IR 05000272/1992012

Insp Repts 50-272/92-12,50-311/92-12 & 50-354/92-12 on 920726-0912.Violations Noted But Not Cited.Major Areas Inspected:Operations,Radiological Controls,Maint & Surveillance Testing,Emergency Preparedness & Security

ML18096B033
Person / Time
Site:	Salem, Hope Creek
Issue date:	09/30/1992
From:	Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML18096B031	List: IR 05000272/1992012 ML18096B030
References
50-272-92-12, 50-311-92-12, 50-354-92-12, NUDOCS 9210140029
Download: ML18096B033 (36)

Text

U. S.-NUCLEAR REGULATORY COMMISSION

REGION I

Report No /92-12 50-311/92-12 50-'-354/92-12 License Nos. DPR-70 DPR.:75 NPF-57 Licensee:

Public Service* Electric and Gas Company P.O. Box 236 Hancocks Bridge, New Jersey 08038 Facilities:

Salem Nuclear Generating Station Hope Creek Nuclear Generating Station Dates:

July 26; 1992 - September 12, 1992~

Inspectors:

T. P. Johnson, Senior Resident Inspector S. M. Pindale, Resident Inspector S. T. Barr, Resident Inspector *

H. K. Lathrop, Re * ent I_ pect~

Approved:

Inspection Summary:

This inspection report documents_ routine and reactive inspections 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. An Executive Summary follows, which summarizes the inspection findings and related* conclusion PDR ADOCK 05000272 G

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EXECUTIVE SUMMARY Salem Inspection Reports 50-272/92-12; 50-311192-12 Hope Creek Inspection Report 50-354/92-12 July 26~ 1992 - September 12, 1992 -

OPERATIONS (Modules 60705, 60710, 71707, 93702)

Salem: The Salem units were operated in a safe manner. The Unit 1 startup from refueling was conducted in a safe and deliberate fashion. Operator response and licensee followup to a Unit 2 reactor trip and Unusual Event-was very. good: Control room operator responses to two Unit 1 main steam line isolations and a Technical Specification 3.0.3 required shutdown

• were appropriate. Corrective actions taken following the licensee's identification that mode ascension occurred with several containment spray valves misaligned were timely and

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effective, consequently, the event was considered as a non-cited violation of Technica Specifications. Opeq1tor identification and response to several Unit 2 main turbine governor valve oscillations was appropriat *

Hope Creek: The unit was operated in a safe mi;umer. Operations personnel conducted a unit shutdown to commence the unit's fourth refueling maintenance outage in a professional and safety conscious fashio.

RADIOLOGICAL CONTROLS (Modules 71707, 93702)

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Salem: Periodic inspector observation of station workers and Radiation Protection (RP).

personnel noted good implementation of radiological controls and protection program requirements. Chemistry Department followup in response to a prior Unit 2 steam generator conductivity and chloride excursion was acceptabie. RP followup to contamination found outside the radiologically controlled area during a routine periodic survey was prompt and effective. The licensee appropriately responded to a routine chemistry analysis that *revealed indications of minor fuel cladding damage at Unit Hope Creek: Periodic inspector observation of station workers and Radiation Protection personnel noted good implementation of radiological controls and protection program requirement MAINTENANCE/SURVEILLANCE (Modules 61708, 61710, 61726, 62703, 72700)

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Salem: Observed maintenance and surveillance activities were well planned and conducted.

. Those activities were effective in meeting the safety objectives.in the respective program The licensee conducted a thorough review and implemented effective corrective* actions for a licensee-identified missed reactor breaker surveillance (personnel error), consequently, that event was considered* as a non-cited violation of Technical Specification surveillance requirements. Two additional personnel errors. resulted in an.engineered safety feature actuation during surveillance testing and a turbine trip during maintenance. Equipment response and licensee followup of these events were acceptabl Hope Creek: Maintenance and surveillance activities observed were well planned and conducted. Those activities were effective in meeting the safety objectives in the respective programs. _The licensee's investigation of and corrective actions for a water intrusion event into the primary containment fostrument gas system were appropriate and conservativ EMERGENCY PREPAREDNESS (Modules 71707, 93702)

. An Unusual Event on September 3, 1992, due to an unexpected response of the.main steam safety valves following a Salem Unit 2 reactor trip was properly classified, declared and reported. Equipment failures of the Salem Emergency Notification System were properly reported by the licensee. A Salem training drill was effectively executed by station and *

emergency preparedness personne SECURITY (Modules 71707' 93702)

Routine observation of protected area access and egress showed good control by the license Security personnel immediately and appropriately responded to a bomb threat that was*

subsequently determined to have been a hoa ENGINEERING/TECHNICAL SUPPORT (Modules 37828, 71707, 71711)

Salem: Review of the management of engineering work* activities* determined that they were being performed in accordance with applicable procedures and were being properly prioritized and executed. Weaknesses in the design and configuration of the main steamline (MSL) flow

• instruments resulted in two MSL isolations..Engineering has provided significant attention to the pressurizer power operated relief'valves in an attempt to resolve long-standing operational.

concerns; progress to date has shown moderate improvement. System engineering followup of operational concerns observed for a Unit 2 safety injection charging pump was conducted

. in a deliberate fashion. Commitments made by the licensee to the NRC relative to corrective actions regarding.the November 9, 1991, Unit 2 turbine/generator failure were fulfilled and adequately addressed on both unit i I

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Hope Creek:. Review of the management of engineering work activities determined that they were being performed in accordance with applicable procedures and were being properly prioritized and execute SAFETY ASSESSMENT/QUALITY VERIFICATION (Modules 40500, 71707, 90712, 92700, 92701, 92702, 94703, 2515/115)

Salem: A permanent, effective resolution remains to be completed for lo~g-standing operational problems associated with the analog rod position display system. Station management recognized and initiated action to address a noted increase in the personnel error rate. Station management provided an appropriate level of attention and oversight to operational, maintenance, and licensing issues dealing with a Unit 1 pressurizer level channe The Station Operations Review Committee properly considered all aspects of the September 3, 1992, Unit 2 reactor trip and conservatively deliberated the results of the post-trip revie Hope Creek: Concerns identified by station personnel were adequately resolved by the

. Safety Review Group Engineer. Licensee exhibited a safety-conscious and conservative approach to outage preparation and plannin Common: Licensee response to concerns related to falsification of fire watch written logs was proactive and timely; one unresolved item was initiated to track continued NRC followup of licensee-identified deficiencies for Salem in this are *

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SUMMARY OF OPERATIONS Salem Units 1 and 2 Unit 1 began the inspection period shutdown as a result of a maintenance outage undertaken -

to accomplish main feedwater piping repairs. This outage immediately followed the unit's tenth refueling outage. The unit's reactor was made critical on August 11, 1992, powe ascension and reactor physics testing were accomplished, and full power was achieved on August 25. The unit remained at full power for the remainder of the perio Unit 2 began the period at full power. On August 1, *1992, power was briefly reduced to 75 % to clean a condensate pump suction strainer~ On September 3, 1992; a reactor trip occurred.due to personnel error. Following a post-trip investigation, *the unit was synchronized to the grid on September 7, and remained at full power through the end of the

• perio.2 Hope Creek The unit remained at or near rated.power until commencing a powe~ coastdown and

• completing a shutdown at the end of the report period for the unit's fourth refueling outag At the time of shutdown, the unit had been on-line _for 88 continuous day *.

OPERATIONS Inspection Activities The inspectors verified that the facilities were operated safely and in conformance with regulatory requirements. Public Service Electric and Gas (PSE&G) Company management control was evaluated 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 deep back-shift (35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br />) inspection.2 Inspection Findings and Significant Plant Events 2.2.1 Salem Unit 1 Startup Activities The inspector observed portions of the Unit 1 mode change and power ascension activities following the unit's tenth refueling and maintenance outage. Control room operators effectively controlled personnel access to the control room to minimize distractions. When operational difficulties were encounter~, such as control rod position indication problems, the operators took conservative actions and appropriately implemented station procedure and

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Technical Specification requirements. The reactor was made critical on August 11, 1992, and the unit was placed on-line August 16, 1992. The inspector concluded that the Unit 1 startup. activities were conducted in a safe manne Unit 2 Reactor Trip and Unusual Event Declaration On September 3, 1992, at 9: 18 a.m., the Salem Unit 2 reactor experienced an unexpected automatic reactor trip. The cause of the trip was not immediately apparent. The plant computer records showed the initiating event of the trip to be the opening of the 11A 11 reactor trip breaker without valid trip signals generated by.the unit's Reactor Protection System. At the time of the trip, a non-licensed equipment operator (BO) was present at the "A 11 reactor trip bypass breaker cubicl The resident inspector was onsite and immediately responded to the Unit 2 control roo The operating crew implemented the Emergency Operating Procedure for a reactor trip and

• stabilized the plant at normal operating pressure and temperature (NOP/NOT). All plant systems functioned as designed with the exception of certain main steam safety valves (MSSVs).

