IR 05000272/1991015
| ML18096A103 | |
| Person / Time | |
|---|---|
| Site: | Salem, Hope Creek  |
| Issue date: | 06/24/1991 |
| From: | Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18096A102 | List: |
| References | |
| 50-272-91-15, 50-311-91-15, 50-354-91-12, NUDOCS 9107080068 | |
| Download: ML18096A103 (36) | |
Text
Report No License No Licensee:
Facilities:
Dates:
Inspectors:
Approved:
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
50-272/91-15 50-311/91-15 50-354/91-12 DPR-70 DPR-75 NPF-57 Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, New Jersey 08038 Salem Nuclear Generating Station Hope Creek Nuclear Generating Station May 8, 1991 - June 15, 1991 T. P. Johnson, Senior Resident Inspector S. T. Barr, Resident Inspector S. M. Pindale, Resident Inspector H. K. Lathrop, Resident Inspector R. L. Nimitz, Senior Radiation Specialist H. J. Ka
, Se or eacto E gineer J. Inspection Summary:
Inspection 50-272/91-15; 50-311/91-15; 50-354/91-12 on May 8, 1991 - June 15, 1991 Areas Inspected:
Resident safety inspection of the following areas: operations, radiological controls, maintenance and surveillance testing, emergency preparedness, security, engineering technical support, safety assessment/quality verification, and licensee event reports and open item followu Results: An executive summary follows.
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SUMMARY Salem Inspection Reports 50-272/91-15; 50-311/91-15 Hope Creek Inspection Report 50-354/91-12 May 8, 1991 - June 15, 1991 OPERATIONS (Modules 71707, 71710, 93702)
Common: Hope Creek and Salem shift staffing and manning were satisfactory for specific shifts reviewed: However, the Salem administrative forms do not document fire brigade and radiation protection personnel manning. The site fire protection organization effectively implements fire protection programs at the Hope Creek and Salem facilities. Salem and Hope Creek programs to reduce control room alarms appear to be effectiv Salem:
The Salem units were operated in a safe manne Radiation monitoring system actuations were reported, and licensee actions were appropriate. The Unit 2 maintenance outage was well planned and conducted; the licensee demonstrated an excellent safety perspective in electing to shutdown the unit to perform maintenanc Plant and fire protection personnel appropriately responded to two fire related event The containment spray systems were adequately aligned. A Unit 2 shutdown was appropriately initiated due to entry into Technical Specification 3. *
Hope Creek: The unit was operated in a safe manner. An I&C technician error during testing resulted in a reactor scra Operator response to the scram was appropriate. However, weaknesses were noted relative to senior reactor operator command and control. The licensee appropriately addressed this issu *
RADIOLOGICAL CONTROLS (Modules 71707, 83750, 93702)
Salem: Periodic inspector observation of station workers and Radiation Protection personnel implementation of radiological controls and protection program requirements did not identify any significant deficiencies. Performance during the Unit 2 maintenance outage was good. The station ALARA committee was effective in reviewing outage exposure goals and task Hope Creek:
Periodic inspector observation of station workers and Radiation Protection personnel implementation of radiological controls and protection program requirements did not identify any deficiencies.
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MAINTENANCE/SURVEILLANCE (Modules 61726, 62703)
Common: Minor material condition deficiencies exist apparently due to a lack of attention to detail during related maintenance activities and subsequent plant walkdown Salem: Routine inspector observations did not identify any deficiencies. Root causes for a licensee identified non-cited violation (three examples of missed surveillance testing) include personnel error, poor administrative controls, and poor communication. Licensee corrective actions were appropriate. Personnel errors resulted in two Unit 1 electrical load-shed, diesel start, and sequential bus loading events. Periodic surveillance and maintenance activities for Unit 1 containment penetration conductor overcurrent protection devices is unresolve Hope Creek:
Routine inspector observations did not identify any deficiencie A diesel generator valid test failure was appropriately pursued by the licensee. The licensee's process for at power system outages appears to be effective with an appropriate level of management involvemen A reactor core isolation cooling system valve isolation event investigation is ongom EMERGENCY PREPAREDNESS (Modules 71707, 93702)
No noteworthy findings were identifie SECURITY (Modules 71707, 93702)
Fitness for duty program requirements were appropriately followed prior to allowing a Hope Creek reactor operator to return to duty. Good performance was noted during a security exercise conducted with participation from local, state, and county law enforcement agencie ENGINEERING/TECHNICAL SUPPORT (Module 37828, 71707)
Salem:
Engineering work activities are being performed in accordance with applicable procedures and are properly prioritized and executed. Service water system pipe replacement programs are progressing appropriatel Hope Creek: Engineering work activities are being performed in accordance with applicable procedures and are properly prioritized and executed. The licensee appropriately responded to a filter, recirculation and ventilation system heater failure even IV
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SAFETY ASSESSMENT/QUALITY VERIFICATION (Modules 30702, 71707, 40500, 90713, 92700, 92701)
Common:
The off-site safety review group adequately assessed the 10 CPR 50.59 safety evaluation process at Hope Creek and Salem. Sp~ific program implementation deficiencies artd associated corrective actions were addressed. An unresolved item for Hope Creek is being opened and the related Salem item remains unresolved pending further licensee improvements in this area and subsequent NRC review. The licensee demonstrated the capability to adequately assess their performance by reviewing SALP functional area Salem: The Station Operations Review Committee displayed a good questioning attitude and an excellent safety perspective. SORC is effectively implementing their review and audit functio The licensee has adequately assessed performance as indicated by a review of the 1990 licensee event report causal factor Hope Creek: The Station Operations Review Committee displayed a good questioning attitude and an excellent safety perspective. SORC is effectively implementing their review and audit function. The licensee has adequately assessed performance as indicated by a review of the 1990 licensee event report causal factors. The licensee demonstrated a good safety perspective relative to the review of industry information for standby liquid control problem.
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DETAILS SUMMARY OF OPERATIONS Salem Units 1 and 2 Unit 1 operated at power during this period. Unit 2 was shutdown on May 10, 1991, for a planned maintenance outage. The unit restarted. on May 21, 1991, and operated at power for the remainder of the perio.2 Hope Creek The unit began the report period shutdown due to a reactor scram that occurred on May 7, 199 The unit restarted on May 11, 1991, and operated at power for the remainder of the report perio.3 Common Two officials from the Japanese Ministry of International Trade and Industry toured Artificial Island on May 14, 1991. The officials observed unit operations and talked with the licensed operators in control rooms at both stations. The Salem radiologically controlled area and the site
protected area were also visited. The inspector accompanied the Japanese official *
On May 17, 1991, T. Martin, NRC Region I Regional Administrator, toured the Salem and Hope Creek facilities. He also met with plant and corporate management personnel. Specific inspection and tour observations and findings are discussed in Section 4..
