IR 05000354/1998001
| ML20248L708 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 03/16/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20248L707 | List: |
| References | |
| 50-354-98-01, 50-354-98-1, NUDOCS 9803240097 | |
| Download: ML20248L708 (58) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
l Docket No:
50-354 License Nos:
NPF-57 Report No.
50-354/98-01 Licensee:
Public Service Electric and Gas Company
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Facility:
Hope Creek Nuclear Generating Station I
Location:
P.O. Box 236 Hancocks Bridge, New Jersey 08038 Dates:
January 4,1998 - February 21,1998 i
l inspectors:
S. A. Morris, Senior Resident inspector J. D. Orr, Resident inspector J. D. Noggle, Senior Radiation Specialist Approved by:
James C. Linville, Chief, Projects Branch 3 Division of Reactor Projects
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9803240097 980316 PDR ADOCK 05000354 G
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EXECUTIVE SUMMARY Hope Creek Generating Station NRC Inspection Report 50-354/98 01 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a seven week period of resident inspection; in addition, it includes the results of an announced inspection by a regional l
inspector who reviewed occupational radiation exposure programs and controls at the l
facility.
l Operations Hope Creek operators exhibited good control over routine activities. Operators were sensitive to adverse equipment conditions and initiated additional equipment monitoring when necessary. Control room operators effectively implemented technical specification action requirements when necessary.'(Section 01.1)
Station housekeeping and transient load control were generally adequate but had declined during recent months. (Section O2.1)
Two unrelated incidents involving standby liquid control system storage tank boron concentration resulted from weak communications, insufficient attention to detail, and ineffective supervisory oversight. Once identified, management response to the issues was prompt and thorough. (Section 04.1)
i Operating crew performance during electrohydraulic control system oscillations was appropriate and safe. Each event was promptly identified and notifications were made within the Hope Creek organization to ensure that problems were addressed. Engineering and operations department personnel worked closely to identify the cause of the failures and to determine an action plan for continued safe plant operation. However, operators did not formally assess the degraded condition in an operability determination. (Section 04.2)
The Nuclear Review Board completed a quality overall review of station activities, and provided good, objective performance feedback to station management. (Section 07.1)
PSE&G adequately maintained NRC-required postings at the site. (Section 08.1)
Maintenance PSE&G management was slow to recognize an apparent declining trend with respect to technical specification surveillance program implementation. Upon recognition, a focused team review was initiated in an effort to fully understand the issue and to develop actions to improvement future performance. (Section M1.1)
An on-line maintenance outage of the "D" emergency diesel generator was appropriately planned and implemented. A quantitative risk assessment adequately justified that the outage resulted in a net safety benefit. Good maintenance, engineering, and operations ii i
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department oversight of the work and test activities was evident. Weaknesses were
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observed in operator knowledge of associated technical specification bases information and implementation of required surveillance activities. (Section M2.1)
In part because of inspector questioning, maintenance department management initiated an assessment of poor work performance during the recently completed refueling outage.
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PSE&G completed a high quality and thorough review, and developed several corrective actions which appropriately focused on the stated root causes. (Section M7.1)
Enaineerina An emergency diesel generator control circuit relay modification package was effectively planned and implemented, and incorporated lessons learned from previous implementation of the modification in other diesel generators. (Section M2.1)
Several earlier opportunities to identify and correct causal factors associated with intermittent failures of the "F" filtration, recirculation, and ventilation system unit were missed, increasing the overall unavailability time of the unit. However, PSE&G's efforts following a recent surveillance test failure of this unit were of excellent quality, and reflected a renewed management focus on the control of troubleshooting activities.
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Engineering personnel properly monitored the performance of the radiation monitoring system at Hope Creek. Appropriate root cause evaluations and corrective actions were either proposed or initiated for identified problems. An expert panel meeting to review and approve a proposed change to performance monitoring of vital electrical system switchgear was thorough and satisfied its chartered requirements. (Section E2.2)
Upon discovery, engineering department personnel conducted a thorough and accurate analysis of the impact of a core flow miscalculation completed in operating cycle seven.