Following the reactor trip, the main steam isolation valves were manually shut to prevent an excessive primary coolant cooldown rate. The erisuing secondary pressure increase caused one MSSV on two steam generators to lift at approximately 1050 psig, below the* MSSV setpoint of 1070 psig. Steam generator pressure was not initially relieved by the atmospheric power operated relief valves, whose lift setpoint is 1035 psig, since the response of the automatic controller for these valves *was not immediate due to the operating characteristics of the device. The MSSVs failed to completely close when the plant was cooled down to NO *Consequently, the licensee declared an Unusual Event at 10:05 a.m. when the MSSVs failed to reseat. The operating crew conducted *a plant cooldown to 530 degrees F to allow the MSSVs to completely close and positively reseat. The UE was terminated at 1 :42 p.m. when the MSSVs were shown to be closed with no evidence of steam weepin The licensee immediately began their post-trip review and initiated a Significant Event Response Team (SERT) to investig~te the cause of the trip and the behavior of the MSSVs following the trip. Over the two days following the reactor trip, the licensee conducted an extensive series of tests on the "A" reactor trip breaker, the reactor trip and bypass breaker cubicles, the solid state protection system, and the MSSVs. All components associated with the plant's reactor trip system tested satisfactorily and provided no evidence of a cause for the

_reactor trip. The MSSVs were examined and showed no signs of abnormal behavio Licensee engineering evaluations and input from the valve manufacturer, Crosby Valves, determined that the* secondary plant pressure, reached subsequent to the closing of the main steam isolation valves, was high enough that MSSV opening could *be expected considering the lift setpoint drift which.may have occurred since the last ASME Code valve inspection (in 1988..:89). According to the valve manufacturer, fluttering of the MSSVs was expectable -

• behavior (i.e., the lift setpoint of the valve tends to change if a significant amount of steam has passed through the valve and warmed the spring mechanism). Consequently, the valves would tend to respo~d to a lower steam pressure than the initial setpoin The licensee had previously initiated a design change to address the slow response of the *

steam generator atmospheric relief valves and plans to ins~l new controllers for those valves at the next refueling outage in order to' decrease r;elief valve reaction time and prevent premature actuations of the MSSVs in the future..

Due to the satisfactory test results achieved with respect to the reactor trip system components, the licensee focused their attention on the presence of the EO in the trip breaker cubicles. The licensee, through interviews and physical evidence, accumulated circumstantial evidence indicated that the reactor trip was likely caused by an inadvertent action of the E At the time of the trip, the licensee had beeri making preparations to perform surveillance testing ofthe Up.it 1 "A" reactor trip breaker. The EO was to rack in the Unit 1 "A" bypass reactor trip breaker in order to make the reactor trip breaker available for testing. While instrument and control technicians were preparing the Unit 1 reactor trip breaker cubicles for the testing, the EO went to the Unit 2 reactor trip breaker.cubicles to re-familiarize himself with the arrangement of the detent mechanism which locks the trip breakers in place. The arrangement of the reactor trip breakers and bypass trip breakers in Unit 2. is different from

. * that of Unit 1, and altering the position of the detent mechanism on a closed reactor trip breaker will cause that breaker to ope The EO admitted to the licensee's investigators that he was not aware that the trip breakers could be tripped upon movement of the detent mechanism. That fact, combined with the different arrangement of the units' reactor trip breakers, led the licensee to concluc;le that the most_probable cause of.the trip was that the EO presumed he was in the bypass breaker cubicle, and altered the position of the detent mechanism on the Unit 2 "A" reactor trip breake *

Notwithstanding the probable cause, the licensee replaced the "A" reactor trip breaker and initiated actions to ship the Qriginal breaker to Westinghouse for a complete tear-down and evaluatio The results of the post-trip review and the preliminary conclusions of the SERT were considered by a Station Operations Review Committee (SORC) on September 5, 1992. The SORC determined that personnel error was an acceptable most probable cause for the trip

• event and authorized a plant restart~ In order to test the MSSVs, the licensee h.ad maintaine the unit in Mode 3 (Hot Standby), and the startup was commenced from there on the evening of September 5, and the reactor was made critical at 4:38 p.m. on September 6. The p~ant was synchronized to the grid at 6:00 a.m on September 7, and the startup was completed without inciden I

While in the Unit 2 control room following the reactor trip, the inspector noted that the operating crew's performance of the required immediate actions and the emergency operating procedures was excellent, and control room decorum and access control were well maintaine The resident inspector staff sub_sequently monitored and observed portions of all relevant testing of the reactor trip and bypass breakers and their cubicles, and the MSSVs. The inspectors found the testing to be well planned, and properly and thoroughly conducte Throughout the licensee's investigation of the event, the inspectors monitored and evaluated the 11.censee's progress; and observed and assessed the performance of the post-trip review, the September 5 SORC meeting, and the SER Ttie inspector concluded that Salem Station management's response to the event was goo The thorough post-trip* investiga_tion, including personnel interviews and equipment testing, was noted by the inspector to be encouraged and supported by plant management. The

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inspector observed that the SORC, in theiI September 5 meeting, properly considered all aspects of the event prior to authorizing a unit restart and conservatively deliberated the _

results of the post-trip review and preliminary SERT conclusions.* The inspector found the SORC root-cause determination and subsequent restart authorization to be appropriate; and the SERT performance to be adequate in providing an independent investigation of the event, including the root cause determination. The SERT report was not completed prior to the end of the inspection period and remains to be reviewed by the inspector. Notwithstanding that review, the inspector determined that the licensee performed well in their immediate and follow-up responses to this even Unit 1 Mode Change to Mode 4 With Containment Spray Valves Closed During Unit 1 startup operations on July 31, 1992, at 1 :45 p. m., the Unit 1 operating crew discovered that valves 11 and 12 CS20, the containment spray eductor supply valves, were in the, closed position. At 2:00 p.m. on the same day, valves 11 and 12 CS6, the containment spray header valves, were also found in the closed position. Unit 1 had entered Mode 4, Hot Shutdown, at 11:45 a.m. on July 30, and the Unit 1 Technical Specifications (TSs) require these valves to be open, in order to make the containment spray system operable, in Modes 1 through 4. The valves were found to be in the wrong position while the licensee was..

reviewing the "Components Off Normal Position" report in preparation for taking the unit to Mode 3. Immediately upon discovering the mis-positioned valves, the operating crew opened

• and -locked in position the four affected valves to satisfy the TS requirements. By 2:46 on July 31 all four valves had been returned to the proper position. Until the valves had been opened, however, both containment spray systems were considered inoperable, and the unit was forced to enter Technical Specification 3.0.3. Due to the short time required to remedy the situation, the operating crew did not initiate a plant shutdown and cooldown before TS 3.0.3. was satisfied and exited.

• The licensee initiated a prompt investigation into the cause of the-event. This investigation

. determined tile root cause of the event to be personnel error attributed to poor work practice While the unit had been in Mode 5 (Cold Shutdown) and preparing Mode 4 (Hot Shut.down),

an equipment operator (BO) was dispatched to verify that the four.CS.valves were in the proper position. Since the unit was still ih Mode 5, the EO mistakenly used a valve positio11 sheet for that mode that showed the closed position as an acceptable position for these valves'.