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 record These inspection activities were conducted in accordance with NRC inspection procedures 60710, 71707, and 9370 The inspectors performed normal and back-shift inspections, including deep back-shift (5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />) inspections as follows:
Salem Hope Creek Inspection Hours 3:00 a.m. - 5:00 :30 a.m. - 10:30 May 21, 1991 June 9, 1991
2 Inspection Findings and Significant Plant Events 2.2.1 Common Shift Manning The inspector reviewed the adequacy of shift manning for both Hope Creek and Sale Technical Specification (section six) and administrative procedure NC.NA-AP.ZZ-0005(Q),
"Station Operating Practices," define the minimum onsite staffing levels. These requirements address licensed and non-licensed operators, emergency response personnel, fire brigade members, and maintenance and radiation protection personne The inspector reviewed records, and interviewed selected personnel. Accordingly, the inspectior determined that the Hope Creek and Salem Stations were appropriately staffed. Salem and Hope Creek maintain staffing requirements in accordance with AD-32 and HC.OP-AP.ZZ-0107(Q),
respectively. Shift manning forms are attached to these respective procedures. The inspector noted that the Salem form did not have a place to document appropriate fire brigade or radiation protection technician manning. The inspector verified that the senior nuclear shift supervisor received verbal reports that these personnel positions were appropriately manned. The licensee agreed to revise the form to include formal documentation for all shift manning requirements. Fire Protection As part of inspector followup to two Salem fire related events (see section 2.2.2.B), a review of Salem, Hope Creek and Site Protection fire protection procedures and activities was conducted. Site Protection maintains the onsite fire department and fire brigade responsibilitie Plant response to fire emergencies include notification and activation of Site Protection. A recently approved nuclear department administrative procedure NC.NA-AP.ZZ-0025(Q), "Fire
. Protection Program," combines previous Salem and Hope Creek procedure The inspector reviewed this administrative procedure and discussed its implementation with plant and fire protection personnel. The fospector also reviewed the following:
Salem and Hope Creek Fire and Medical Emergency Response Manual and associated fire preplans (M 10-FRS and H)
Salem fire abnormal operating procedure (AOP-FIRE-1)
Salem and Hope Creek alarm response procedures for fire detection panels
I L
The inspector noted that Salem's fire response was in accordance with AOP-FIRE-1; and that Hope Creek's fire response was in accordance with the Fire and Medical Emergency Response Manual, even thm,Igh both programs were derived from the same administrative procedur Although the inspector did not identify any performance issues, there appeared to be no basis for such an inconsistency. Accordingly, the licensee agreed to review this matter in an effort to establish a common approach to fire respons *
Overall, the inspector concluded that a well trained and well managed site fire protection organization effectively implements the program in support of the Salem and Hope Creek facilitie Control Room Alarms The inspector reviewed the licensee's performance program for control room alarms at both Hope Creek and Salem. The licensee tracks illuminated overhead alarms, and management reviews alarm status each week at the Thursday daily management meeting. The reason for the alarm, the corrective action to clear the alarm, and estimated completion date are tracked. The goal is achieve a "black board" condition (e.g., no alarms).
The inspector noted a decrease in the number of alarms during the period.. At the end of the inspection period the following status was noted by the inspector:
Hope Creek Salem 1 Salem 2 Number of Alarms
8
The inspector concluded that licensee actions were appropriate to reduce the number of control
- room alarm.2.2 Salem Unit 2 Maintenance Outage On the evening of May 10, 1991, following a 255 day, record run for the unit, Salem Unit 2 was shut down for a scheduled maintenance outage. The unit was taken off line at 6: 10 a,m.,
on May 11, 1991, and reached Mode 4 (Hot Shutdown) at 10:44 that evening. The shutdown and cooldown were accomplished without incident. The outage was conducted to perform a number of maintenance activities to prepare the plant for the peak electric demand season over the summe Unit 2 is scheduled for its sixth refueling outage in January 1992. The key maintenance activities included main steam isolation valve repacking, control air system panel testing/repairs, main generator hydrogen leak repairs and rod control system
power supply replacement. Unit 2 was restarted following this ten day outage and achieved criticality without incident at 6:25 a.m., on May 21, 1991, and power ascension followe The inspector reviewed the outage preparations and planning; observed the conduct of outage, *
including shift turnover and outage meetings; inspected selected maintenance and testing activities; and, observed portions of the unit shutdown, outage plant conditions, and unit restar Overall, the inspector concluded that outage performance was excellent. This included planning, execution and recovery activitie Further, the licensee demonstrated conservatism and an excellent safety perspective in shutting down the unit to perform these maintenance and testing activitie Fire Related Events The inspector reviewed two fire related events that occurred at Salem during the report perio On May 13, 1991, at 2:40 a.m., a roving fire watch noted smoke coming from the Unit 1 number 11 emergency lighting inverter. He called the control room and extinguished a small fire associated with an AC output ammeter (l-AM-0081), located on the outside of the panel, using a portable C02 fire extinguisher. Site fire protection was notified and they also responde The panel was de-energized and inspecte This apparent faulty ammeter was the only equipment damage Other nearby equipment in the 100 foot elevation relay room was unaffected. System engineering inspected similar emergency lighting inverters on both unit The same ammeter was replaced on the number 12 inverter and the ammeter is scheduled for replacement on the remaining inverters. The number 11 inverter was repaired and placed back in servic On May 26, 1991, at 9: 18 a. m., the Unit 2 high pressure turbine bearing deluge system actuate Plant and site fire protection personnel responded. No fire was noted, however, a fusible link had actuated causing the deluge. This was probably due to high ambient temperatures and a small steam leak in the area. The licensee improved area ventilation and replaced the fusible link actuating device. Longer term corrective actions are being considere The inspector reviewed each event, including the site fire protection and plant incident report The inspector also examined the areas in the plant that were affected. Discussions were held with control room personnel that were onshift during these events and with fire protection personnel. The inspector concluded that licensee response to these events was appropriate. The inspector noted that quick and proper action on the part of the roving fire watch limited the damage caused by the failed lighting inverter ammeter. For additional inspector observations and reviews of site fire protection see section 2.2.1.A.
5 Radiation Monitor Engineered Safety Feature (ESF) Actuations The following ESP actuations occurred and were reported by the licensee during the period:
Unit Radiation Monitor Date Time
lRlA May 10, 1991 1:32 R12B May 22, 1991 3:45 a.m. '
1R41C May 29, 1991 8:15 R41C June 3, 1991 9:00 These events continue to be indicative of the degraded radiation monitor syste Systems responded as designed causing a containment ventilation isolation or a control room ventilation start. Licensee actions include short term and long term equipment upgrades. The inspector reviewed licensee actions regarding these events. The licensee intends to submit an LER for these events. No unacceptable conditions were note Engineered Safety Feature (ESF) System Walkdown The inspector independently verified the operability of the Unit 1 and 2 Containment Spray Systems by performing a walkdown of the accessible portions of the systems to confirm that system lineups and procedures matched plant drawings and the as.-built configuration, and to identify equipment conditions which could degrade performance. This inspection was conducted in accordance with NRC inspection procedure 7171 The inspector walked down the Containment Spray Systems and concluded that the systems were fully functional and appropriately aligned in the standby mod Valves and breakers were positioned as indicated by the computer generated (TRIS) lineup sheets. The inspector also reviewed the appropriate sections of the UFSAR, Technical Specifications, electrical schematic drawings, and surveillance testing and operating procedure The inspector noted that material condition of the Unit 1 and 2 Containment Spray Systems appeared satisfactory. Housekeeping in areas inspected was determined to be adequate although a few areas were not yet up to the level expected by the licensee. Efforts to improve these areas is ongoin Based on the above, the inspector concluded that both units Containment Spray Systems appeared fully operational and capable of performing their design functio Unit 2 Shutdown Due To Technical Specification (TS) 3.0.5 Entry At 6:30 a.m., on June 6, 1991, the licensee entered TS 3.0.5 when 2C emergency diesel generator (EDG) was declared inoperable concurrent with the (21) containment fan coil unit (CFCU) out-of-service for maintenance cleaning. The 2C EDG inoperability caused the (23) and
(25) CFCUs, and the (22) containment spray pump to be technically inoperable because the 2C 4.16 KV vital bus (2C EDG) powers this equipmen The licensee began a power reduction and made an ENS call at 7:14 a.m. At 8:00 a.m., the 2C EDG was returned to service. The EDG prelube system was isolated and EDG operability was maintained with oil temperature greater than 100 degrees F per licensee TS interpretation OD-1 In addition, (21) CFCU was returned to service and made operable later that morning. Reactor power had been reduced to 95 % and the unit was subsequently returned to full power. A subsequent ENS call was made to report TS 3.0.5 terminatio The inspector was in the control ro9m at the time of TS 3.0.5 entr Unit 2 equipment conditions and TS implementation were verified. The inspector also discussed the event with on-shift operators, and with management personnel at the 7:30 a.m. morning meeting in the control room. The inspector concluded that licensee actions were prudent, *and in accordance with procedures and TS requirement.2.3 Hope Creek Automatic Reactor Scram on May 7, 1991
Licensee Actions and Review
The Hope Creek unit automatically scrammed from 100% power at 9:02 p.m., on May 7, 1991, due to low reactor water level ( + 12.5 inches). Safety systems responded as expected: all control rods inserted, reactor pressure was maintained by the electro hydraulic control (EHC)
system, no safety relief valves lifted, and containment isolations occurre Reactor level decreased, and the reactor core isolation cooling/high pressure coolant injection (RCIC/HPCI)
systems automatically started at -38 inches. The operators took manual control of the three reactor feed pumps (RFP), restored level and manually secured the RCIC/HPCI systems once adequate core cooling was assured. Level decreased to a low of -41 inches and was returned to a normal post scram level with 15 seconds. The RCIC/HPCI systems did not inject into the reactor. An ENS call was made and the resident was informed at hom The unit was taken to Mode 4 (Cold Shutdown) to perform maintenance, testing, modification work and troubleshooting of the feedwater level control system. At 7:58 a.m. on May 8, 1991, a second scram signal occurred while shutdown. This was caused when an IRM spiked during testing on the opposite reactor scram channel. No rod movement occurred. Another ENS call was mad The licensee's investigation into this event included the normal line management review consisting of an operations post-trip review and Station Operations Review Committee (SORC).
