, Inspection, Repair, and Reassembly, required significant revision, since it assumed mid-loop conditions for RCP seal wor Salem personnel had not previously performed RCP seal work with fuel in the vessel without reducing RCS level to reduced inventory conditions. Plant management's decision to lower the RCP onto the backseat to perform the maintenance without going to reduced inventory conditions, provided greater RCS inventory and reduced the likelihood of Residual Heat Removal (RHR) pump vortexing and loss of net positive suction hea Salem maintenance staff made numerous changes to the procedure to provide careful instructions for lowering the RCP and to ensure an effective backseat to limit RCS leakage during the seal work. After reviewing the procedure and observing the backseat activities, the inspectors concluded that the procedure provided very effective control of the backseating process. Notwithstanding, the inspectors noted that some weaknesses existed in the procedur For example, the procedure did not establish initial plant conditions for the backseating activity, and did not specify the conditions to be maintained during and after the backseating proces The inspectors also noted that senior plant management initially did not review the revised maintenance procedure though the procedure revision was extensive, the plant staff had not previously performed the proposed evolution with fuel in the vessel, and the potential existed to impact safety. After consideration, senior management concluded that a procedure change review was appropriate. Subsequently, several significant procedure improvements resulted from the management review
. When workers implemented the procedure, after management review, the work proceeded exactly as planned, i.e., safely and without even.1.3 Evaluation of On-Line Maintenance In order to evaluate the impact on safety of licensee procedures and practices regarding the removal of equipment from service for on-line scheduled maintenance, the NRC issued Temporary Instruction (Tl) 2515/126, "Evaluation of On-line Maintenance," as an addition to the NRC Inspection Manua The inspe~tor reviewed the practice of on-line maintenance at Salem using the guidance provided in TI 2525/126, with a focus on whether the licensee has in place a program that focuses on the risk factors involved and that evaluates the impact of scheduling on-line maintenance with regard for plant safet The Salem Planning Department is responsible for the scheduling and planning of maintenance activities at the Salem Station.* Schedulers in that department work with a 156-week schedule that is composed of 13 12-week schedules, each of which segregates planned work and surveillances by the affected equipment's power supply and control channel. The 156-week schedule is a rotating system window schedule that is based on preventative maintenance, planned maintenance, and surveillance frequencies. Approximately 45 days prior to performing a system outage, PSE&G performs a review of the existing system
work scope, including a system walkdow This review is conducted by a scheduler, a planner, the pertinent system engineer, and a representative from the Operations Departmen With the system work scope defined, current Salem practice calls for a net safety gain assessment to be performed approximately 30 days before the system is to be removed from servic PSE&G performs this type of assessment for all safety significant systems as defined by the maintenance rule (IOCFRS0.65),
and part of this assessment is a probabilistic risk assessment (PRA) performed by the PSE&G Engineering Sciences Group, the group that developed and maintains the Salem individual plant examination (IPE).
The PRA for the equipment to be removed from service includes an analysis of risk factors for initiating events, core damage, and a release from containmen The PRA also provides compensatory measures which can reduce risk while the system is out of servic Two weeks prior to system removal, Salem system engineering and scheduling are to have completed a net safety gain checklist which ensures that the system outage critical path has been identified, other maintenance or testing in conjunction with the system outage does not increase the likelihood of a plant transient during the outage, and that the system outage has been considered with regard to the overall schedule and plant condition As a final check of the work scheduling process, a meeting of planning, scheduling, operations, maintenance and engineering personnel is conducted within a week of the system outag The inspector discussed the Salem system outage process with members of the Salem Operations and Planning Departments and members of the PSE&G Engineering Sciences Grou The inspector also reviewed applicable PSE&G procedures (especially procedure SC.PS-AP.ZZ-0300(Z),"Daily Scheduling Guidelines"),