Subsequently, he reported to the Unit 1 Nuclear Shift Supervisor (NSS) that the valves were in the correct position for Mode 4. The NSS did not verify that the EO meant tha~ the valves were open and proceeded with the unit startup, in accordance with integrated operating procedure IOP-2, "Cold Shutdown to Hot Standby." It was not -until the Mode 3

"Components Off-Normal Position" report was checked that the licensre. realized the actual position of the valve In addition to the immediate corrective actions of opening the valves and.counseling_ the involved personnel with respeet to their work practices, 'the licensee initiated-the additional corrective action of revising IOP-2 to have the procedure require the NSS to issue a tagging release for the valves and to verify the proper valve position before entering Mode The Unit 1 Operations Engineer promp-tly notified the resident inspector of the event and informed the inspector of the immediate corrective actions taken and of the intended revision to IOP-2. The inspector determined the licensee had correctly made the required entry into TS.3.0.3 and had taken the appropriate actions to rectify the-situatio The containment spray systein is designed to remove heat from the containment atmosphere following a loss of coolant accident and, by entraining an NaOH sollJtion in the spray, remove radioactive iodine from the post-accident containment atmosphere. The inspector

verified that the safety significance of the event was *minimized due to all five containment fan coil units (CFCUs) being available at thetime of the event, but that the event had constituted a violation of the unit TSs for a period of approximately 27 hours3.125e-4 days <br />0.0075 hours <br />4.464286e-5 weeks <br />1.02735e-5 months <br />. For design basis accident, five CFCUs provides adequate containment heat removal and depressurization, *

regardless of the containment spray loops. This violation is not being cited, however, because the inspector verified that all the criteria specified in Section VII.B of the NRC Enforcement Policy had been satisfie Unit 2 Main Turbine Governor Valve Oscillations On August 11, 1992, and then twice again on September 10, Salem Unit 2 main generator*

electrical load decreased slightly due to the main turbine governor valves partially closing without demand. The August 11 event irivolved a drop of approximately 80 megawatts, while both September 10 events were of a 20 megawatt magnitude. All three events lasted less than one minute each, and each corrected itself without operator action. Salem System Engineering had initiated an investigation of the phenomenon and determined that the governor valve behavior was most likely caused by electronic spikes in one of six different circuits in the main turbine electro-hydraulic control system. The inspector discussed the

• matter with the system engineer and found that the licensee intends,to install brush-type recorders on the six circuits in order to identify* the responsible circuit. Since the installation of the recorders would involve the risk of tripping the main turbine, _the licensee scheduled the installation of the monitoring equipment upon a forced outage. The* inspector determined that the monitoring equipment was previously scheduled to be installed during the outage following the September 3, 1992, reactor trip, but due to art impr~isely worded workorder and miscommunication between maintenance supervision, the work order was not accomplished. *The inspector will monitor licensee action and performance in the resolution of this matter in future inspection *

2.2.2 Hope Creek Unit Shutdown For Refueling On September 11, 1992, at 5:00 p.m'., operations personnel began a controlled shutdown of the unit in preparation for the fourth refueling outage. Reactor power was* stabilized at about 15% to allow the performance of several special tests associated with the main generator:

. The generator was then removed from the grid and the unit was manually scrammed at 3:03 a.m. on September 12, 1992. Unit cooldown to Operational Condition 4 (reactor temperature

,less than 200 degrees F) followe The resident inspector staff monitored operations activities throughout the power reduction,

• unit scram and initiation of plant cooldown and made the following observations:

Command and control as exercised by the senior reactor operator on shift was excellent. Individual responsibilities were clearly indicated for personnel both inside the control room and those performing various tests/evolutions in the power bloc The shift turnover briefing was comprehensive and was augmented by periodic updates to the control room personnel as the shutdown progresse *

Good control Of qutside evolutions was noted on the part of all the nuclear control operators (NCOs). "Repeat backs" were heard for almost all instructions issued as well as for information received from personnel in the power bloc *

Shortly after the reactor was manually scrammed, the "A" reactor feed pump tripped on low suction pressure when the "B" secondary condensate pump minimum flow valve failed to close as operators were re-aligl)ing the condensate system to support the reduced feedwa:ter requirements. Operators responded promptly to the incident,

.recovering reactor water level from a low of about * + 15 inches to the normal operating level (about +30 inches) before ariy safety system actuations would initiat The inspector concluded that shift personnel had conducted the shutdown in a professional and safety conscious manner, with close attention to detail and in strict accordance with their procedure..

7 RADIOLOGICAL CONTROLS Inspection Activities PSE&G's conformance with the radiological protection program was verified on a periodic basi.2 Inspection Findings 3.2.1 Salem Steam Generator Chemistry Followup In response to a Unit 2 steam gen~rator chernistry excursion (high conductivity and chloride concentration) on May 13, 1992, the licensee implemented additional actions during the recent Unit 1 startup. Unit 1 had been shutdown for approximately five months for a refueling and maintenance outag To ensure that similar chemistry problems would not occur during the Unit 1 s.tartup in August 1992, all three heater drain pumps.(HDPs) were momentarily operated (bumped) in the recycle system alignment. The heater drains were sampled on the discharge side of each HDP before and after each bump. The sample analyses indicated acceptable sodium and chloride levels. Based on the results, the licensee concluded that no additional HDP flushing was required or routine HDP bumping and heater drain sampling in recycle during each refueling startup. The licensee determined that the previous Unit 2 problems were directly

• attributable to the N~vember 9, 1992, turbine generator failure event, which resulted in river water intrusion into the secondary system through the failed condenser tube The inspector discussed the Unit 1 activities with the Chemistry Engineer (CE). The CE*

indicated that the Chemistry Department was evaluating a potential change to an associated integrated operating procedure to ensure that chemistry parameters are monitored via in-line instrumentation as the HDPs are placed*in service. The inspector concluded that the licensee's actions were acceptabl * Contamination Found Outside the Radiologically Controlled Area (RCA)

On August 31, 1992, a Radiation Protection (RP) technician identified contamination outside the Radioactive Waste Building roll-up door while performing a routine periodic survey. A particle w~s found embedded in_ the asphalt and was removed upon discovery. The survey indicated a contamination level of 60,000 dpm. RP technicians had been performing quarterly surveys at RCA egress points under new guidelines since September 199.

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. The licensee initiated an Incident Report and a Radiological Occurrence Report (ROR) to evaluate this event. An analysis and calculation by the licensee indicated that the particle age was roughly 3.5 years. At the end of this inspection, the root *cause of the corttaminatfon was not 19lown and the investigation was continuing. The* inspector noted that the RP initial

response to this identification was timely and thoroug Indications of Minor Fuel Cladding Perforation

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On September 1, 1992, Chemistry personnel detected an increase in the specific activity of the Unit 1 reactor coolant system (RCS). The unit had previously reduced power from 100%

to 90% on August 30, to repair the No. 11 heater drain pump. Power was restored to 100%

ori August 31. The RCS Dose Equivalent Iodine-131 (DEI) on September 1 was 0.009

microcuries/gram (uCi/g). A normal DBI value is about 0.001 uCilg. The licensee evaluated the chemistry data, and determined that possibly one fuel pin in a twke-cycled fuel assembly may have a cladding leak. The particular assembly is in its third and final core cycle. Through the end of the inspection period, the Unit 1 RCS DBI had been relatively stable at between 0.004 and 0.008 uCi/ The maximum allowed DBI value allowed by Techqical Specifications (TSs) for both units is 1.0 uCi/ Therefore, operation is well within TS requirement *

Unit 2 has also been operating with slightly elevated DBI levels of between 0.004 and 0.007 uCi/g.* The Unit 2 DBI increase was detected on June 20, 1992, following a unit shutdown due to feedwater system piping erosion/corrosion issues. The licensee confirmed that analysis results indicate a slight cladding defect, also on a twice-cycled fuel assembly. No significant DBI spikes have occurred since June 20, 199 The inspector observed that the licensee was closely monitoring and evaluating the increased DBI levels on both units and had no further question.2.2 Hope CJ'.eek The inspectors did not identify any noteworthy finding.

MAINTENANCE/SURVEILLANCE TESTING Maintenance Inspection Activity

- The inspectors observed selected maintenance activities on safety-related equipment to ascertain that these activities were conducted in accordance with approved procedures, Technical Specifications, and appropriate industrial codes and standard *

Portions of the following activities were observed by the inspector:

Salem 1 Salem 1 Salem 1 Salem 2 Salem 2 Hope Creek Hope Creek Work Order(WO) or Design Change Package (DCP)

Various; Temporary Modification No.92-056 WO 920806129 W0-920910122 WO 920807169 Various DCP 4EC-3254 Various*

_ Description Emergency Turbine Trip Solenoid Vaive No. 20/ET - Investigate and Repair No. 13 Auxiliary Feedwater Pump Governor Adjustment Investigate No. 13 Auxiliary Feedwater Pump Oscillations No. 22 Charging Pump Speed Increaser Replacement Reactor Trip and Bypass Breaker and Cubicle Test and Inspection Filtration, Recirculation and Ventilation System (FRVS) Heater Control Panel Modification Installation of VOTES Sensor 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 regulations~

The following surveillance tests were reviewed, with portions witnessed by the inspector:

Procedure No. -

Salem 1 SI.OP-ST. TRB-0002(Q)

Turbine Protection System - Full Functional Test

• Salem*2 Salem 2 Salem 2 Salem 1&2 Hope Creek

S2.MD-FT.SEC-0003(Q)

2IC-18.1.013 SC. MD-ST. RC:P-0001 (Q)

Various SE-PR.EG-001 2C Safeguards Equipment Control Sequ~ncer Monthly Surveillance Reactor Trip Breaker 18 Month Surveillance*