In addition, an independent Significant Event Response Team (SERT) investigated the scram.
At the time of the scram, instrument and control (l&C) surveillance testing (IC-FT.BB-028) was in progress on one of three narrow range level transmitters (B). The A level transmitter was in
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control when its indication went upscale causing all three RFPs to respond to minimum flo The licensee's review determined that a personnel error on the part of the I&C technician was the root cause of the scram. The I&C technician lifted the correct leads on the B transmitter; however, he installed the test equipment on the A transmitter. This resulted in the upscale indication on the A transmitter and subsequent low level scra Licensee corrective actions included the following:
Counselling the I&C technician involved and informing the entire I&C department of this occurrence Procedural enhancements to the related I&C surveillance test procedures Implementation of design change package (DCP) 4HC-204 item no. 24. This DCP installed test jacks on the exterior of the feedwater panel to prevent lead lifting and the need for internal panel access during testin Once the licensee completed their review and implemented corrective actions, the unit was restarted on May 11, 1991, and achieved full power on May 13, 199 NRC Review and Conclusions The inspector reviewed the following documents:
LERs91-008 and 009 DCP 4HC-204, item no. 24 SERT report Emergency operating procedure (EOP) OP-:EO.ZZ-lOl(Q), "Reactor Pressure Vessel Control EOP" Post scram review procedure (AP-101)
Control room logs and chart recorder traces Computer alarm and sequence of events printouts Surveillance testing procedures The inspector interviewed the onshift reactor and senior reactor operators. The inspector also discussed the scram with maintenance, operations, plant management personnel and SERT manager. The inspector attended the SORC meetings (Number 91-036) which addressed the scram root cause and corrective action The inspector also examined the interior of the feed water level control panel in the lower relay room and portions of the DCP implementation, including QA verification and post-modification testin The inspector verified that the operator decision to secure RCIC/HPCI was consistent with training and EOPs. The inspector noted the Senior Nuclear Shift Supervisor (SNSS) made the decision to secure these safety systems as feedwater had returned level to normal. In addition,
it was the SNSS who also performed the action at the control panels located outside the horseshoe. This was primarily due to the fact that the remaining control room licensed operators were busy responding to_ the scram within the control board interior horseshoe. The Nuclear Shift Supervisor (NSS) was also inside the horseshoe implementing the flow chart EOP Discussions were held with operations and plant management regarding this issue. Licensee actions included restating management expectations during a transient in a letter dated May 17, 1991. The SNSS is expected to maintain overall command and control while the NSS directs response in accordance with the EOP Overall, the inspector concluded that operator response to the scram was appropriate and adequate, and in accordance with procedures. Licensee followup to the scram was noted as being timely and aggressive. Effective corrective actions were implemented. The LER and SERT reports were well written and thoroug Residual Heat Removal (RHR) Walkdown Update An independent walkdown of the RHR system to verify operability was performed in April and May 1991, as discussed in Inspection Report 354/91-08. During the walkdown, discrepancies were noted in the computer-generated (TRIS) valve lineup sheets. The licensee had initiated actions to address the inspectors' concerns when the report period ende The inspector reviewed the revised TRIS valve lineup sheets and discussed the corrective actions with operations management. The licensee had attempted to make each loop (A, B, C and D)
lineup "stand alone" to the extent practicable while avoiding the duplication of effort required by the earlier lineups. Additionally, valve position and condition (e.g., locked, capped) noted on TRIS were reconciled with the piping and instrumentation diagrams (P&ID) for the RHR system, M-51-1, field verified as necessary, and TRIS updated accordingly. The inspector noted that components shared by more than one RHR loop (e.g, the "C" RHR jockey pump provides
"keep fill" capability to both the "C" and "A" loops) appeared on only one loop TRIS printou The licensee explained that some 6f the "shared" components were listed only with the loop with which they were most commonly associated to avoid duplication and confusion. In this case, shift management would amend the applicable TRIS printout for situations requiring a less-then-complete system lineup. The inspector concluded that this method appeared reasonable, having been used extensively in the past with only a few minor discrepancies note.
RADIOLOGICAL CONTROLS Inspection Activities-PSE&G' s conformance with the radiological protection program was verified on a periodic basi These inspection activities were conducted in accordance with NRC inspection procedures 71707, 83750 and 93702.
- .2.1 Salem Open Item Followup (Open) Violation (50-272/91-08-02; 50-311/91-08-02) The licensee did not adhere to Technical Specification 6.1 The licensee did not establish adequate procedures for placement of dosimetry, and personnel did not adhere to radiation work permits. The inspector reviewed this matter with respect to the corrective action outlined in the licensee's April 25, 1991, letter to the NRC. The licensee implemented the scheduled corrective action outlined in this letter including revision of applicable procedures and retraining of personnel. The licensee has yet to complete the scheduled continuing training for radiation protection technicians (scheduled for July 1991)
and the training of contractor radiation protection technicians (scheduled for January 1992). This item remains ope Specialist Observations A specialist inspector reviewed the implementation and adequacy of radiological controls provided at the station including those provided for the Unit 2 mini-outage. The review was with respect to applicable licensee procedures and IO CFR 20.
The evaluation of the licensee's performance in this area was based on discussion with cognizant personnel, review of documentation and independent inspector observation of ongoing work activitie Within the scope of the review, no violations were identifie The following observations were noted:
The licensee's planning and preparation for the Unit 2 mini-outage incorporated lessons learned from past outages. Independent inspector observation indicated generally good planning, preparation and radiological controls for outage work (e.g. disassembly and repair of the Unit 2 residual heat removal hot leg injection check valve 23SJ156).
Radiological controls personnel displayed a good understanding of planned wor Appropriate radiological control goals were developed and tracke There was good management and supervisory oversight of work activitie Radiation work permits were properly implemented..
High Radiation Area access controls were adequat The licensee made good radiological surveys to support work activities.