(Section E2.3)
The engineering department provided effective support to operations staff in an attempt to minimize frequent elevated pressure conditions in the residual heat removal system shutdown cooling suction piping. Engineering also supported radiation protection technicians by providing a method to minimize the radiation dose received during the course of clearing the elevated pressure condition. (Section E2.4)
The configuration and material condition of the filtration, recirculation, and ventilation system was adequate. (Section E2.5)
PSE&G design engineering personnel performed a quality design and licensing basis review of the turbine building battery exhaust ventilation system to validate its acceptability with respect to effluent release path requirements. Minor modifications were developed to l
further enhance the system's design. (Section E3.1)
In general, resolution of the specific deficiencies identified by the service water system operational performance inspection (SWSOP!) has been timely and appropriate.
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Engineering management response to broader programmatic conclusions of poor performance were of good quality in that specific, detailed action plans were developed and implemented to address the issues. (Section E8.3)
Plant Sunoort The design of a condensate profilter system at Hope Creek appeared capable of reducing the radiological source term of the plant and acting to reduce stress corrosion cracking.
(Section R1.1)
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l Radiation protection department support for emergent reactor water cleanup pump seal
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maintenance was well planned and executed. (Section R1.2)
PSE&G maintained low collective exposures at Hope Creek as compared to other boiling l
water reactors, however, there were several areas of opportunity for reducing high
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exposure sources in the plant to maintain the plant in an as low as reasonably achievable condition. (Section R1.3)
PSE&G effectively controlled and prevented internal exposures at Hope Creek during l
refueling outage number seven. (Section R1.4)
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PSE&G maintained an accurate and reliable external exposure monitoring program.
(Section RI.5)
PSE&G conducted several levels of RP program oversight with varying degrees of effectiveness. The Radiological Occurrence Report program did not provide consistently
high quality results in that twveral low safety significance chronic issues remained unresolved after ceveral months. The RP program reviews provided an adequate system of checks and balances, but did not contain significant recommendations for program
enhancements. (Section R7.1)
l-i A quality assurance department audit provided an effective and timely assessment of l
emergency preparedness performance. Identified deficiencies were properly entered into j
the corrective action process for resolution. (Section P7.1)
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l PSE&G se::urity department management acted promptly and appropriately in resolving several minor site access badging issues. (Section S1.1)
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TABLE OF CONTENTS I
EX EC UTIVE SU M M ARY.............................................. ii
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TA B LE O F CO NTE NTS............................................... v l
1. O p e ratio n s..................................................... 1 O1 Conduct of O perations.................................... 1 l
01.1 G eneral O observations................................ 1
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O2 Operational Status of Facilities and Equipment................... 2 O2.1 General Plant Housekeeping........................... 2
Operator Knowledge and Performance......................... 3
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I O4.1 Standby Liquid Control System Storage Tank Chemistry Control.. 3 04.2 Electrohydraulic Control System Oscillations................ 5
Quality Assurance in Operations............................. 6 07.1 Nuclear Review Board Activities
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Miscellaneous Operations issues............................. 7 l
08.1 NRC Posting Requirements............................ 7 l
ll. M ainte n a nc e................................................... 7 M1 Conduct of Maintenance................................... 7 M 1.1 Technical Specification Surveillance Testing Program.......... 7 M2 Maintenance and Material Condition of Facilities and Equipment....... 8 M2.1
"D" Emergency Diesel Generator On-Line Maintenance........ 8 M7 Quality Assurance in Maintenance Activities.................... 10 M7.1 Poor Maintenance Work Practices During RFO7............. 10 M8 Miscellaneous Maintenance issues........................... 11 M8.1 (Closed) LER 50-354/97-33: technical specification prohibited
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condition - failure to perform secondary containmer,t isolation actuation instrumentation channel checks................ 11 M8.2 (Closed) LER 50-354/97 34: operation in a technical specification (TS) prohibited condition due to both subsystems of main steam isolation valve sealing system (MSIVSS) inoperable.......... 12 l