"A" Reactor Trip Breaker Functional Tests Unit 1 and 2 Pressurizer Power Operated Relief Valve Stroke Time Testing Safety Auxiliaries Cooling System (SACS) Heat Exchanger Performance Tes The surveillance testing activities inspected were effective with respect to meeting the safety objectives of the surveillance testii:ig progra.3 * 'Inspection Findings 4.3.1 Salem Missed Reactor Trip Breaker Surveillance Due to Personnel Error On July 24, 1992, the licensee identified that the semi-annual Technical Specification (TS)

surveillance for the No. 2A reactor trip breaker (RTB) was not performed within the required time interval. The surveillance was last performed on November 1, 1991, when the breaker was in the 2A bypass RTB position. The licensee determined the cause of the missed surveillance to be. personnel error (inattention to detail). Specifically, -a maintenance planner did not properly update the surveillance schedule to reflect the fact that the breaker from the 2A bypass RTB position was moved to the 2A RTB position subsequent to the* November I, 1991, surveillanc Inspector review of this event identified that the RTB surveillance work orders are issued against RTB position, not against the. specific RTB serial number. Therefore, it becomes important to document RTB position changes to maintain the RTBs in conformance with TS surveillance requirements. On July 24, 1992, the semi-annual surveillance was satisfactorily completed for the 2A RTB. Other licensee corrective actions included taking disciplinary action and reviewing this event with the applicable maintenance personnel. Although this missed RTB surveillance constituted a TS violation, this licensee identified violation is not being cited because the criteria specified in Section VII.B of the NRC Enforcement Policy were satisfie *

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11 Engineered Safety Features Actuation Due to Personnel Error On July 27, 1992, during a Unit 2 monthly functional test of the 2A 4kV vital bus, technician mispositioned a test switch, causing a bus. 4ndervoltage condition to be sense That condition resulted in an automatic start_ of the 2A emergency diesel generator and subsequent loading of the associated equipment, including the No. 21 auxiliary feedwater pump. The licensee attributed the cause of this event to be personnel error (poor work.

practices) in that the technician involved did not implement self-check techniques as required

. by station work standards. All equipment functioned as designed and was subsequently restored to normal. LiCensee corrective actions included reviewing this event with applicable station personnel and stressing the necessity to implement self-:cheek techniques. The inspector concluded that the licensee's followup*to this event was appropriat Inadvertent Turbine Trip.During.Maintenance On August 17, 1992," an inadvertent turbine trip occurred at Unit 1 during maintenance. **

Reactor power was approximately 22 %. A reactor trip did not automatically occur as a result of a turbine trip because the unit was operating at less than 49% power (P-9 permis_sive).

Maintenance technicians were repairing the main generator voltage regulator adjustor when a maintenance technician apparently inadvertently bumped a main generator protection relay,

• resulting in the automatic turbine trip. The associated relay is located very close to the comporient that was being worke *

The inspector reviewed the licensee's response to the turbine trip and found. that associated equipment functioned normally. Additionally, the appropriate turbine trip abnormal procedure (No. Sl.OP-AB.TRB-0001) was entered and followed by control room operator The inspector also reviewed operator logs and selected control room chart recorders to verify that unit response was as expected.* The voltage regulator maintenance activity and subsequent generator synchronization was completed without further incident. The licensee

. discussed this event with-the technicians involved. The inspector concluded that the licensee's response to this event was appropriat * *

4.3.2 Hope Creek Water Intrusion Into The Primary Containment Instrument Gas (PCIG) System During surveillance testing utilizing the traversing incore probe system (TIP) in August 1992, difficulties were encountered in driving several probes into* the reactor core. The surveillance was completed satisfactorily, however. On August 16, 1992, following a control rod pattern adjustment the licensee found that the "A" and "C" TIP drive units were inoperabl Attempts to drive. in the "B" and "D" units were also unsuccessful., An initial investigation indicated water had entered the TIP tubing and mixed with the tubing lubricant designed to facilitate probe movement. The resulting mixture increased the friction in the tubes to a point

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where the drive mechanisms could not drive the probes through the tubing. Since the TIP tubing is normally supplied with a nitrogen purge to prevent moisture buildup, the licensee suspect~ the PCIG system had become contaminated with water. A substantial amount of water was blown down from each PCIG gas receiver, however the gas exiting the PCIG compressors' inner and after coolers was dry, indicating no cooler leakag The licensee eventually determined that the most likely source of the water was from backleakage from the main steam isolation valve sealing system (MSIVSS), for which PCIG.

provides the sealing gas. While PCIG is normally isolated from MSIVSS, piping where water could collect is open~ to the PCIG system during several periodic instrument

• calibration and surveillances. The licensee's corrective actions included performing more frequent blow downs of the PCIG receivers, draining of affected portions of PCIG piping prior to surveillances on instrument calibrations, and initiating work orders to 1) inspect and repair the suspect leaking MSIVSS isolation valves, and 2) inspect and clean the TIP tubing during the upcoming refueling outag The inspector reviewed this event and its potential consequences with operations and epgineering personneL Since PCIG provides the motive force for a number of safety-related valves inside the drywell (MSIVs*, safety/relief valves, and containment isolation valves), the inspector_ was concerned that water in the PCIG lines could render one or more components inoperabl *

The licensee stated that due to an earlier.water intrusion event, safety-related components in the drywell were checked during the mini-outage in March 1992. The PCIG distribution header in the drywell was blown down from two drains, with a very small spray of moisture*

issuing from each. Six of the ten lowest elevated components (below the distribution header)

were disconnected and inspected. No moisture was found. Based on this and other comprehensive examinations, the licensee concluded. that operability of drywell components was not affecte *

.

.

Additionally, the licensee indicated that the accumulators for both the MSIVs and relief

• valves were blown down during each refueling outage. No moisture was found during the third refueling outage (January - February 1991). Engineering personnel also stated that the PCIG piping in the drywell and torus would be blown down during the fall refueling outage, including lines to the MSIVs and relief valves. Based on the results of the earlier investigation and measures taken to prevent further water intrusion,_ the inspector concluded that the licensee had acted appropriately and conservatively in determining the source of the water, establishing corrective actions, and assuring of safety-related equipment operability.

)

.

13 EMERGENCY PREPAREDNES.1 Inspection Activity The inspector reviewed PSE&G's conformance with 10CFR50.47 regarding implementation of the emergency plan and procedures. In addition, licensee event notifications and reporting requirements per 10CFR50. 72 and 73 were reviewe.2 lnspeetion Findings Emergency Communications On August 5 and 14, 1992, and on September 10 and 11, 1992, the Salem Emergency Notification System (ENS) became inoperable. The current ENS phone is the recently installed FTS 2000 System. The NRC initiated trouble reports with the local telephone company on all four occasions, and repairs were subsequently completed. The inspector verified that.the licensee properly reported the loss of the ENS on the above dates in accordance with 10CFR50. 72 reporting requirements. * Eniergency Preparedness Training Drill The inspector participated in and observed the licensee's training emergency preparedness (EP) drill, conducted on August 28, 1992: The inspector participated at the Salem simulator

• and observed portions of licensee response from the Technical Support Center, Operations Support Center and the Emergency Operations Faci_lity. The inspector concluded that the drill provided an effective training session for the participants. The annual NRC graded EP

. exercise in currently scheduled for October 28, 199 : SECURITY Inspection Activity.*

PSE&G's conformance with the security program was verified on a periodic basis, including the adequacy of staffing, entry control, alarm stations, and physical boundarie.2 Inspection Fi!tdings Security. Response to Bomb Threat On August 7, 1992, Security personnel responded to a telephone bomb threat targeted at an Artificial Island cafeteria. Security immediately searched the three on-site cafeterias (Salem, Hope Creek and Administration Building) and did* not identify any explosives or incendiary devices. The licensee identified the individual responsible for making the phone call and subsequently confirmed that the threat was a hoax. Employment action was taken against* the

• non-PSE&G visiting service contract employee. The licensee concluded that this non-nuclear threat was not reportable per 10CFR50. 72 or 10CFR73. 71, however, they did inform the NRC of the event. The inspettor.reviewed the licensee's actions and concluded that the Security personnel appropriately responded to this even.