Contamination controls for work were good, including posting and labelin **
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The licensee held a special ALARA committee meeting to discuss the planned work for the Unit 2 mini-outage including the total projected exposure. This was a commendable licensee initiativ The licensee implemented appropriate ALARA control for work activitie External exposure controls including personnel monitoring was goo Internal exposure controls including use of respirator protective equipment was goo Appropriately trained and qualified personnel were overseeing radiological work activitie The following observations were provided to the licensee:
An air sampler with an out-of-date calibration sticker was observed being used on the 78 foot elevation of the Unit 2 Auxiliary Buildin Although the licensee's program provided for a 25 % grace period, the licensee's policy was to remove air samples from service prior to exceeding the expiration dat The licensee counseled appropriate radiation protection personnel on this matter.
The inspector observed evidence (discarded candy wrapper) of ingestion of food material in the Unit 1 Spent Fuel Storage Building. Ingestion of food materials is prohibited in the radiological controlled area. The licensee has been closely monitoring this issue and will continue to do so in the futur During inspector use of an ion chamber survey meter, the inspector observed a picture of an individual's face placed over the thin mylar window used for beta dose rate measurement The picture could affect the instrument response capabilitie The licensee counseled all radiation protection technicians on the inappropriateness of this matte Overall, radiation protection and radiological control performance during the Unit 2 maintenance outage was goo Station ALARA Committee (SAC)
The inspector attended a meeting of the Salem SAC on May 7, 1991. The inspector verified that meeting was held per procedure NC.NA-AP.ZZ-0013(Q).
At this meeting the Unit 2 maintenance outage exposure goals were discussed. The inspector concluded that the Salem SAC appears effective in reviewing high exposure jobs and ensuring that radiation dose is ALARA.
11 Poor Radiological Controls Practice During Minor Work Activity On May 22, 1991, during a routine tour of the radiologically controlled Unit 1 and 2 auxiliary building, the inspector observed a chemistry technician exit a contaminated area without removing his labcoat. The technician did, however, properly remove his protective gloves and shoe covers as require The inspector questioned the technician and notified Radiation Protection (RP) personnel of the finding. The inspector was informed that for minor jobs, such as inspections or root valve manipulations, chemistry and operations personnel were not required to remove their labcoats and this was an accepted RP practice. The inspector expressed concern that the individual may possibly become contaminated and spread the contamination to other plant areas. Additionally, the inspector ascertained that labcoats were typically reused for similar activities without a formal mechanism in place to ensure thar the labcoats are frisked. The individual's labcoat was frisked and was not contaminate The inspector reviewed applicable station procedures and did not identify a procedure compliance issue. However, the inspector discussed this issue with RP management, who acknowledged that the above accepted activity is a poor RP controls practice. The~ manager subsequently issued a memorandum to the appropriate personnel on June 3, 1991, directing that the above practice may lead to the spread of radioactive contamination and should be discontinued immediatel The memorandum also specified the proper procedure for crossing contaminated area boundaries while wearing protective clothin The inspector concluded that the licensee properly addressed the observed poor RP practice, and will continue to monitor performance in this are.2.2 Hope Creek Periodic inspector observation of station workers and radiation protection personnel implementation of program requirements did not identify any deficiencie.
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 standards. These inspections were conducted iri accordance with NRC inspection procedure 62703.
Portions of the following activities were observed by the inspector:
Work Request (WR)/Order Unit (WO) or Procedure Description Salem 2
. W0901011167 22AF22 repair Salem 1 Various WOs 13 auxiliary feedwater pump Hope Creek W0910509120 Feedwater Control Panel design change modification work Hope Creek Troubleshooting Form Annunciator panel troubleshooting Hope Creek Various WOs B Low Pressure Coolant Injection System Hope Creek Various WOs C Emergency Diesel Generator With the exception of the observations noted in Section 4.3.1., the maintenance activities inspected were effective with respect to _meeting the safety objectives of the maintenance program. Surveillance Testing Inspection Activity The inspectors performed detailed technical procedure reviews, witnessed in-progress surveillance testing, and reviewed completed surveillance package The inspectors verified that the surveillance tests were performed in accordance with Technical Specifications, approved procedures, and NRC regulations. These inspection activities were conducted in accordance with NRC inspection procedure 6172 The following surveillance tests were reviewed, with portions witnessed by the inspector:
Salem 2 Salem 1 Hope Creek Hope Creek Procedure N SP(0)4.0.5-P-SW(25)
SP(0)4.0.5-P-CS(22)
S 1. MD-FT.4KV-1,2,3(Q)
OP-ST.KJ-004 IC-FT.BB-028 25 service water pump 22 containment spray pump 4KV bus undervoltage relays D Emergency Diesel Generator Monthly Surveillance Reactor Pressure Vessel Water Level Eight Functional Test
With the exception of the observations noted in Section 4.3.1., the surveillance testing activities inspected were effective with respect to meeting the safety objectives of the surveillance testing progra.3 Inspection Findings 4.3.1 * Common Regional Administrator's Tour The Region I Regional Administrator visited the Hope Creek and Salem facilities on May 17, 1991. He toured each facilities' radiologically controlled areas, control rooms, and emergency diesel generators (EDGs), and inspected safety related equipmen Specific deficiencies identified were reported to the licensee for resolution. These included.*
minor material condition items including loose brackets, missing screws, broken electrical insulation, improper storage of equipment on or near the EDGs, and indications of poor housekeeping after maintenance.. The apparent lack of attention to detail during maintenance, or during post-maintenance activities or during periodic licensee walkdowns indicated that equipment conditions may not always be fully re-established following maintenance activitie *
The inspector verified that the licensee corrected or documented for correction each item identified.. The inspector will continue to review this item at both _facilitie *
4.3.2 Salem Missed Unit 1 Technical Specification (TS) Surveillance (LER 91-019)
The licensee identified three instances of missed surveillance.
On May 1, 1991, the LER coordinator discovered that a special report was not initiated as required by TS 3.3.3. lb {Table 3.3-6 Action 23) when the Unit 1 main steam line radiation monitors 1R46 A-E (alarm function only) were out of service for outage related maintenance. The licensee determined root cause to be poor administrative controls and communication.
On May 13, 1991, a maintenance supervisor discovered that a Unit 1 pressurizer pressure channel functional test had been missed. Channel lPT-456 requires a monthly test per TS Tables 4.3-1 and 2. The licensee attributed the event to personnel error.and poor administrative controls. When discovered, the test was satisfactorily performed twelve hours* 1at.
On May 14, 1991, operators noted that the Unit 1 containment fan coil unit (CFCU)
radiation monitors (1R13 A-E) were out of service and no grab samples had been taken
L
as required by TS 3.3.3.8 Action 28. The 1R13 inoperability was caused when the Unit 2 circulating water pumps were removed from service on May 12, 1991. The Unit 1 CFCU service water discharge is routed to the Unit 2 circulating water discharge. The
- .licensee determined root cause to be personnel error and inadequate operating procedure The inspector reviewed these events including the LER and associated corrective actions. These events are collectively classified as a licensee identified violation of TS and they are not being cited because the criteria in the NRC Enforcement Policy section V.G.1 were satisfied (NON 272/91-15-01). The inspector concluded that licensee corrective actions as stated in the LER appear to be adequat High Electrolyte Level In 125 Volt DC Battery On May 23, J991, the inspector identified that the electrolyte levels in several cells of the N C 125-volt DC battery were above the maximum level indication marks. Eight of the 60 cells were above the marks, and the electrolyte levels in several other cells were higher than normal, but within the high and low level mark The inspector notified the control room operators of the high electrolyte levels in the eight battery cells, and they promptly initiated an investigation with the assistance of system engineering and maintenance personnel. The applicable Technical Specification (TS) Action requirement was appropriately entered at 3:30 p.m. and the IC battery was declared inoperabl Maintenance personnel restored the electrolyte levels to within specification and implemented the appropriate specific gravity and related surveillance requirements for the eight affected cell Operations subsequently declared the IC battery operable and exited the TS Action requirement at 6: 10 p.m. A unit shutdown was not required by TSs for this event. All other safety related batteries were visually inspected and verified operable based upon satisfactory electrolyte level Followup action taken by the licensee included consultation with the battery vendor and increasing the monitoring of the electrolyte levels in the IC battery on a weekly inspection interval. The vendor stated that the batteries would remain fully functional with the level being.
up to 1/4 inch above the maximum level indication mark. None of the eight reached 1/4 inch above the mark. On June 10, I99I, the weekly inspection identified that many cells were approaching the maximum level indication marks. The levels were subsequently reduced on 56 cells and satisfactorily teste The licensee postulated that the level rise was due to a combination of relatively high initial electrolyte level and high battery room temperature. Additionally,.the licensee found that the ventilation damper for the battery room was not functioning properly, and they initiated actions *
to correct the problem. The licensee plans to continue the weekly inspections and followup activities until this item is fully resolved. The inspector will monitor the licensee's efforts.