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lil. Engine ering................................................... 13 E2 Engineering Support of Facilities and Equipment................. 13
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E2.1 Filtration, Recirculation, and Ventilation System Troubleshooting. 13 E2.2 Safety System Performance Monitoring.................. 14 E2.3 Core Flow Miscalculation During Operating Cycle Seven...... 16 E2.4 Residual Heat Removal System In leakage................ 17 E2.5 Engineered Safety Feature System Review................ 18 E3 Engineering Procedures and Documentation.................... 19 E3.1 Turbine Building Battery Exhaust System Review............ 19 E3.2 Inservice Testing of Core Spray Subsystem Pumps and Valves.. 20 E8 Miscellaneous Engineering issues............................ 21 E8.1 Service Water System Operational Performance Inspection Follow Up R e vie w......................................... 21 v
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E8.2 (Closed) VIO 50-354/E97-160-01013: inadequate safety evaluation for residual heat removal (RHR) cross-tie modification........ 22 E8.3 - (Closed) VIO 50-354/97-01-06: temporary scaffolding not installed or maintained in accordance with established procedures........ 22 E8.4 (Closed) LER 50-354/97-31: engineered safety feature actuation -
reactor core isolation cooling (RCIC) system isolation......... 22 I V. Pl a nt Su pport................................................. 2 3 R1 Radiological Protection and Chemistry (RP&C) Controls............ 23 R1.1 Radiological Source Term Effects of a Condensate Filter Modification
..............................................23 R1.2 Applied RP Performance............................. 25 R1.3 As Low As is Reasonably Achievable (ALARA) Performance.... 25 R1.4 Internal Exposure Control............................ 27 R1.5 External Exposure Measurement...................... 27 R7 Quality Assurance in RP&C Activities......................... 28 R7.1 RP Program Review and Oversight...................... 28 P7 Quality Assurance in EP Activities........................... 30 i
P7.1 Quality Assurance Audit of Emergency Preparedness......... 30
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S1-Conduct of Security and Safeguards Activities.................. 30 l
S1.1 Protected and Vital Area Access Control................. 30
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V. Management Meetings........................................... 31 X1 Miscellaneous......................................... 31 X2 Exit Meeting Summary................................... 31 X3 Pre-Decisional Enforcement Conference Summary................ 32 X4 Management Meeting Summary............................. 32 l
i INSPECTION PROCEDURES USED..................................... 33 j
i ITEMS OPENED, CLOSED, AND DISCUSSED.............................. 33
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LIST O F ACRO NYMS USED.......................................... 34 l
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Report Details 1. Ooorations
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Conduct of Operations 01.1 General Observations a.
Insoection Scope (71707)
The inspectors observed numerous routine operator activities, as well as their i
responses to plant problems and implementation of technical specification (TS)
action requirements, l
b.
Observations and Findinas i
On January 27,1998, a non-licensed equipment operator identified an increasing temperature trend on the "A" reactor water cleanup (RWCU) pump seal cavity. The
"A" RWCU pump seal cavity temperature had risen 34 degrees Fahrenheit in about I
three weeks. The equipment operator appropriately documented the condition in an action request and made an entry on the Hope Creek operations shift turnover sheet. The engineering staff provided a maximum seal temperature limit above which the "A" RWCU pump should be removed from service. Operators closely
monitored the pump seal cavity temperature as it continued to degrade, and removed it from service on February 10,1998 to conduct on-line maintenance repairs.
On February 9,1998, the inspectors observed the performance of a quarterly high pressure coolant injection (HPCI) pump surveillance test. The inspectors focused on the coordination of the evolution and the operations conducted in the main control room. The inspectors determined that the control room supervisor was very knowledgeable and prepared for the evolution. The control room operators closely coordinated their respective activities. One control room operator not directly operating the HPCI system was aware and attentive to the effects on other plant systems while the HPCI system was operating. The inspectors noted that the control room operators adhered to all applicable operations department standards.
On February 13,1998, the Hope Creek planning department discovered that HPCI steam line differential pressure sensor calibrations were not performed within the allowed TS surveillance interval due to a scheduling error. Specifically, these calibrations were inadvertently removed from the TS surveillance scheduling matrix as part of TS Amendment 85 implementation. This amendment only authorized removal of instrument time response tests from the TS. The noted calibrations should have been performed every 18-months, but because of the error were not completed for 23 months, which exceeded the 25% grace period per TS 4.0.2.