ENGINEERING/TECHNICAL SUPPORT Salem Main Steam Line Isolations Two inadvertent steam line (MSL) isolations (art engineered safety feature actuation)* occurred at Unit 1 on July 30 and August 5, 1992, while in Mode 4 (Hot Shutdown) and Mode.3 (Hot Standby), respectively. All valves that were required to close upon receipt of the MS isolation signal were already closed for both events. The July 30, 1992, isolation was caused by flashing of condensate in the reference leg of the steam flow instrumentation during the heatup through Mode 4. The August 5, 1992, event was caused similarly, however, erratic operation (speed oscillations) of the turbine-driven auxiliary feedwater (AFW) pump contributed to the steam flow channel spikes on the two main steam lines (Nos. 11 and 13),

. which provided the steam supply for th(f AFW turbine.. Both events were reported to the NRC in accordance with 10CFR50. 72 reporting requirement The licensee's troubleshooting for both events concluded that the false high steam flows were not caused by failed components, and the signals had subsequently cleared on their ow This design deficiency was previously documented in NRC Combined Inspection 92-09 and in previous licensee event reports. Engineering personnel had recently completed a detailed

.

design evaluation of the existing steam flow instrumentation, and design modifications. were being developed to address the operational concerns. The inspector concluded that operator response to the MSL isolations were proper and in accordance with station procedure Pressurizer Power Operated Relief Valves In July 1992, the licensee installed a temporary modification (T-moq) on the Unit 1 and 2 pressm;izer power operated relief valves (PORVs) and instituted a quarterly stroke test schedule to monitor the effectiveness of the T-mod. The PORVs are reverse-acting, air to open, spring to close, three inch relief valves, and function to relieve reactor coolant system (RCS) pressure during pressure transients to minimize the undesirable opening of the three spring loaded code safety valves.* They are also used during reactor cooldown and shutdown operations to protect against RCS overpressurization. There are two PORVs per uni Previous actuator bolting, sealing and design considerations had resulted in excessive ai leakage through the actuator flange area (see NRC Combined Inspection 91-26). The licensee subsequently implemented several PORV modifications, including changing the actuafor cover I

bolt pattern from a 12 to 24 pattern design and changing the elastomer diaphragm materia However, air leakag~ continued to occur and represented a potential for excessive PORV stroke times. The required time to _open a PORV is two second The T-mod that was implemented in July 1992 instailed an o-ring inside the top portion of the PORV actuator, concentric with the cover flange. The purpose of the o-ring was to provide an additional seal to the actuator cover seal. Prior to installing the T-mod at either unit, the proposed T-mod was installed in an identical-diaphragm air actuator at the PSE&G Training Center, where the o-ring and actuator was satisfactorily teste To monitor the effectiveness of the T-mod, the licensee 'instituted a quarterly stroke time test for both units' PORVs. The inspector-observed the performance of the Unit 2 PORV test on August 20, 1992._ Maintenance personnel were inside containment near the valves during the stroke. The inspector noted that the maintenance personnel first checked for leaks at the actuator cover flange, identified minor air leaks, and then verified the proper torque on the 24 actuator bolts. - Then the PORV was satisfactorily teste The inspector questioned-the operations shift supervisor why the valve was worked prior to obtaining an as-found stroke time, since the purpose of the test was to verify the effectiveness of the t-mod. Before continuing with the test, the_ shift supervisor notified the responsible system engineer (SE) regarding the inspector's concern. The SE reported to the control room and instructed operators of the need to get accurate as-found data, and the second PORV was satisfactorily tested without pre-test adjustments:

The inspector reviewed the T-mod packages associated with both units (Nos.92-042 for_Unit 2 and 92-044 for Unit 1). Both T-mods also installed temperature detectors to monitor and record surface and ambient air temperatures at the PORVs to evaluate the effectiveness of the new diaphragm material. The inspector concluded that the T-mod safety evaluation properly evaluated the proposed PORV temporary changes. Operator conduct of the testing was conservative in that related RCS parameters were monitored during the stroke test. However, the lack of SE involvement and lack of pre-test coordination was a weakness. This concern was discussed with the appropriate personnel, and subsequent testing at Unit 1 on September 11, 1992, was well controlled. The inspector will continue to monitor the effectiveness of the installed PORV change Charging Pump Speed Increaser Degradation During the week of August 10, 1992, the licensee investigated a potential problem with the No. 22 safety injection charging pump. _Specifically, an abnormal noise was heard in the location of the speed increaser (motor-to-pump gear coupling) during pump operation. All related charging system operating parameters were within specification. However, a subsequent detailed vibrational analysis identified an elevated high frequency vibration level, which *was indicative of a potential wear problem related with the speed increaser gears. -An oil sample was also analyzed. That sample contained metal wear fragments, indicating a

...

' 16 minor degree of gear degradation. The manufacturer of the speed increaser (Nuttall Gear Corporation) was consulted by the licensee regarding the vibration and oil sample result The manufacturer. indicated that the pump was running slightly* rough due, most likely, to pitting or rust~

'

Based on the results of the licensee's analyses and evaluation, they elected to maintain the No. 22 charging pump operable per Technical Specifications (TSs). However, a planned and systematic approach was developed to replace the speed increaser in the near future. The redundant (No. 21) charging pump remained operable per TSs. Additionally, bearing temperature,. lubricating oil and speed increaser bearing temperature readings were continuously monitored with satisfactory results. On August 26, 1992, the licensee replace the No. 22 charging pump speed increase The inspector observed related licensee evaluation activities, discussed the issues with the responsible system engineering and maintenance personnel, and observed portions of the maintenance activities. The inspector concluded that the licensee's identification, followup and resolution of this issue was conducted in a safe and deliberate fashion. In addition, the inspector noted that the maintenance activity. associated with the speed increaser replacement was well planned. Unit 1 Design Changes Made Pursuant to Unit 2 Turbine Overspeed Event Prior to the Unit 1 restart,. the inspector reviewed and inspected the implementation and completion of several design changes and associated procedure changes. The purpose of the review was to assess PSE&G's progress toward meeting the commitments that the licensee

had made to the NRC in response to the findings of the NRC Augmented Inspection Team which investigated the Unit 2 tm:bine~generator overspeed event of November 9, 1992 (NRC Inspection Report 50-311/91-81). The inspector had previously reviewed the repairs and modifications made to the Unit 2 turbine and generator prior to that unit's restart from its refueling outage in NRC Combined Inspection 92-04;

'

Duri~g the course of the Unit 1 refueling outage, the inspector observed portions of the implementation of several different design change packages (DCPs) intended to improve the main turbine control systems arid the turbine overspeed protection systems. The inspector also discussed the effects of the DCPs with the pertinent members of the Operations and Engi~eering Departments. The specific DCPs which were reviewed were:

.lEC-3161, which involved the installation of primary and back-up reverse power relays to provide for generator protection against* motoring,

lEC-3162, which provided for the addition of filters to the autostop oil (ASO) system to prevent plugging of the restricting orifice with debris from the turbine lube oil system,

• lEC-3163, which: revised the 1/1 trip logic of the 20-ET emergency trip solenoid to 2/3 trip logic; deleted the automatic reset of the moisture separator-reheater stop

. valv~s, turbine drain* valves, and electro-hydraulic control (EHC) valves upon a drop of ASO pressure below the setpoint; installed an additional ASO trip (AST) solenoid valve in the ASO hydraulic line which is not blocked by the Overspeed Trip Test Lever; implemented a permanent circuit modification to facilitate independent testing of all overspeed protection control (OPC) and all AST solenoids; and aligned the turbine trip ASO pressure switches' setpoints with the reactor protection system ASO pressure switches' setpoints,

lEC-3164, which modified the control room turbine speed recorder panel and installed a new turbine speed tachometer and enclosure at the turbine front standard,

lEC-3165, which rearranged the existing test pressure gauges located on the turbine front standard instrument rack to match the existing test valve positions and installed new clearly readable nameplates for those gauges in order to prevent confusion during the performance of turbine tests; and

1EC-3166, which added a 110 % overspeed trip signal in the regular turbine trip.

control circuit;. modified the shape of the turbine overspeed trip test to facilitate more positive control during turbine testing; and revised the operation of the main steam stop_ valve bypass valves in order to better prevent the possibility of any steam being *

admitted to the 'turbine following a turbine tri The inspector also reviewed the changes made to operating and Technical Sp~cification surv.eillance procedures that*were affected by the above DCPs. Following implementation of the DCPs and the procedure changes, the inspector observed portions of post-modification testing, startup turbine testing,. and initial turbine roll-up and generator loading activitie As a result of the above-cited inspection and review, the inspector concluded that the licensee's actions concerning the Unit 1 main turbine controls and overspeed protection were appropriate and well-implemented. The licensee exhibited the same aggressive approach to the Unit 1 turbine.as had been demonstrated in the Unit 2 refueling outage for that turbine and related systems. The inspector's review conducted duringthis inspection period, combined. with the effort cited in NRC Inspection 50-311/92-04, revealed that PSE&G has *

appropriat~Iy accomplished. or adequately addressed all commitments they had made to the NRC as a result of the findings of the NRC AI Temporary Modification Made to Unit 1 Main Turbine Controls During the Unit 1 startup, on August 12, 1992, the unit's control room operators experienced difficulty when tb,ey attempted to latch the main turbine. Latching the main turbine involves opening the four turbine stop valves while the control valves are kept closed. Upon