15 Unit 1 Engineered Safety Features (ESF) Actuations At 1 : 03 a. m., on June 6, 1991, an inadvertent ESF actuation occurred on Unit 1 during surveillance testing. During performance of procedure Sl.MD-FT.4KV-0003(Q) on the lC vital 4KV bus undervoltage (UV) relay 27-lC/2, an I&C technician inadvertently touched the terminals of an adjacent relay (27-lC/l) with a jumper. This action satisfied the two of three coincidence necessary to cause an electrical load shed on the lC 4KV vital bus, a start of the lC emergency diesel generator (EDG), and a sequential start of associated safety related component All systems functioned as designed. The operators entered procedure AOP-ELEC-4KV-C and verified automatic actions. Per the procedure, the operators secured unnecessary loads and returned the lC vital bus to a normal lineup. The lC EDG was subsequently secured and returned to standby. The affect on unit operation was minimal. Slight increases in pressurizer level and containment pressure were adequately compensated for by operator At 2:09 a.m., on June 13, 1991, a second and similar ESF actuation occurred on Unit During restoration from testing of the IB vital bus UV relays with Sl.MD-FT.4KV-0002(Q),
an I&C technician skipped a step in the procedure. This resulted in the bus potential transformer (PT) fuse to blow because the test equipment was still installed. A loss of voltage signal in IB bus resulted in an electrical load shed, a lB EDG start, and a sequential start of safety related equipment. All systems functioned as designed. The operators entered AOP-ELEC-4KV-B and verified automatic actions. The Safeguards Equipment Cabinet (SEC) could not be reset because a false loss of voltage remained on the 4KV bus. The licensee de-energized the SEC, ent.ered a six hour Technical Specification Action Statement (TSAS), commenced a unit shutdown, and made an ENS call. The PT fuses were subsequently replaced, systems were tested satisfactorily and declared operable, and the TSAS was exited at 6:30 a.m. Reactor power had been reduced to 75%.
Licensee followup actions included the normal incident report investigatio The licensee determined root cause to be personnel error, with contributing causes to be testing arrangements, procedures, and human factors considerations. In addition, the licensee assembled a Significant Event Response Team to review these events. The licensee intends to submit an LER for these events. Corrective actions included reviewing and modifying the test method and arrangement, re-instructing test personnel, and informing maintenance personnel regarding these event The inspector responded to the control room to review post event recovery operations. The inspector discussed these events with the on-shift operators and with maintenance, operations and plant management personnel. The inspector examined. the relay and testing arrangements at the 4KV vital bus. The inspector also reviewed associated documents including the test procedure, TSASs, control room logs and the incident report. The inspector concluded that safety systems functioned as designed, and that the licensee adequately determined root cause and implemented corrective actions.
16 Containment Penetration Conductor Overcurrent Protection Devices On June 3, 1991, the licensee informed the inspector of a potential problem with meeting the requirements of Technical Specification (TS) -3/4.8.3.1 regarding containment penetration overcurrent devices. Each electrical conductor that penetrates containment is required to have ail operable primary and backup overcurrent protection device. These devices may include breakers and/or fuses. Unit 1 had just implemented these TS requirements on the completion of the ninth refueling outage (February - April 1991). TS Amendment No. 105 (Unit 1) and N (Unit 2) dated December 4, 1989, added these requirements for Unit 1 and removed the associated TS table in the FSAR for Unit TS surveillance requirement 4.8.3.1 requires a functional trip test of 10% of the overcurrent devices every 18 months, and inspection and preventive maintenance of all devices every 60 months. A QA review of the Unit 1 TS implementation determined that the TS surveillance requirement may not have been properly met. Unit 2 implementation of the similar TS was satisfactory. As a result at 5:35 p.m. on June 3, 1991, the licensee entered TS Action Statement (TSAS) 3.8.3.1.a for Unit 1. This required the devices be operable in 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> on the circuits tripped and* the associated components declared inoperable. The licensee also informed the
- inspector that preventive maintenance (PM) and inspection, and retesting for one motor operated valve (MOY), 1CV284, would require stroking of the MOY. However, since this MOY was the reactor coolant pump seal return valve, its cycling would not be appropriate at powe Therefore, the licensee pursued a waiver of compliance. Further licensee review determined that maintenance had been performed on this component and other breakers during the Unit 1 ninth refueling outage (February - April 1991). The licensee also contacted the breaker vendor (GE)
and received concurrence that maintenance performed during the outage was acceptable. Also, an Engineering and Plant Betterment (E&PB) engineering directive concluded that inspection and preventive maintenance performed per the vendor manual was acceptable to meet TS 4. 8.3. For those devices that no maintenance records could be found, the licensee performed the required maintenance per procedure MP2.5, "Motor Control Center Maintenance." The licensee concluded that they met the TS requirements and exited TSAS 3.8.3.1.a on June 6, 1991. Also, no waiver of compliance was neede The inspector reviewed the following documents:
General Electric letter (EFS-91-040) dated June 5, 1991 E&PB engineering directive S-2-E30-EFD-277, Revision 1, dated June 5, 1991 Various work orders performed during the recent Unit 2 refueling outage Maintenance Procedure MP-GE Vendor Manm~l, "Testing and Maintenance of Molded Case Circuit Breakers" The inspector concluded that licensee actions appeared appropriate once the problem was identified by QA. However, TS 3/4.8.3.1 compliance for Unit 1 is unresolved pending the
completion of the licensee's historical review and LER submittal, if appropriate (UNR 272/91-15-02). Unit 2 Vital 4KV Bus Undervoltage Relays Found Out-of-SpecificatiOn (UNR 311/91-05-01)
On June 3, 1991, during performance of a maintenance surveillance test on the Unit 2 three 4KV vital buses, five of the nine undervoltage (UV) relay trip setpoints were found to be low and out-of-specification. The minimum Technical Specification allowed value for the trip setpoint is 108.2 volts. The lowest value for any relay setpoint found on June 3, 1991, was 107.52 volt These Unit 2 relays had previously been found out-of-specification on February 26, 1991, (see NRC Inspection Report 50-311/91-05) and the Unit 1 relays had been discovered to be low and out-of-specification on April 13, 1991 (see NRC Inspection Report 50-272/91-09). Due to these prior two events, the licensee had begun performing the relay calibration surveillance on a weekly basis vice the original monthly basis. The licensee's initial investigation into the drifting of the relay setpoints had concluded the cause to be the better accuracy in setpoint determination available with a new procedure and new test equipment. On June 3, 1991, however, the as-fotind setpoints had been set with the new procedures and equipment, and the licensee continued the investigation into the setpoint drifting problem. The investigation is focusing on component aging and possible human factor effects of the surveillance procedur At the end of the inspection period the licensee investigation was still progressing and, in conjunction with the relay manufacturer, Rochester Instruments Systems, Inc., PSE&G was considering filing a 10 CFR Part 21 report on the relays with the NR Following the June 3, 1991 discovery of the low relay setpoints, the inspector determined that the relay setpoints had immediately been reset to their required value and discussed the question of the relay's operability with licensee engineering. The responsible engineer had determined that, to-date,* none of the relay trip setpoints had drifted low enough to prevent the relay from adequately performing its safety function. The inspector concluded that the licensee's actions and modified surveillance schedule were conservative and adequate to ensure operability of the relays pending the final determination of the engineering investigation.* The resident inspector staff, along with NRC Region I and Headquarter specialists, are following licensee actions, and this item remains unresolve.3.3 Hope Creek Open Item Followup (Closed) UNR 354/89-02-002. This item dealt with the leak rate testing of various containment isolation valves installed (by design) such that the valves' packing glands are not subjected to local leak rate test pressure.