Salem management memoranda, and several PRAs that had been prepared for recent system outage The inspector determined that Salem planning and scheduling had made considerable progress over the last six months in addressing the areas of NRC concern involving on-line maintenance and system outages at powe The Salem process for assessing the overall safety impact of removing a system from service and for preparing for that system removal is a very good one; PSE&G incorporates the risk defined by the Salem IPE and properly integrates scheduling, planning, engineering, maintenance and operations input into the proces The inspector noted, however, that the current Salem process had yet to be proceduralize The above-defined process of system outage risk assessment has been a result of management directive via memoranda, and a formal program for the control of on-line maintenance had not yet been defined by procedur The licensee did provide the inspector with a draft attachment to SC.PS-AP.ZZ-0300(Z) that is intended to define that process* in a procedure. The inspector also noted that, while licensed operator awareness of the plant IPE and risk assessment had increased, no forma*l training on the on-line maintenance process or the IPE had been provided those operators. The Salem Operations Department informed the inspector that the type of training had been scheduled for inclusion in the next requalification training cycle *
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In summary, the inspector found the current Salem process for scheduling and assessing the risk of on-line maintenance to be very goo PSE&G had plans in place to address shortcomings in the areas of proceduralization and formal operator trainin.2 Surveillance The inspectors performed detailed technical procedure reviews, observed surveillances, and reviewed completed surveillance package The inspectors verified that plant staff did the surveillance tests in accordance with approved procedures, Technical Specifications and NRC regulation The inspector reviewed the following surveillances:
Unit Salem I Salem 2 Salem 2 Salem 2 Procedure N Sl.OP-ST.RC-0008 S2.0P-ST.SSP-0002 S2.RE-ST.ZZ-0002 S2.0P-ST.AF-0007 Test Reactor Coolant System Water Inventory Balance Engineered Safety Features Manual Safety Injection 2A Vital Bus Shutdown Margin Calculation In Service Testing Auxiliary Feedwater Valves The inspectors observed that plant staff did the surveillances safely, effectively proving operability of the associated system.0 ENGINEERING Control Air System Performance On December 19, 1994, Unit I operators maintained the block valve closed for 1PR2, one of two pressurizer power operated relief valves (PORVs), for a period of 41 minutes. Operators shut the block valve to comply with Technical Specifications (TS 3.4.3) due to low control air header pressure. Operators placed the header emergency air compressor in service, which increased control air header pressure and allowed operators to unblock the POR However, during this period of time IPR!, the remaining PORV, was* also blocke Operators blocked IPRI on November 1, 1994, due to leakage past the sea On December 20, operators closed the 1PR2 block valve for 16 minutes under similar circumstance The opening of the PORVs prevents actuation of the high-pressure reactor trip for all transients, up to a 50 percent step load decrease with steam dump actuatio PORV opening also limits the undesirable operation of the spring-loaded safety valve The inspector recognized that although PORV operability is desirable, it is not required by plant Technical Specifications, nor
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necessary to prevent plant over pressurization. However, degraded control air system performance affects PORV operability which can adversely impact overall plant operatio (Previous control air system abnormalities are noted in NRC Inspection Reports 50-272/94-19 and 94-2 The inspector noted a concerted effort by system engineering, planning, and operations to address control air deficiencies. Licensee troubleshooting in this area identified problems in control air dryer preventative maintenance, control air header leakage, and station air compressor (control air source)
load cycles. The inspector acknowledged the licensee's pursuit of control air system problem resolution. The effectiveness of the licensee's efforts will be examined in future inspection.2 Reactor Coolant Pump Oil Leakage Inspectors identified oil leakage located circumferentially about the no. 23 and no. 24 reactor coolant pump (RCP) platform The NRC held a conference call on January 26, 1995, with the licensee to evaluate the amount of RCP motor oil leakage, leakage acceptance criteria, and planned corrective action The licensee stated that the motors for RCP nos. 23 and 24 were of a 1975 Westinghouse design. This design was believed to restrict oil flow internal to the motor from the top of the upper oil reservoir upward toward the flywhee The No. 21 RCP motor uses an improved Westinghouse design structured with a truncated flow chamber and segmented covers to allow for better oil and air flow through the moto The licensee believed this internal structure contributed to a better motor internal leaktightnes The licensee performed a test on January 25, 1995, to determine the actual leakage being dispersed by No. 23 RCP motor. This test included a five hour run of the motor including three starts and stops of the moto The licensee stated that it was their judgement that starting and stopping the motor would produce the largest quantities of oil for conservatism in determining the amount of oil lost by the moto PSE&G collected oil found to have migrated past the upper labyrinth seal onto the ratchet plate by installing two oil traps on vent tubes located on the internal side of the upper labyrinth sea Approximately one