• investigation, the licensee system engineer determined that the stop valves would not go open because the 20-ET turbine trip emergency solenoid yalve had not de-energized and gone closed during the latching proces *

The 20-ET solenoid valve had been replaced during the unit's recent refueling outage. (see Section 7.1.D above), and the licensee's investigation revealed that the turbine control system supervisory circuit was maintaining too high a voltage across the 20-ET solenoid for it to drop-out and allow the stop valves to go open. This supervisory circuit maintains a current path through the 20-ET, in parallel with the trip signal paths, in order to ensure that the solenoid has not failed open and thus prevent it from performing its safety function. In conversation with the solenoid valve's manufacturer, the system engineer determined that the

. latest inodel number. of the valve had been built to tighter tolerances and would require a lower voltage drop across the solenoid for the valve to close. PSE&G remedied the situatiov by implementing a temporary modification which added a resistor to the supervisory circuit in series with the 20-ET valve, thereby lowering the voltage drop wh1ch occurs across the solenoid. Subsequent to the installation of the temporary modification, the turbine was latched without incident. *

The inspector reviewed the tempora(y modification package and discussed the problems encountered with the turbine control system with the system engineer. The inspector verified that the changes made to the turbine control system did not affect the safety-related functions of that system and that the changes made in the latest model number 20-ET solenoid also had not affected the performance of the solenoid's trip function. The inspector concluded that the licensee had performed a thorough investigation or the pro_blem encountered in latching the main turbine and that the corrective actions taken by the licensee were appropriat Open Item Followup (Closed) Unresolved Item 50-272/89-13-02. The licensee was to revise the FSAR to reflect the reclassification of the condenser air removal raqiation monitor. This proposed licensee action was previously reviewed in NRC Inspection 50-272/90-27 and was found to be

.acceptable. The inspector reviewed the licensee's proposed FSAR change (to be incorporated into the next yearly FSAR update) and did not identify any deficiencies. This item is close (Closed) Deviation 50-272/89-13-04. This item noted nonconformances to NRC Regulatory Guide (RG) 1.97, "Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident," for the steam line monitoring variable. The NRC previously reviewed the status of the licensee's resolution as documented in NRC Inspection Nos. 50-272/90-08 and 50-272/90-27, and concluded that the licensee's proposed modifications to ensure RG 1.97 conformance must be reviewed by the NRC prior to closing the open ite *

The Instrumentation and Controls (I&C) Group of Nuclear Reactor Regulation (NRR)

subsequently completed an evaluation of the licensee's proposed modifications. The licensee's method and modifications to satisfy RG 1.97 are as follow Radi~tion monitors

. R46A through E would be the RG 1. 97 Type A, Category 1, instrumentation to detec_t a steam generator tube rupture (SGTR), although the R~6 monitors do not meet all RG 1. 97 single failure and separation requirements. To address the single failure and separation requirement deficiencies, the licensee proposed to modify the power supply so that R46A through D are independent of R46E and the steaJ11 generator (SG) wide range level indication.* T.he SG water level wide and narrow range indications will be used as functionally redundant indications of a SGTR. In addition, the R1(5A through D (SG

.

radiation) and the R15 (condenser air removal radiation) monitors provide Type E, Category

. 2 diverse instrumentation for the plant operators to evaluate and*respond to a SGTR even The NRR l&C personnel concluded that the.licensee's proposed changes, the R46A through E radiation monitors, and the SG wide and narrow range level instruments provide an acceptable set of indicators for the SGTR event; The implementation of the above will be subject to future NRC inspections. Based on the NRC acceptance of the proposed changes to satisfy RG 1.97 for the steam line monitoring variable, this item is closed.

7.2 Hope Creek

• Open Item Followup (Closed) Unresolved Item 50-354/91-14-01. During surveillance testing iri May and July 1991, the licensee experienced multiple failures of ~he filtration, recirculation and ventilation system (FRVS) recirculation unit heater fuses. (See NRC Inspection Reports 50-354/91-14 and 91-16 for details.) Three licensee event reports (LERs) were submitted to the NRC detailing the licensee's extensive evaluation of the causes of and corrective actions taken to preclude further fuse failure (91-007-00 on June 4, 1991; 91-007-01 on August 5, 1991; and 91-007-02 on August 28, 1991). On August 9, 1991, the _manufacturers of the affected heater control panels (Nutherm International, Inc.) submitted a report to the NRC detailing the design safety defect as required by 10CFR21. This report cited only two panels as being defective. The licensee disagreed with this conclusion since it was based solely on test data submitted to the vendor by the licensee which was intended to be representative of all the panels. Licensee corrective actions included the issuance of two design change packages (DCPs), 4EC-3254 and 4EC-3254 Package 2, the former installing small "muffin" fans in the two ventilation units and the latter installing spray shields in front of the six recirculation units whose doors had been removed. Both DCPs were completed by August 199 The inspector reviewed the licensee's DCPs and subsequent retests on the "A" ventilation unit heater control panel, which indicated only a nominal temperature rise in the panel with th heaters energized. The inspector also reviewed the licensee's FRVS white paper detailing the efforts taken to identify and resolve the issues raised by the fuse failures.* A sampling of the I

• monthly surveilla_nces performed since August 1991 did not indicate any fuse failures. Based on the foregoing, the inspector concluded that the licensee had adequately addressed this

• problem and had implemented effective corrective measures. This item is therefore close,

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(Closed) Unresolved Item 50-354/92-01-01. Backdraft Damper Evaluation. During a root cause investigation into high main steam tunnel temperatures in January 1992,. the licensee discovered that the inlet side backdraft dampers were installed backwards. These dampers

• prevent the passage of steam from the room where installed to other areas of the buildin Further investigation revealed that every pair of inlet backdraft dampers used in the reactor building were also installed backwards. The outlet side dampers were all found to be correctly oriented. The licensee committed to reinstalling the main steam tunnel inlet backdraft dampers in_ the correct orientation an-d to evaluate the possible effects_ steam ruptures in other areas could have on adjacent rooms and components where the inlet backdraft dampers were incorrectly installed (reference DEF No. DEH-92-00017, dated January 20, 1992).

,

The inspector determined that the main steam tunnel inlet backdraft dampers had been correctly repositioned, the work being completed during the ten-day mini-outage in Marc. Additionally, the inspector reviewed the associated engineering evaluation, which assessed the impact that a steam rupture in the affected room could have on adjacent rooms and equipment. The evaluation concluqed that the ability to safely achieve and maintain a plant shutdown was not compromised by the potential affects of a high energy line break with the inlet backdraft dampers misoriented for any of the rooms analyzed. The inspector reviewed the evaluation's scope, analysis approach, assumptions and analysis results-and concluded that they appeared to be conservative and well-founded, and supported the

_

evaluation's conclusion. Based on the inspector's review, the licensee's evaluation and the corrective actions taken to correctly position the inlet backdraft dampers in the main steam tunnel, this item is close * SAFETY ASSESSMENT/QUALITY VERIFICATION Salem Plant Sh11tdown Required By Technical Specifications On Augu~t 26, 1992, Unit 1 commenced a Technical Specification (TS) required shutdown from 100% power. At 4:05 p.m., control room operators observed three analog rod position indication (ARPI) displays in the same control rod bank indicating positions greater than a 12 _

step deviation from the group position. Since more-than one ARPI per bank was inoperable as permitted by TS 3.1.3.2.1, TS 3.0.3 was entered. In accordance with the requirements of TS 3.0.3, control room operators initiated a unit shutdown at 5:00 p.m. The licensee

informed the NRC Operations Center of this event in accordance with the reporting requirements of 10CFR50.7 *

By 5:40 p.m., instrument technicians had successfully completed calibration of two ARPis, at*

which time the unit shutdown was terminated at 92% power, TS 3.0.3 was exited, and the Action requirements of TS 3.1.3.2.1 were implemented (determine rod position using the moveable incore detectors).

The inspector observed the ARPI troubleshooting and calibration activities and the control_

room operator response, and determined that those activities were well.controlled. The inspector also verified that the operators implemented the appr<:,>priate abnormal operating procedures. The licensee attributed the drifting of the three ARPis to be due to system design in that the inherent nature of the control rod stack coils are susceptible to ambient temperature changes.