This error resulted in a violation of TS 4.3.2.1.
l Once informed of this issue, operators appropriately declared the affected isolation actuation instrumentation inoperable and reviewed TS 4.0.3, which under certain circumstances allows for up to a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> delay in implementing TS action
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I requirements, for applicability. However, an appropriate review of the TS bases indicated that the TS 4.0.3 delay could not be implemented in this case, and the HPCI system was removed from standby service. The operators thoroughly reviewed the applicable TS for the overdue HPCI steam line sensor calibration and promptly completed action statement requirements. Additionally, planning department personnel conducted a thorough " extent of condition" review and did not identify any other missed surveillences. The TS matrix and scheduling codes were also revised. This licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement
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Policy. (NCV 50-354/98-01-01)
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Conclusions Hope Creek operators exhibited good control over routine activities. The operators were sensitive to adverse equipment conditions and initiated additional equipment monitoring when necessary. Control room operators effectively implemented technical specification action requirements.
O2 Operational Status of Facilities and Equipment QL1 General Plant Housekeenina j
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Igoection Scope (71707,71750)
The inspectors conducted frequent tours of the Hope Creek facility to evaluate the effectiveness of station housekeeping and transient load control, b.
Observations and Findinas Storage of temporary equipment and materialin the reactor building was minimized and in all cases items were properly secured. Contamination control boundaries
were properly posted and conspicuous. High radiation area doors were locked and i
posted in accordance with PSE&G's radiation protection program. With one exception, the inspectors noted improvements in cleanliness in the radiation protection department storage areas of the service /radwaste building. This exception involved the storage of twelve barrels of radioactive " sludge" removed from the reactor building sumps in 1995. Though this storage area was properly posted and controlled, general area lighting was poor, and rain water leaks from outside the building had accumulated on the floor inside the posted area. Upon
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questioning, radiation protection personnel indicated that no definitive plan had been established to dispose of the radioactive waste material.
A notable decline in housekeeping was observed in both the service water intake structure (SWIS) and the turbine building. Regarding the SWIS, several water leaks were evident, in large part from service water pump packing gland leakage, which were not well contained or directed to area sumps. Operators continued to track degraded conditions with the building's watertight doors, which are required to be operable per technical specification 3.7.3 (Flood Protection). As for the turbine
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building, the inspectors noted leaks from a reactor feedwater pump which were not
well contr'7ed or directed to the nearby floor drain. Numerous unrestrained items,
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including used pump and valva parts, lubricating oil barrels, and filter media, were l
observed in the Unit 1/ Unit 2 common areas for the duration of the report period.
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Conclusions Station housekeeping and transient load control were generally adequate but had declined during recent months.
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Operator Knowledge and Performance 04.1 Standbv Liauid Control System Storaae Tank Chemistry Control a.
Inspection Scope (71707,71750)
l The inspectors reviewed two incidents involving sodium pentaborate chemistry control in the standby liquid control (SLC) system storage tank.
b.
Observations and Findinas On January 12,1998, the inspectors were informed of a discrepancy in the results of a routine SLC tank boron sample analysis, which had the potential to cause the i
SLC system to be inoperable. The tank sample had been " split," allowing an independent analysis by both the Hope Creek and Salem chemistry laboratories.
l However, the resultant analyses differed by 1.7 weight percent, a difference greater
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than could be explained by analytical uncertainty. The Hope Creek analysis was
- consistent with previous tank sample results, while the Salem analysis was well below the technical specification (TS) allowable limit for boron concentration.
Chemistry technicians re-sampled the tank and submitted a sample to an off-site certified independent laboratory for analysis.
j Based on PSE&G's subsequent investigation, and the results of the independent analysis, chemistry technicians identified two causal factors for the difference between the original split samples. Specifically, the Salem analysis was performed assuming the sample was boric acid (rather than sodium pentaborate), which rendered the results inaccurate. This error was due in part to insufficient communications between the Salem and Hope Creek chemistry departments.
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Additionally, the Hope Creek analytical method was inconsistent with industry standards, though this latter discrepancy had only a minimal effect on the final result. However, Hope Creek technicians revised their analytical procedure to conform with the industry standard analysis technique. The inspectors noted that quality assurance (QA) department personnel were closely involved in the resolution of this issua.