ounce of oil was collected by the licensee from the ratchet plate. The licensee previously collected nine ounces of oil resulting from three weeks of RCP operatio The licensee calculated that this amount of oil loss corresponded to an expected 1.7 gallon total oil loss over an 18 month operating cycle. This quantity represented less than one percent inventory loss with respect to the 175 gallon oil filled upper oil reservoir. Control room operators receive a low level alarm following an eight gallon upper oil reservoir los The licensee further stated that the pressure and air flow measurements made under the flywheel during this test verified the assumptions made by Westinghouse prior to the test. This verification confirmed t~e expected cyclic air flow under the flywhee PSE&G stated that the lost oil inventory identified during this test did not affect pump operabilit The licensee stated that future analysis would be performed to evaluate the amount of oil leaking past the labyrinth seals. This analysis would include enhanced monitoring of motor performance during future shutdown conditions to evaluate oil leakage around the RCP motors and to confirm engineering judgement In addition, investigation of the possibility for installing truncated oil reservoirs and/or segmented covers on all RCP motors would be considere The licensee stated that further evaluations would be conducted with Westinghouse to address RCP motors installed in both Units 1 and The inspectors concluded that licensee actions to quantify the amount of oil leakage were valid for determining the inventory lost during the test perio The inspectors determined that the licensee's planned actions to reduce oil leakage, closely monitor motor performance and oil leakage, and further evaluate motor structures for possible modification were appropriat.3 Mechanical Steam Piping Penetration Area Vent Panels On January 23, 1995, a PSE&G system engineer noted that mechanical steam piping penetration area vent panels were locked closed and not in accordance with plant drawing Nuclear Engineering subsequently identified that the Final Safety Analysis Report (FSAR Sections 3.6.5.4/3.6.5.10) requires the vent panels be available to provide an atmospheric vent path in the event of a high energy steam line break outside containment. A high energy steam line break in the turbine driven auxiliary feedwater (TDAFW) pump enclosure could overpressurize the enclosure and adversely affect the motor driven auxiliary feedwater pumps (located immediately adjacent to the TDAFW pump enclosure)
without an adequate atmospheric vent path through the penetration area vent panels. The licensee found the above condition existed on both Salem units, and determined that the plant security had maintained the penetration area vent panels locked to prevent unauthorized access into the auxiliary building The licensee ensured appropriate security measures were in place prior to removing the vent panel lock On January 24, the licensee discovered that the hinged vent panels were obstructed and would not fully open if neede PSE&G recognized that the degraded condition of the vent panels placed the plants outside their design basi On January 24, maintenance removed the vent panel obstructions. Security posted the vent panels until January 27, when maintenance installed an internal security grating. The security grating allows for proper vent panel operation and serves to thwart unauthorized acces The inspector observed the unobstructed vent panels and the increased security measure The inspector noted that operations took prompt action to address TDAFW pump operability concerns.. In addition, the inspector noted that the discovery of the locked vent panels was a good finding by system engineering, and that security, radiation protection, and operations coordinated well with engineering to resolve the vent panel proble *
10 ' Service Water Header Inspection At 10:40 a.m. on January 11, 1995, during a weekly service water system walkdown, system engineering identified a degraded condition on the No. 11 common distribution header in the No. 1 service water ba System engineering discovered a 3/4" socket-welded cap broken off of an abandoned-in-place pipe on the distribution heade The pipe was filled with Belzona (a sealant)
which acted as the service water pressure boundary due to the degraded pipe cap. System engineering immediately notified operations. Operations declared the header inoperable and initiated actions to remove the header for maintenanc In addition, the licensee inspected their remaining service water headers for similar problem The licensee found no other examples of degraded service water pipin Maintenance coordinated with planning and operations to repair the degraded 3/4" pipe and to perform post-maintenance testing. Operations returned the No. 11 service water header to service and declared the header operable at 2:30 a.m. on January 1 The inspector noted system engineering's thorough service water piping inspection and prompt communication of concern The inspector observed operations' timely problem resolution and good safety perspective concerning service water operabilit.5 Engineering support of Pressurizer Code Safety Investigation During the startup from the refueling outage, Salem staff detected seat leakage from the pressurizer code safety valves (2PR3, 2PR4, and 2PR5).