.. Similar events recently occurred at Unit 2 on Juiy 17 and 18; 1992. The inspector found, at that time, that the licensee had previously recognized that the existing system represented an operational difficulty, and had instituted changes in performing ARPI calibrations, with some improvements noted. However, the inspector identified that Unit 1 licensee event repoi::t (LER) 90-28, which documents a similar event on August 14, 1990, stated that the ARPI system is presently under consideration for upgrade to eliminate the temperature susceptibility of the ARPI coils. Unit 2 LER 92-11 (for the July 17 and 18, 1992 events) documents nearly the same corrective actio The inspector identified a concern relative to repeated TS 3.0.3 entries due to a long-standing and known problem. Unit shutdowns in the relatively short time frame required by TS 3; (six hours) should be avoided so as to minimize the risk of creating undesired plant transients. The inspector concluded that because of the existence of continuing TS* required shutdowns, more aggressive management attention is warranted to prevent future occurrence This concern was discussed with licensee management personnel, who acknowledged the inspector's concern and stated that a permanent system upgrade (micro-processor based system) is currently being pursued to effect final resolutio Open Item Followup (Closed) Unresolvedltem 50-272/91-05".'02. The licensee was to submit a second licensee event report (LER) supplement to correct an inadequate Unit 1 LER (No. 91-09) and first LER supplement, and to address equipment operability concerns under postulated accident conditions. Supplement 2 to the LER was submitted on June 11, 1992. Inspector review of the LER determined that the document was well written and thorough. Additionally, the associated analysis of the postulated event (main steam line break in the mechanical*

penetration area with missing seismic gap seals) concluded that the multiple trains of safety equipment would not have become inoperable, a.s assumed previously in the original LE Sufficient supporting information was provided in the text.

• .

The inspector conducted an independent review of the postulated sequence and concluded that

.* the event was bounded by existing accident analyses and ~tation procedur~s. The inspector also determined that the licensee's corrective actions were appropriate. Based on the above, this item is close Personnel Errors During this inspection period, there appeared to be an increased personnel error rate at Sale !~eluded are the Unit 2 reactor trip (Section 2.2. l.B), a missed reactor trip breaker Technical Specification surveillance test (Section 4.3.1.A), an inadvertent turbine trip during maintenance (Section 4.3. l.C), an automatic diesel generator start during surveillance testing (Section 4.3.1.B), and a mode ascension with containment spray valves misaligned (Section 2.2. l.C). The inspectors noted that recent performance relative to committing personnel errors has been very good, especially considering the high work activity levels during both units' refueling/maintenance and forced outage The inspector discussed this increase in personnel errors with station management, who had

. recognized the high rate.. Station management has re-stressed the importance of attention. to detail and self-verification with appropriate groups of station personnel in an attempt to reverse the apparent trend. The inspector concluded that station management had taken appropriate actions and has provided sufficient attention to this concern. The effectiveness of those actions will be monitored during future routine inspection Pressurizer Level Channel Inoperability and Technical Specification Emergency Amendment During the month of August 1992, operational problems were experienced with the Unit 1 pressurizer level channel III. As the channel remained out -of service,* the monthly functional surveillance test became due to be performed on channel I. There are three pressurizer level channels, which must satisfy a two-out-of three trip coincidence to generate a high pressurizer water level reactor trip signal.* On August 26, 1992, the licensee requested the NRC to process a Technical Specification (TS) Amendment on an exigent basis to change the surVeillance interval from monthly to quarterly to allow continued troubleshooting and. repair of channel III and defer testing for channel I. On August 28, 1992, an Emergency TS Amendment was granted by the NRC, thereby avoiding a unit shutdown per existing TS requirement Pressurizer level channel III became inoperable on August 13, 1992, due to that channel deviating from the remaining two by more than 3 %.. Removing the channel from service involved placing the associated high level reactor trip bistable in the tripped conditio Maintenance personnel had performed extensive troubleshooting in an attempt to restore the channel to an operable status. During those activities, problems were found with the sealed

• reference leg bellows, and minor leaks at refer~nce leg fittings were identifie */

Pressurizer level channel I was due for its monthly channel functional test to be completed by 12:00 p.m. on August 29, 1992.* Since testing the channel involves tripping the high level reactor trip bistable, channel I could not have been tested with *the channel III bistable already in the tripped position because the reactor trip coincidence would have been satisfie The licensee had previously submitted to the.NRC (May 11, 1992) a TS Amendment Request

• to extend the surveillance test fotervals and allowable outage times for several components in the Reactor Trip System and Engineered Safety Features Actuation System of TSs. That change request included the pressurizer level channels. The NRC determined that the

• licensee's August 26, 1992, exigent request provided sufficient bases that the situation could not have been avoided by prior application, and granted the amendment for 'both Units 1 and 2 on August 28, 199 *

The inspector monitored the activities associated with pressurizer level channel III, the status of the upcoming channel I test and the associated TS Amendment Request. The maintenance activities, although slow to fully resolve the problem,.were systematic in troubleshooting the operational problems. Maintenance technicians ultimately found failed transmitter circuit cards to be the cause of the latest (August 28, 1992) problem/failure experienced with channel III. The channel was restored to an operational status at 8:30 p.m. ori August 29, 1992. The inspector concluded that an appropriate tevel of management attention*and oversight was provided for tl_lis issu.2 Hope Creek Review of Reactor Engineering Concerns On August 28, 1992, the on-site safety review group (SRG) engineer released a report addressing a number of concerns raised by a technical staff member in April 1992. The technical staff member informally discussed concerns with the NRC resident staff, indicating

, satisfaction that SRG would investigate the matters. The inspector reviewed the concerns and *

determined that there. were no nuclear safety-significant issues. The inspector also reviewed the SRG engineer's report {document HSR-92-052), determining that the report was well-written with each issue thoroughly researched and appropriate recommendations made. The report's overall conclusiort indicated that no -significant safety issues were found, however, a number of administrative issues were _resolved. Appropriate entries were made.in the* action tracking system (ATS) for SRG's seven recommendations. The inspector concluded the potential concerns *were adequately resolved by the SRG enginee Shutdown Risk Management In preparation for the September 1992 refueling outage,. the licensee undertook a number of shutdown risk assessments, as required by administrative procedure NC.NA-AP.ZZ-0055,

"Outage Management Program." (Note: A discussion of the licensee' entire shutdown risk management program may be found in NRC Inspection Report 50-354/92-02, Sections

.*

• ./

~*

-

'

~

2.2.2.B, 4.3.2.A and. 8.2.A.) On Septem~er 4, 1992, the on-site safety review group (SRG)

issued its assessment of the shutdown risks* and the adequacy of the station's actions to minimize such nsks. This assessment covered five areas:

.

Decay heat removal,

Reactor water inventory control,

Electrical power (on-site and off-site) availability,

Reactivity control, and

Containmen One potential issue dealing with the inability of the fuel poof cooling (FPC) system to remove the spent fuel pool heat load for some tiirie after the full core off-load was adequately addressed by changing the scheciule to maintain the fuel pool cooling assist mode of residual heat removal until FPC could handle the decay heat. *Overall, SRG determined that methods addressing shutdown risk were satisfactory and provided six recommendations for enhancements. The inspector noted that se~eral such enhancements had been incorporated prior to the unit coming off line on September 12, 1992..

The inspector interviewed operations and outage management personnel to gain a perspective on their approach to the safety issues surrounding the refueling outage. The licensee indicated that the lessons learned from the ten-day March 1992 mini-outage had been incorporated iri the planning for this outage, including the use of an enhanced required equipment status sheet, proceduralized electrical bus outages, additional operator training (24

• hours per crew), and an evening of the work load between the three shifts. An incentive plan

• was developed to focus licensee and contract personnel attention on safety and job performance. Incentive clauses were also added to vendor contracts to further improve performance and quality. The outage schedule was developed using the full scope of available documentation, including NUMARC 91-06. The inspector reviewed the outage schedule and noted thatit appeared to maximize the availability of systems and components necessary to assure safe shutdown conditions.. The inspector concluded that the licensee had exhibited a safety-conscious and conservative approach to outage preparatiOns and plannin C..