Following the next monthly SLC tank sample analysis in February 1998, chemistry technicians elected to perform a chemical addition to restore boron concentration to the middle of the TS-required band. On February 4,1998, the chemical addition
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was made. This addition should be performed by adding equal measured amounts of borax and boric acid. However, the post-addition sample analysis yielded essentially the same result as the pre-addition analysis, indicating that an error was made either during the chemical addition, the sampling process, or the sample analysis. A re-sample validated the initiallower than expected results. Control room operators were promptly notified of the concern, and an investigation was initiated.
PSE&G technicians quickly determined that they had improperly performed the chemical addition in that only boric acid was used. This resulted from storage of a pre-measured amount of boric acid in a bulk borax chemical container, and the fact that the two chemicals look virtually the same. As a result, the technicians, monitored by a supervisor, added two equal amounts of boric acid to the tank, contrary to SLC tank chemical addition procedure HC.CH-AD.BH-OOO1(Q) Revision j
13. The inspectors determined that this was a violation in that technicians failed to properly implement a procedure required by TS 6.8.1. Upon recognition of this error, the chemistry technicians promptly performed visual inspections of the tank
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internals and SLC pump suction lines to verify that no boron precipitation or
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crystallization had occurred (which could adversely affect system operation. Tank
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bottom samples were also collected and analyzed. Additionally, an appropriate chemical addition was made to restore the tank contents to the desired chemical concentration.
The inspectors noted that the SLC system remained operable during the entire incident. PSE&G's investigation into this issue determined that poor chemical control and inadequate attention to detail were primary event causal factors.
Additionally, supervisory oversight of the original chemical addition was ineffective.
Corrective actions included a procedure revision to assure proper chemicals are used, individual counseling, department training, and reinforcement of expectations with regard to chemical control and attention to detail. As a result of these recent issues, the operations department manager (to whom the chemistry department reports) requested a special QA department assessment of chemistry activities. In a conversetton with the QA manager, the inspectors verified that this special assessment was planned for completion in March 1998. This licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-354/98-01-02)
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Conclusions Two unrelated incidents involving control of standby liquid control system storage tank boron concentration resulted from weak communications, insufficient attention to detail, and ineffective supervisory oversight. Once identified, management response to the issues was prompt and thorough.
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04.2 Electrohydraulic Control System Oscillations I
a.
Insoection Scone (71707)
-The inspectors observed the control room operators respond te an electrohydraulic control (EHC) system pressure regulator failure. The inspectors also reviewed PSE&G's operability assessment of the EHC pressure regulator degraded condition.
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Observations and Findinas i
On January 3,1998, during a control room panel walkdown, operators noticed slight oscillations on chart recorders for main generator megawatts, main turbine l
first stage pressure, and main turbine control valve (TCV) position. The operators
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verified that the EHC system was operating properly, but they could not determine
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the cause of the oscillations. On February 10,1998, a similar transient was
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observed by the control room operators. In this case, the oscillations persisted for r
about three minutes and the No. 4 TCV cycled between 15% and 40% open. _The oscillations subsided without any operator action. Operators questioned the
functionality of the No. 4 TCV, and reduced reactor power below 87% which ensures that the No. 4 TCV remains closed.
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The engineering staff promptly developed a troubleshooting plan which initially focused on identifying problems with that portion of the EHC system associated with the No. 4 TCV. On February 11,1998, before troubleshooting began, EHC i
oscillations recurred, this time affecting the remaining three TCV's. The inspectors
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observed the control room operators discover the oscillations on this occasion, and noted that their response to the transient was prompt, safe and appropriate.
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l Following the February 11,1998 event, the troubleshooting plan was revised to -
consider those portions of the EHC system which could affect the operation of any TCV or bypass valve. Engineering used data collected in a transient analysis
recording system computer to evaluate possible EHC circuit failures. PSE&G determined that the most likely cause of the EHC system anomalies was a signal filter card failure in the "A" EHC pressure regulator circuit. Engineering, in close
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coordination with operations, determined that safe plant operation could be L
continued with the "B" EHC pressure regulator placed in service, and the "A" EHC pressure regulator adjusted as a backup.. The inspectors considered this course of I
action to be consistent with the licensing basis and system operating procedures.