The licensee was informed that their test methodology was acceptable with additional controls to prevent inadvertent packing adjustment pending resolution of this issue. The licensee duly implemented the necessary program control The inspector reviewed these controls to prevent inadvertent packing adjustments and determined them to be adequate. The licensee's pursuit of a long-term resolution to this issue is ongoin A BWR owners group position is currently being formulated and will be available later this yea The licensee is actively involved with the owners group on this issue and the licensee's activities in this area will be assessed after their implementation. Consequently, this item is close "D" Emergency Diesel Generator (EDG) Start Failure On May 22, 1991, during the performance of the monthly EDG operability surveillance test HC.OP-ST.KJ-004, "D" EDG failed to start on the first attempt. An immediate investigation could not determine an apparent cause for the failure. The licensee determined that per the surveillance's acceptance criteria, this was considered a valid test failure. This was the second valid test failure within the last 20 valid starts (the first occurred on January 7, 1991). The licensee was therefore required by Technical Specification (TS) Table 4.8.1.1.2-1 to increase the test frequency from once per 31 days to once per seven days until seven consecutive successful tests had been performed and the number of failures in the last 20 valid tests had been reduced to one.
About 30 minutes after the diesel had first failed to start, the test was repeated. The diesel started and loaded as require By the close of this inspection period the diesel had been successfully run four consecutive times with three more starts needed to fulfill the TS requirement and return to the normal surveillance interval. The licensee's investigation by engineering support personnel was ongoing at the period's en The inspector discussed the diesel start failure and subsequent investigation with the engineering personnel involved and concluded that to date the actions taken had been appropriate and thorough. The inspector also verified that the licensee had correctly determined the number of increased frequency tests required to satisfy the TS action statemen Scheduled System Maintenance The licensee performs corrective and preventive maintenance on plant systems both during refueling outage periods and during system outages that occur during the operating cycle. The inspector reviewed the licensee's process for scheduled system maintenance with the unit at powe Two weeks prior to a scheduled system outage, the maintenance planning department assembles a list of open work orders. This includes corrective maintenance, preventive maintenance, inspection and testing activities for the syste Work is then reviewed by maintenance, engineering and operations personnel. An approved sequential work list is published. The
allowed outage time per technical specification action statement (TSAS) is also reviewe Planned work is then scheduled not to exceed 2/3 of the TSAS time, with work ongoing for round-the-clock coverage. Required system tagouts, and post-maintenance inspection and testing activities are included in this schedul The final work list is then reviewed by plant management the week prior to the scheduled system outage. Management determines whether the work list justifies taking the system out-of-service for maintenanc The inspector reviewed this process as discussed in procedure NC.NA-AP.ZZ-0009(Q), "Work Control Process." The inspector also observed implementation of the process for the B and C loops of low pressure coolant injection, and for the C emergency diesel generator. This included pre-outage work lists and schedules, system tagouts, work in progress, planning and management reviews, and post-maintenance testing. The inspector concluded that the process. works well and that management is involved throughout. The licensee is considering procedural enhancements including the use of PRA as an input for the decision process in removing systems from service for maintenanc Reactor Core Isolation Cooling (RCIC) System Isolation Valve Closure At 4:47 p.m., on May 15, 1991, during the performance of a surveillance test on dry\\.vell pressure instrumentation, RCIC vacuum breaker isolation valve FCHV-F062, a normally open valve, closed for no apparent reason. Troubleshooting during the ensuing investigation could not duplicate the event. The isolation valve was reopened and system lineup returned to normal at 5: 15 p.m. The licensee made the required notifications to the NRC and other parties per their procedure The licensee h3:s performed an extensive investigation into this event, however, a root cause has not been determine As described in LER 91-10, two possible scenarios are under consideration, an electrical spike (or fault) in one (or more) of the six components in the RCIC low steam pressure instrumentation or an error on the part of the technician performing the surveillanc In the latter scenario, the technician involved did not remember making any procedure errors/deviations and independent verification of steps had been provide Troubleshooting the electronic circuits would require RCIC to be inoperable for a potentially significant period. The licensee's Safety Operations Review Committee (SORC) determined that there was no net safety benefit to removing RCIC from service for this troubleshooting, especially as the RCIC surveillance was successfully completed when repeated following the reset of the isolatio The licensee intends to continue investigating during the next forced or scheduled unit outag The inspector concluded that the licensee's actions in this event appeared appropriate and demonstrated a good safety perspective relative to removing RCIC from service. No significant deviations were noted in LER 91-10, also a supplement to LER 91-10 would be submitted no later than November 15, 1992 detailing the results of the troubleshooting and inspection.
20 EMERGENCY PREPAREDNESS 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 Inspection Findings There were no noteworthy findings during this inspection perio.
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 boundaries. These inspection activities were conducted in accordance with NRC inspection procedure 7170.2 Inspection Findings Fitness for Duty (FFD); Reinstatement of Licensed Operator On February 21, 1991, a Hope Creek licensed reactor operator (RO) was removed from licensed duties and had his unescorted access authorization revoked after testing. (See Inspection Report 354/91-04, Section 6.2.A for details).
On June 10, 1991, licensee operations management informed the resident staff that the RO had successfully completed the prescribed rehabilitation
. program and had been evaluated by the licensee's medical staff and operations management as fit for reinstatement of his unescorted access and return to his former position. Consequently, the RO was returned to his licensed duties effective June 7, 1991. Licensee FFD procedure NC.NA-AP.ZZ-0042 requires more frequent unannounced followup tests following reinstatement. This includes testing at least once per month for the first four months, then at least once per quarter for the following two years and eight month The inspector reviewed licensee actions and determined them to be per approved procedures and FFD program requirement Security Exercise On May 29, 1991, the licensee conducted a security exercise at the Hope Creek facilit Participants included the site security force organization, and law enforcement agencies from
the local area, the co-unty and the state. The drill scenario included area intrusions, sabotage and terrorist activities. A pre-drill briefing and post-drill critique were hel The inspector observed portions of the drill from the security alarm stations and in the fiel Overall drill performance was good. The licensee effectively planned, conducted and critiqued their performance. Areas for improvement were identified. The inspector noted senior licensee security management personnel observing and conducting the drill. The inspector questioned why Hope Creek operations was not involved to provide more realism and emergency plant implementation. The licensee stated that operations was not part of the scenario for this first drill, however, that operations would participate in future drill.