"All Hands" Pre... Outage Meetings On September 10 and 11, 1992, a series of pre-refueling outage meetings were held with all licensee and contractor personnel in order to convey senior plant management's expectations relating to the outage. The plant manager, outage manager and station quality assurance manager each addressed areas of concern. A number of handouts detailing "do's and don'ts" were made available, as well as the RF04 outage manual. The inspectors monitored a nuinber of these meetings and observed that they appeared effective in underscoring the. job performance policies of the station and management's commitment to safety, quality performance and attention to detail, as well as the importance of plant appearance and*

housekeeping during outage activitie *-

25 Common Verification of Plant RecordS Introduction and Backi:round

• The resident inspectors conducted reviews at both Salem and Hope Creek facilities to evaluate PSE&G's ability to obtain accurate and complete log readings from non-licensed operator On April 23, 1992, the NRC staff issued Information Notice (IN) 92-30, "Falsification of Plant Records," to alert licensees to the NRC's concern that plan.t mechanics, technicians, and operators may have falsified plant logs at several nuclear power plants. AH personnel involved in NRC regulated activities are responsible for complying with applicable NRC regulatory requirements. The inspector reviews *were performed by: i) evaluating the licensee's self-initiated investigation, and 2) observing several non-licensed equipment operators (EOs) performing periodic rounds. The following is a summary of the inspection findings. *

Licensee Assessment of EO Tours As previously documented in NRC Combined Inspection 92-04, both facilities have conducted proactive investigations in an effort to determine whether BOs were properly perfonning and documenting their assigned tours and duties. Those investigations were completed by Quality Assurance (QA) personnel~ The inspector concluded that the investigations were thorough and well documente *

The Hope Creek inv~stigation did not identify any concerns relative to BO log falsification over approximately a two month perio The Salem investigation identified several discrepancies between BO logs and the Security computer system records. The investigation was conducted over a three-week period in September 1991, and approximately a six-week period beginning on February 1, 1992. The Operations Department followup review of the QA investigation included EO interview Some hardware problems were subsequently identified related to specific security key card readers and with some of the BO's security key cards. However, some unexplained discrepancies remained. None of the discrepancies appeared to involve logs required by Technical Specifications. Pending completion of a more detailed NRC review of these discrepancies,* including a review of the security key card system, this is an unresolved item (URI 50-272,311&354/92-12-01).

The inspector found that the licensee's self-monitoring efforts, conducted by QA, were

. sufficient to detect deficiencies. The inspector also ascertained that the licensee plans to institute periodic monitoring of a similar fashion to confirm continued accurate and complete

• logs. In addition,* the licensee implements a program designed to ensure that EOs properly perform their functions once they enter the appropriate plant area *.J

EO Tour Accompaniment The inspectors accompanied several EOs during various station* tours, including those during backshift/weekend hours. The EOs observed were knowledgeable of the associated plant areas and of their assigned tasks and responsibilities. The inspectors concluded that the EOs satisfactorily and accurately completed station lo~ documentation requirements..

Licensee Response to IN 92-30 As a followup to concerns documented in NRC IN 92-30, licensee management.issued memoranda to all Salem and Hope Creek employees. Those memoranda attac.hed a copy of IN 92-30 and expressed management's expectations that all station personnel (both licensed

• and non-licensed) must-provide clear and factual accounting of plant operations which reflect actual performance only. Additionally, management conducted briefings with the non-licensed EOs to delineate specific management expectations relative to conduct of EO tour The inspector concluded that the licensee's response to IN 92-30 was appropriate.

. Summary The inspector concluded that the licensee properly evaluated and proactively responded to the concerns identified in IN 92-30. A thorough evaluation identified some discrepancies regarding the non-licensed EO logs at Salem, for wh1ch an unresolved item was opened to track the NRC's followup review. ~C inspector accompaniment of EO tours found the EOs to be knowledgeable and the logs to be accurately complete.

LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPOR'fS,

.AND OPEN ITEM FOLLOWUP LERs and Reports Periodic and Special Reports PSE&G submitted the following licensee event reports, and special and periodic reports, which were reviewed for accuracy and evaluation adequac *

Salem Special Report Supplement 92-4-1 was submitted regarding fire pump inoperability, dated August 7, 199 *

Sruem Special Report 92-5, dated July 23, 1992, was submitted in accordance with Unit 2 Technical Specification 3.3.3.1.b to describe an equipment failure associated with two gaseous radiation rponitors for the Plant Ven _,

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Salem Special Report 92-6, dated August 21, 1992, was submitted in accordance with Unit 1 Technical Specification 3.3.3.1.b to describe.the inoperability of two plant vent gaseous radiation monitor /

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Salem and Hope Creek Monthly _Operating Reports for-July 1992.

Salem and Hope Creek Semi-Annual Report of Fitness for Duty Performance Data for the period January 1 through June 30, 199 Salem and Hope Creek Senii~Annual Radioactive Effluent Release Report for the period January 1 through June 30, 199 Salem LERs Unit 1

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LER 91-04-01 (Supplement) documented the *results of licensee investigations related to a February 6; 1991, turbine runback event. The supplemental report determined the root cause (equipment failme) and associated corrective actions for the even LER 91-09-02 (Supplement) provided_ additional analysis results and corrected information in response to concerns related _to NRC identifie<I LER weaknesses (See Section 8.1.B of this report).

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LER 92-04-01 (Supplement) described the completed event causal factor investigation performed by the licensee following the discovery of incorrect detectors in several main steamline radiation monitors. The event was documented in NRC Inspection 50-272/92-04.. Since that report was issued, the. licensee determined that the root cause for the event was personnel error in that replacement detectors. were improperly classified in the licensee's folio system as Commercial Catalog Items. The improper detector part number has been.replaced with the proper detector. The inspector noted that this Supplement was properly prepared and the root cause determination to be acceptabl *

-LERs 92-06 and 08 concerned Technical Specification surveillances that were not performed within the required tim_e frames. These events were previously discussed in --

NRC Inspection 50-272/92-0 *

LER 92-11-01 (Supplement) described an additional radiation monitoring system (RMS) engineered safety feature actuation that was similar to a recent event in which the lRlB radiation monitor failed, resulting in a control room ventilation isolation.

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~ER 92-14 was a voluntary report and described linear indications identified b radiographic examinations in the area of steam generator (SG) feedw~ter nozzles for three of the four Unit 1 SGs. This issue was previously discussed in NRC Inspection 50-272/92-0.

LER 92-15 reported the potential for the loss of control and position indication for pressurizer power operated relief valves during an accident. This potential existed due to the power for those affected circuits sharing a common circuit breaker with non-environmental.ly qualified circuits. This event was discussed in NRC Inspection 50-272/92-0 '

LER 92-16 discussed worker performance weaknesses in which several roving fire -

watch inspections were apparently not performed as required. This event was reviewed in NRC Inspection 50-272/92-0 *

• . LER 92-17 described an inadvertent main steam isolation that occurred during unit mode ascension activities (Mode 4 - Hot Shutdown). This event is further discussed in Sect~on 7.1. A of. this repor *

LER 92-18 documented the improper mode change _made during the Unit 1 startup with* the containment spray valves closed and the resulting Technical Specification noncompliance. This* event is discussed in Section 2.2.1. of this repor *

LER 92-19 described an inadvertent main steam isolation that occurred during post-

.maintenance testing of the steam-driven auxiliary feedwater pump while.in Mode 3 (Hot Standby). This event is discussed in Section 7. l.A of this repor.

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.LER 92-20 concerned a reactor protection signal actuation in which an.automatic turbine trip from 21 % power occurred during maintenance. This event is discussed in Section 4. 3. 1. C of this repor *

LER 92-21 described a Technical Specification required shutdown due. to inoperable analog control rod position indication displays. This event is discussed in Section 8.1.A of this repor Unit 2

LER 92-08-01 (Supplement) provided a description of an additional similar event concerning a main steam line isolation that occurred while in Mode 4 (Hot Shutdown)

on July 13, 1992. This event is discussed in NRC Inspection 50-311/92-09.

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• LER 92-11 concerned a Technical Specification 3.0.3 entry due to having more than one control rod analog position* indicator per bank inoperable. This event was reviewed in ~C Inspection 50-311/92-0 *

LER 92-12 concerned a missed Technical Specification surveillance of the No. 2A reactor trip breaker. This event is discussed in Section 4.3.1.A of this repor *

LER 92-13 discussed an engineered safety feature actuation (diesel generator automatic start) due to personnel error during surveillance testing. This event is discussed in Section 4.3.1.B of this repor Inspection Findings Inspector review of the above Salem and Hope Creek reports determined them to be accurate and generally well writte *

9.2. Open Items The following previous inspection items were followed up during this inspection and are tabulated below for cross reference purpose /89-13-02 272/89-13-04 272/91-05-02 Hope Creek 354/92-:01-01 354/91-14-01 Report Section 7~.LF 8.....

EXIT INTERVIEWS/MEETINGS 1 Resident Exit Meeting Closed Closed Closed Closed Closed The inspectors met with Mr. C. Vondra and Mr. J. Hagan and other PSE&G personnel periodically and at the end of the inspection report period to ~ummarize the scope and findings of their inspection activitie I

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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 restri~tion.2 Specialist Entrance 'and Exit Meetings 8/3-7/92 Inspection Subject Report N Erosion/Corrosion 354/92-11

_Program Reporting Inspector Patnaik