Following these activities, the inspectors questioned why operators did not employ their administrative procedure HC.OP-AP.ZZ-0108(O), " Operability Assessment and Equipment Control Program," to assess the operability of the EHC system and potential impact on the turbine bypass valves given the degraded condition. The inspectors also questioned the scope of this procedure in that it appeared only to address some of the structures, systems and components that affect Hope Creek's design and licensing basis. The operations manager agreed that scope of the operability assessment procedure was perhaps too narrow. However, he did not agree that the condition of the "A" EHC pressure regulator required a formal r
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operability determination, in part because he was confident that engineering personnel had analyzed the condition sufficiently to insure that the design basis was still maintained.
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Conclusions i
Operating crew performance during electrohydraulic control system oscillations was appropriate and safe. Each event was promptly identified and notifications were made within the Hope Creek organization to ensure that problems were addressed.
Engineering and operations department personnel worked closely to identify the cause of the failures and to determine an action plan foi continued safe plant operation. However, operators did not formally assess the degraded condition in an operability determination.
Ou.slity Assurance in Operations 07.1 Nuclear Review Board Activities a.
Insoection Scope (71707.40500)
The inspectors attended an offsite Nuclear Review Board (NRB) meeting on February 4,1998, during which station managers presented departmental performance summaries and fielded questions from board members. NRB members also presented their independent assessments resulting from various programmatic reviews. Additionally, minutes from previous meetings as well as NRB action items and associated management responses were reviewed.
b.
Observations and Findinas Throughout the meeting, NRB members frequently challenged individual presenters regarding their knowledge of various issues and the adequacy of proposed corrective actions. For example, NRB members questioned why the Hope Creek
" Conduct of Operations" procedure had not yet been updated to account for recent lessons learned and management expectations stemming from the November 11, 1997 control rod withdrawal / reactivity management event. Also, based on a review of recent refueling outage events, NRB members expressed a concern that maintenance and surveillance procedures were not of sufficient quality or detail to ensure consistent and reliable results during implementation.
The inspectors noted that NRB members performed thorough reviews and assessments of recent licensee event reports, violation responses, and quality assurance audit findings. These reviews were clearly aimed at identifying declining performance trends, and provided good insight into overall station performance and areas for increased management attention. Configuration control, interdepartmental communications, trending of low level issues, and work planning and scheduling i
were judged by the NRB to be areas requiring additional effort.
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I The inspectors determined that NRB members were well prepared for the meeting. A formal j
agenda was issued prior to the meeting. Meeting minutes were sufficiently detailed and
concise, and NRB action items were clearly articulated. Follow up activities were l
appropnately tracked and resolved.
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Conclusions l
PSE&G's Nuclear Review Board completed a quality overall review of station I
activities, and provided good, objective performance feedback to station
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management.
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Miscellaneous Operations issues
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08.1 NRC Postina Requirements The inspectors reviewed PSE&G's postings to demonstrate compliance with 10 CFR 19.11, " Posting of Notices to Workers," and 10 CFR 21.6, " Posting Requirements."
l PSE&G procedure NC.LR-AS.ZZ-OO16(Z)," Posting Requirements," establishes the method for conformance with WRC requirements. This procedure defines specific locations, posting requiremere, and controls for periodically reviewing the adequacy of the posted material. The inspectors determined that PSE&G was in l
conformance with NRC posting requirements at their procedurally-defined locations.
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However, the inspectors discovered other locations where postings were out of date, not complete, or obscured. The inspectors discussed these latter posting locations with the Hope Creek licensing manager. The licensing manager confirmed that these posting locations were unnecessary and initiated an action request (980217190)to remove the old material.
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11. Maintenance j -
M1 Conduct of Maintenance l
M1.1 - Technical Specification Surveillance Testina Proaram l
a.
Insoection Scope (61726)
r The inspectors reviewed PSE&G management's review and response to an apparent increase in the number of missed technical specification (TS) surveillance requirements, b.
Observations and Findinas During the report period, the inspectors noted an increase in the number of missed TS surveillance requirements. All of these individualinstances were self-identified and either were or were planned to be reported in accordance with 10 CFR 50.73.