ENGINEERING/TECHNICAL SUPPORT Salem Open Item Followup (Closed) Unresolved Item (272/90-05-02) Cable separation deficiencie Several more deficiencies were subsequently identified in NRC Inspection 50-272 and 311/90-81. Unresolved Item 272/90-81-13 was opened to address the programmatic weaknesses in the cable separation program. Unresolved Item 272/90-05-02 is therefore administratively closed. Salem Unit 1 Service Water System Inspection On March 22, 1991, during the Salem Unit 1 ninth refueling outage, the inspector conducted a tour of certain areas of the service water system (SWS). The results of the inspection are summarized as follows. Visual examination of the inside diameter surface of several open three inch branch connections in no. 11 containment fan coil unit showed no evidence of corrosion deposits -or pittin The overall surface, however, exhibited a light oxide fil These connections had been replaced in spring 1989 with AL6XN, a highly corrosion resistant stainless steel with six percent molybdenum. The degree of corrosion is similar to that found on corrosion test specimens examined by the inspector during a November 1990 NRC inspectio The licensee reported that by the end of the present outage about 47 percent of the scheduled replacement of the SWS with AL6XN was complete The inspector also observed replacement work in progress in the number two and three SWS intake bays and lB diesel generator room where reduced-wall thicknesses were uncovered during an NRC inspection on February 4-15, 1991 (NRC Inspection Report 91-04). The i~spector also examined numerous piping components of various sizes which had been recently removed from the SWS valve room. The inner* diameter cement lined or coal tar epoxy lined surfaces were found to be in good condition with only isolated areas of lining deterioration observed. No evidence of visible marine growth was seen. The relatively good condition of these components supports the licensee's opinion that the overall structural integrity of the SWS was not in immediate danger of being compromised. Isolated leaks due to microbiologically influenced
corrosion (MIC) or susceptible areas due to unfavorable design could be expected until replaced with new materials and/or new component On April 23, 1991, the licensee provided the inspector with a set of "marked up" SWS drawings showing the replacements completed during the Unit 1 refueling outage. The work included certain piping components associated with the lA, lB and lC diesel generators water coolers and oil coolers, various pump room coolers, and steam generator blowdown heat exchangers. The replacement material was* the same as the material removed, either cement lined or coal tar epoxy lined carbon stee The inspector concluded that the SWS pipe replacement program is progressing appropriatel.2 Hope Creek Open Item Followup (Closed) Unresolved Item (354/90-20-01) Source Range and Intermediate Range Monitor environmental qualification. This item was upgraded to a violation in NRC Inspection Report 354/90-23-01. The unresolved item is considered closed and the violation remains ope Filter, Recirculation and Ventilation System (FRVS) Failures On May 5, 1991, while performing a monthly FRVS surveillance, three of the recirculation units were determined to be inoperable due to blown fuses in the heater control circuits. Since the Technical Specifications (TS) allow only two units to be inoperable at any one time, TS 3. was entered at 9:58 a.m. The blown fuses were replaced and the TS action statement exited prior to the time a plant shutdown would have to be initiate The licensee's corrective actions included initiating a change to the applicable surveillance procedures to verify FRVS heater element currents by a different method. Additionally, the Systems Engineering group would perform testing on the heater groups to determine the root cause of the blown fuses. The investigation was still ongoing when the inspection period close The inspector determined that the licensee's actions in this event were appropriate. The Licensee Event Report (LER) discussing this event was reviewed and no discrepancies were observed (LER 354/91-07). *The inspector noted that a supplement to the LER would be submitted discussing the results of the investigation.
23 SAFETY ASSESSMENT/QUALITY VERIFICATION Common Effectiveness of 10 CFR 50.59 Safety Evaluation Reviews On May 9, 1991, PSE&G personnel met with the inspectors to appraise them of the results of the Off-Site Safety Review (OSR) assessment of the effectiveness of 10 CFR 50.59 applicability reviews at Salem and Hope Creek. This meeting was scheduled as a follow-up on PSE&G's commitment in its response to the Notice of Violation on Salem misapplication of 10 CFR 50.59 safety evaluations (NLR-N91016 dated February 1, 1991).
The inspectors reviewed OSR reports, OSR 91-001 and OSR 91-002, dated February 20 and April 18, 1991, respectively. Overall, the licensee concluded that the 10 CFR 50. 59 process is functioning per procedure NC.NA-AP.ZZ-0059(Q).
No unreviewed safety questions were identified, and no problems with Station Qualified Reviewer (SQR) independence or training were identified. However, the following deficient items were noted:
Two documents were incorrectly screened from NAP-59 consideration (Hope Creek).
Two documents had incorrect 10 CPR 50.59 applicability conclusions (Hope Creek).
One document had insufficient detail to support its conclusion (Salem).
Nineteen documents had minor documentation deficiencies (Hope Creek and Salem).
The process (procedure) was not being used by Nuclear Service Departmen A 10 CPR 50.59 process was not in place for deficient balance of plant (BOP)
component OSR recommendations and corrective actions included the following:
Revision of the deficient applicability reviews; Full adoption of the change review process by the Nuclear Services Department; Inclusion of the 10 CPR 50.59 process for BOP reliability control program; Re-enforcement, through training, of the importance of providing complete change description, and identification of all of the relevant licensing-basis documents reviewed to support the change; and, A commitment to re-audit the program in late 1991
~-
The inspector concluded that the licensee performed a thorough review of this process. Further, the licensee has noted improvements in their 10 CFR 50.59 safety evaluation process and that OSR has performed an adequate assessmen The Salem unresolved item (272/90-81-18)
regarding SQR training is considered closed. The Salem unresolved item (272/90-81-23) remains open pending completion of NRC review. In addition, the inspector is opening an unresolved item for Hope Creek regarding the 10 CFR 50.59 safety evaluation process to track licensee improvements and subsequent NRC review (UNR 354/91-12-01). Self Assessment Capability The inspector assessed licensee performance during the current SALP period. The inspector reviewed reports, and other related correspondence and documentatio Each licensee department manager and the station general manager assessed their performance and indicated areas for improvement. Issues were discussed with each Salem manager individually. At Hope Creek issues were discussed at a meeting on June 10, 199 The inspector concluded that the licensee has the capability to adequately assess their performanc.2 Salem Station Operations Review Committee (SORC)
The inspector attended several SORC meetings during the perio This. included meeting numbers 91-64, and 65. The inspector verified that tfiese meetings met the requirements of Technical Specification 6.5.1 and administrative procedure NC.NA-AP.ZZ-0004(Q).
The inspector noted that SORC thoroughly reviewed each issue. A good questioning attitude and an excellent safety perspective was note For example, SORC did not approve a safety evaluation for a secondary plant design change due to problems with the process. Changes were made to an LER to better focus corrective action The inspector concluded that SORC is effectively implementing its review and audit functio Performance Trend Analysis The Salem technical group reviews licensee event reports (LERs) and incident reports (IRs)
annually for trends and overall station performance. The inspector reviewed the 1990 analysis as presented in a licensee report dated March 13, 1991. The licensee concluded that the number of LERs and IRs has increased, and personnel error continues to be the primary root caus Also, the number of procedure inadequacy events has decreased primarily due to the procedure upgrade project (PUP). This review also identified that IR backlog is high.
Overall, the inspector concluded that this report was factual and thorough, and adequately assessed performanc Open Item Followup (Closed) Unresolved Item (272/89-23-01) Impending NRC guidance for Technical Specification (TS) surveillance requirements for AMSAC Syste The NRC is independently evaluating the applicability of TSs for AMSAC, and the issue will be addressed separately (e.g. Generic Letter, Information Notice). Licensee response will be evaluated at that time. This item is close.
(Closed) Unresolved Item (272/89-27-03) Teehnical Specification Interpretations (TSis)
are not reviewed by the Station Operations Review Committee (SORC). Both the Unit 1 and 2 TSis have been reviewed by the SORC following TSI technical review and evaluation. The inspector reviewed selected TSis and found that sufficient technical bases were provided for the associated interpretations. This item is considered resolved and close.3 Hope Creek A.