Operators measured initial leakage, at approximately 1700 psig (RCS pressure),
of about 2.0 gallons per minute (gpm) for all three valves. Salem engineering staff surveyed industry experience with the Crosby relief valves, and attempted to seat the valves, by lowering RCS pressure to 1600 psig and slowly increasing pressure to normal operating pressure (2250 psig) and normal operating temperature (550 degrees F) (NOP/NOT). Although repeated attempts to stop the leakage by this method did not succeed, the gradual lowering and slow increases in pressure and temperature reduced total leakage for all three valves to about 0.5 gp Plant management considered several options, including operating the plant with the reduced leakage *. After deliberation, Salem management decided to determine the cause of the leakage. Engineering staff concluded, based on measurement and evaluation, that stress on the valve discharge flanges, caused primarily by thermal loading, had caused the seat leakage. Although the loading was within code limits for structural integrity, engineering concluded that the loading exceeded the limit supplied by Crosby to preclude seat leakag To verify their conclusion, engineering staff developed, and plant management reviewed and approved, a test to relieve the stresses on the discharge flang The plant staff carefully implemented the test plan with mixed results. The engineering staff noted some improvement in seat leakage with lower thermal loading, but they could not completely eliminate the leakage during the test. As provided in the test plan, operators placed the plant in cold shutdown so that maintenance staff could replace the valves, and engineering staff could adjust pipe hangars to permanently reduced pipe loadin ~..
The inspectors found that engineering personnel worked closely and effectively with maintenance and operations staff to determine the cause of the seat leakage and effect resolution. The plant was maintained in a shutdown condition while the licensee took actions to understand and resolve the conditio.0 PLANT SUPPORT Radiological Controls 5.1.1 Radiation Protection Coverage of Maintenance Activities As discussed in sections 3.1.2 and 4.5, above, significant plant activities occurred within the Radiologically Controlled Area (RCA) during this inspection period. Radiation Protection staff closely monitored those activities to insure minimum worker exposure and minimum risk of contamination. The inspectors noted that RP technicians frequently monitored the work areas for changing conditions, interacted with the workers to ensure implementation of good work practices, and to minimize the risk of contaminatio The inspectors concluded that the radiation protection, maintenance, and engineering staff continued to effectively control and limit worker exposure to radiatio.1.2 Contaminated Wrench Used Outside Radiologically Controlled Area (RCA)
On January 14, following calibration of a temperature probe on the no. 1 auxiliary feedwater tank (which is outside the RCA), a crescent wrench alarmed the small article monitor (SAM).
Radiation protection (RP) personnel confiscated the wrench and performed a direct frisk and smear survey of the wrenc They found 3000 dpm/16 cm2 fixed contaminatio Isotopic analysis showed the contamination to be Cobalt-60. Radiation Protection surveyed the auxiliary feedwater tank work area, and performed a direct frisk of the technician's desk and his tool area. They found no detectable activit The licensee conducted an investigation of the event, but was not able to determine how the wrench initially left the RC PSE&G also conducted random surveys of maintenance tool boxes, with all results negativ To detect additional potentially contaminated tools, they revised survey maps for selected areas outside the RCA to require tools and equipment in the area be surveyed for loose and fixed contaminatio The inspector reviewed the event and root cause investigation with the RP staff. The inspector determined licensee immediate actions were thorough and that corrective actions were adequate to both prevent recurrence and to help identify any other contaminated tools that might be outside the RC The inspector concluded licensee response to the contaminated wrench was appropriat *
12 Emergency Preparedness The inspector reviewed PSE&G's conformance with 10 CFR 50.47 regarding implementation of the emergency plan and procedure In addition, the inspector reviewed licensee event notifications and reporting requirements per 10 CFR 50.72 and 7.3 Security The NRC verified PSE&G's conformance with the security program, including the adequacy of staffing, entry control, alarm stations, and physical boundarie Inspectors observed good performance by Security Department personnel in their conduct of routine activitie.4 Housekeeping The inspector reviewed PSE&G's housekeeping conditions and cleanliness controls in accordance with nuclear department administrative procedure.5 Fire Protection The inspector reviewed PSE&G's fire protection program implementation in accordance with nuclear department administrative procedure Items included fire watches, ignition sources, fire brigade manning, fire detection and suppression systems, and fire barriers and doors. REVIEW OF REPORTS AND OPEN ITEMS The inspectors reviewed the Salem Monthly Operating Report for December for accuracy and content, and found it acceptable. The inspectors also reviewed the following Licensee Event Reports (LERs} to learn whether the licensee took the corrective actions stated in the report, and to detect if the licensee responded to the events adequately, met regulatory requirements conditions, and commitments:
Salem Unit 2 LER 94-013 October 23, 1994 LER 94-016 December 26, 1994 Core alterations and fuel movement without containment building penetration closur Unplanned entry into TS 3.0.3 due to an engineered safety feature being blocked above 545° The inspectors did not identify any deficiencies or discrepant information in the licensee's report, based on independent review of the events.