The inspectors further observed that for each missed surveit!ance, the root causes were different. Some of these events, including associated licensee event reports,
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were reviewed and closed during this inspection period as non-cited violations (see sections 01.1, M8.1, and M8.2), in recognition of the fact that they were self-identified and corrected, and were not repeat in nature.
Notwithstanding the individual event assessments, the inspectors questioned the
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overall effectiveness of implementing the TS surveillance program in light of the l
relatively high number of recently identified issues. Additionally, the inspectors questioned whether internal PSE&G reviews had detected the adverse trend in performance, and whether any corrective actions had been initiated to reverse the trend. The inspectors met with management representatives from the licensing, planning and scheduling, and operations departments to discuss these issues. The PSE&G managers agreed with the inspectors' observations, and stated that corrective actions to date had for the most part been limited to addressing the specifically identified event root causes rather than potentially broader programmatic weaknesses. PSE&G management attributed the recent high number of self-identified TS surveillance-related issues to improved work week management controls and refueling outage preparations.
Just after the conclusion of the report period, in part the result of inspector questioning, the inspectors learned that PSE&G management initiated a dedicated, independent team review of recent TS surveillance-related issues at both Salem and Hope Creek stations. The team's charter was to focus on the broader programmatic implications of these individual issues and to recommend corrective actions to minimize the likelihood of future incidents.
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Conclusions PSE&G management was slow to recogni:c sn apparent declining trend with respect to technical specification surveillance program implementation. Upon recognition, a focused team review was initiated in an effort to fully understand the issue and to develop actions to improvement future performance.
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M2 Maintenance and Material Condition of Facilities and Equipment i
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M2.1
"D" Emeroencv Diesel Generator On-Line Maintenance
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a.
Inspection Scoos (62707)
The inspectors reviewed the planning and implementation of an on-line maintenance outage for the "D" emergency diesel generator (EDG). A design change package installed during the outage to replace Class 1E relays in the diesel control circuits was also assessed.
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Observations and Findinas On February 2,1998, the "D" EDG was removed from standby service and declared inoperable for a scheduled five day maintenance outage. The inspectors reviewed the on-line maintenance plan and noted that it accurately described the scope of l
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work to be performed, provided a " net safety gain" analysis which justified performance of the work on-line, and assessed the impact on 10 CFR 50.65 performance monitoring. Additionally, the risk impact of performing this work was collectively evaluated with the knowledge of other plant equipment scheduled for work at the time the EDG was to be unavailable. Contingency actions were established for potential emergent concerns.
Because the scheduled outage duration exceeded 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, the inspectors questioned whether station operators were aware of technical specification (TS) 3.8.1.1 bases assumptions regarding extended EDG unavailabilities. These l
assumptions were included in the TS bases as part of a licensing commitment in TS Amendment 75 which granted allowed outage time extensions. Additionally, a Notice of Deviation was issued in NRC Inspection Report 50-354/97-01 for failing to include these assumptions in the TS bases as originally committed. Upon questioning, on-shift operators were unaware of these assumptions. Additionally, i
the LCO maintenance plan did not explicitly account for these stipulations to ensure j
they would be properly addressed. The inspectors determined that all of the assumptions were satisfied in spite the lack of a deliberate review by PSE&G.
The inspectors verified that the operations department TS action statement tracking log accurately reflected the status of the "D" EDG as well as other inoperable or degraded plant systems. Further, the inspectore observed that TS 3.8.1.1 required actions were properly implemented while the "D" EDG was inoperable. However, later in tha weak, on February 4,1998, operators self-identified that the TS 3.8.1.1 action requirement to verify the availability of offsite power sources was not performed within the required eight hour surveillance interval, despite a PSE&G management directive to complete this activity on a six hour basis. This requirement was identified and completed within the 25% grace period extension permitted by TS 4.0.2, but highlighted a continuing weakness in the effective implementation of TS surveillance requirements. Hope Creek received a Non-Cited Violation in NRC Inspection Report 50-354/97-04for failing to complete this exact same TS surveillance within the mandated time. PSE&G attributed this recent
"near miss" event to individual human error.