Station Operations Review Committee (SORC)
The inspector attended several SORC meetings during the period. This included several special SORC meetings (number 91-036) after the May 7, 1991, scram (see section 2.2.3.A) and a routine meeting (number 91-050) on May 22, 1991. The inspector verified that these SORC meetings met the requirements of Technical Specification 6.5.1 and administrative procedure NC.NA-AP.ZZ-0004(Q), Revision The inspector noted that the SORC thoroughly reviewed the scram, determined root cause, and established corrective actions necessary for unit restart. The inspector also noted that at the routine SORC meeting members displayed a good questioning attitude and an excellent safety perspective. As a result, a temporary modification to the main turbine steam seal evaporator due to level transmitter failure was not approved. This was due to an incomplete operations and systems engineer review of the effects that could result from this temporary modification. Also at this SORC meeting, a revision to the inservice testing administrative procedure was delayed due to probing questions regarding slow valve closure time In all, the inspector concluded that the Hope Creek SORC is effectively implementing its review and audit functio Performance Trend Analysis The Hope Creek technical group reviews licensee event reports (LERs) and incident reports (IRs)
annually for trends and overall station performance. The inspector reviewed the 1990 analysis
as presented in a licensee report dated March 27, 1991. The licensee concluded that the number of LERs and IRs, and personnel errors has remained relatively constant for the last three year However, they concluded that human personnel error continues to be the predominant factor of all incidents, and in particular, lack of attention to detail as the primary root cause. A 1990 station goal of nine errors was exceeded as twelve errors occurred. Overall, the inspector concluded that this report was factual and thorough, and adequately assessed performanc As a result of personnel errors in general and specifically as a result of the May 7, 1991, scram (see section 2.2.3.A) caused by l&C technician personnel error, the licensee has initiated the following:
Quality Assurance review of recent personnel erro Safety Review Group assessment of collective root causes, adequacy of the corrective actions and common threads for the recent seven reactor scrams (December 1989 - May 1991).
General Manager restatement of the station priorities for error free work with an emphasis on attention to detail and "self-checking".
The inspector reviewed these initiatives and discussed them with licensee management personne These initiatives appear to be an appropriate step towards understanding the higher than normal Hope Creek.scram rate (e.g. seven scrams in one and one-half years) and personnel error rat Standby Liquid Control (SLC) System Inoperable During Monthly lnservice Testing On June 5, 1991, a review of Operating Experience Report 4622 by a member of the licensee's Safety Review Group (SRG) determined that a similar situation existed at Hope Creek. During inservice testing while one SLC pump was on recirculation to the test tank, should an automatic initiation signal occur, the discharge from the operable pump would also be directed to the test tank through the under test loop's exploded squib valve instead of the reactor vesse Consequently, the performance of either inservice test procedure (HC.OP-IS.BH-0001or0002)
would technically render both SLC loops inoperable. The licensee immediately changed both procedures to fully isolate the loop to be tested so that the other loop would still be operabl With both SLC pumps inoperable Technical Specification (TS) 3.1.5 requires the restoration of at least one loop within eight hours for continued reactor power operation. A review of the last two previously performed procedures established that the test performance time averaged about three hours in length and neither test was found to have exceeded the eight hour TS action statemen The licensee therefore concluded that although they had unknowingly entered a limiting condition, no TS violation had occurred. The licensee initially decided that this event was not reportable to the NRC under 10 CFR 50.72. However, after discussion with the NRC resident staff, a four-hour non-emergency report was made per 10 CFR 50. 72 and in accordance with Section 18, Part 0 of the licensee's Event Classification Guide (ECG). The inspector also
noted that the licensee's conclusion that no TS violation had occurred was based on too small a sample to establish an adequate confidence level. The licensee agreed with the observation and stated that a further review would be performe In summary, the inspector concluded that the licensee demonstrated a good safety perspective relative to the review of industry-generated experience reports for applicability to Hope Creek and had taken appropriate corrective action for the situation discussed above. However, an apparent weakness was noted in the determination of reportability artd the adequacy of the review for TS complianc.
LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS, AND OPEN ITEM FOLLOWUP 9.1 LERs and Reports PSE&G submitted the following licensee event reports, and special and periodic reports, which were reviewed for accuracy and evaluation adequac The Salem and Hope Creek Monthly Operating Reports for April and May 1991. No unacceptable conditions were noted.
Hope Creek Special Report 91-01 dealt with a valid test failure of the "D" emergency diesel generator (EDG) on January 7, 1991, the first such failure in the last 100 valid starts. No deficiencies were noted in this report. (See Section 4.3.2.B of this inspection report for a discussion of a second valid test failure of the "D" EDG on May 22, 1991.)
Hope Creek Special Report 91-02 discussed the inoperability of one seismic monitoring channel for greater than 30 days. During a semiannual functional test on March 21, 1991, the longitudinal trace of the triaxial time-history accelograph did not function properly due to a failed sensor located on the "B" core spray pipe in the drywell. Repairs were scheduled for the next outage where a drywell entry could be made. The inspector concluded that the failure of one (of 12) channel did not unacceptably degrade overall accelograph operation and that licensee actions in this regard were appropriate. No deficiencies were noted in the repor Hope Creek Technical Specification 6.9.1.5 - challenges to main steam line safety/relief valves (SRV) - Annual Report for 1990 noted that there were two challenges to the SRVs as discussed in LERs 90-01 and 90-28. No deficiencies were noted in this annual report.
Salem LERs Unit 1 LER 91-017 reported the undervoltage trip setpoints for the nine 4 KV vital buses being found low and out-of-specification on April 13, 1991. This event was previously documentd in NRC Inspection Report 50-272/91-09, Section 4. 3. 1. D, and the progress of the licensee investigation is updated in Section 4.3.. 2.E of this report. No inadequacies were noted relative to this LE LER 90-018 concerned a Unit 1 manual safety injection test failure and was discussed in NRC Inspection 50-272/91-0 LER 91-019 (See section 4.3.2.A)
LER 91-020 (See Section 2.2.2.C)
Unit 2 None Hope Creek LER 91-07 (See Section 7.2.B)
LER 91-08 (See Section 2.2.3.A)
LER 91-09 discussed a reactor scram which occurred on May 8, 1991, while the unit was shutdown. As all control rods were already fully inserted, no control rod motion occurred, all appropriate annunciation and actions were received/noted. Reactor Protection System (RPS)
channel "B" was in a tripped condition due to a number of intermediate range monitors (IRM)
being inoperable for maintenance and testin When IRM "G", feeding RPS channel "A" electrically spiked high, the trip logic was satisfied and a full scram signal was generated by the RPS. Corrective actions consisted of replacing the "G" IRM detector. Additionally, the licensee is conducting an internal investigation into IRM reliability to identify potential enhancement No inadequacies were noted in this LE LER 91-10 (See Section 4.3.3.D)
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9.2 Open Items The following previous inspection items were followed up during this inspection and are tabulated below for cross reference purpose /89-23-01 272/89-27-03 272/90-05-02 272/90-81-18 272/90-81-23 272;311/91-08-02 311/91-05-01 Hope Creek 354/89-02-02 354/90-20-01 Report Section 8......2..3..3...
EXIT INTERVIEWS/MEETINGS 1 Resident Exit Meeting Closed Closed Closed Closed Open Open Open 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 summarize the scope and findings of their inspection activitie Based on Region I review and discussions with PSE&G, it was determined that this report does,
not contain information subject to 10 CFR 2 restriction.2 Specialist Entrance and Exit Meetings Inspection Reporting Date(s)
Subject Report N Inspector 5/13-17/91 Rad waste 272&311/91-13; Noggle Transportation 354/91-11 5/20-24/91 Maintenance/
272&311/91-16 Finkel Surveillance
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- 6/10-14/91 Requalification 272&311/91-14 Silk 5113-617191 Requalification 354/91-10 Fish 5/20-24/91 Maintenance/
354/91-13 Baunack Surveillance 6/10-14/91 Procedures 272&311/91-17 Baunack 6110-14/91 Radiation 272&311/91-18 Nimitz Protection