The inspectors observed several of the work activities associated with the EDG outage and verified that appropriate procedures and work orders were in use.
Maintenance supervisors and system engineering personnel were frequently observed at the work sites. The inspectors witnessed an EDG post-maintenance test run on February 6,1998 from the local engine control panel and noted good in-field oversight by the operations shift supervisor. Three-way communications, procedure usage, and peer checking were evident. A good questioning attitude was exhibited when unexpected or unfamiliar indications were noted. During the re-tests, a minor jacket water leak was discovered on an un-worked portion of the machine. PSE&G management elected to extend the EDG outaae by an additional two days to repair the leak and minimize future challenges to EDG operability.
Part of the scope of EDG outage was to install upgraded design Class 1E relays in the control logic circuits. The inspectors reviewed the implementation of this i
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modification to determine whether lessons learned from installation of this change
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made earlier on redundant EDGs had been incorporated. Based on discussions with
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maintenance technicians and engineers, as well as a review of the design change l
package documentation, the inspectors determined that previously experienced problems were averted. Additionally, only three minor administrative package changes were needed to complete the work successfully.
l c.
Conclut 2ng i
l An on-line maintenance outage of the "D" emergency diesel generator was appropriately planned and implemented. A quantitative risk assessment adequately justified that the outage resulted in a net safety benefit. Good maintenance, l
engineering, and operations department oversight of the work and test activities l-was evident. A Class 1E relay design change effectively incorporated lessons learned from previous implementation on other diesels. Weaknesses were l,
demonstrated in knowledge of associated TS bases information and implementation l
of TS-required surveillance activities.
I M7 Quality Assurance in iWiaintenance Activities M7.1 Poor Maintenance Work Practices Durina RFO7
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j a.
Inspection Scope (627071 l
l The inspectors reviewed PSE&G management's " common cause analysis" report i
generated to evaluate maintenance work performance during the recently completed j
refueling outage, and discussed the findings with maintenance department
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management. Additionally, on January 14,1998, the inspectors attended a l
management meeting held in the NRC regional office to discuss these and other issues.
I b.
Observations and Findinas
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On January 8,1998, partly in response to issues raised by NRC inspectors, PSE&G initiated a " significance level 1" root cause assessment to evaluate the apparently
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poor maintenance department performance during the refueling outage. The j
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inspectors reviewed the final assessment, which was completed on February 4, i
l 1998. This detailed report concluded that though several examples of poor l
performance were documented, the overall number of issues was not abnormally l
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L high compared to historical outage work periods. However, the evaluation also
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determined that PSE&G workers made more than twice the number of errors than did contract employees. The report found that inattention to detail, procedure non-
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L compliance, and ineffective supervisory oversight wers the primary causal factors in I
the examples of poor work performance. The dominant factor inf.luencing poor l
performance was the " absence of an adequately sir.d supervisory staff to
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compensate for the increased outage work force.".ais impacted the ability of
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PSE&G maintenance supervisors to provide effective and consistent oversight of in-i progress work.
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Several corrective actions were developed as a result of PSE&G's assessment, which appropriately focused on addressing the primary causes. For example, maintenance department management was assigned an action to develop a plan to ensure that an appropriate supervisor-to-worker ratio was maintained during outage periods. Additional actions were aimed at reinforcing the use of the "stop, think, act, and review" principle during work activities and clarifying management expectations with respect to oversight of contract maintenance workers.
c.
Conclusions in part because of inspector questioning, maintenance department management initiated an assessment of poor work performance during the recently completed refueling outage. PSE&G completed a high quality and thorough review, and developed several corrective actions which appropriately focused on the stated root causes.
M8 Miscellaneous Maintenance issues M81 (Closed) LER 50-354/97-33: technical specification prohibited condition - failure to perform secondary containment isolation actuation instrumentation channel checks.
The inspectors performed an on-site review the subject licensee event report (LER),
which documented two self-identified violations of technical specification (TS)
surveillance requirements which occurred during refueling outage number seven.
The first example involved a discovery by operations personnel that the special test requirement TS 3.10.8 requirement to perform channel checks on the " reactor vessel water level - low low" and "high drywell pressure" trip functions for the secondary containment isolation actuation system were not performed prior to and during reactor vessel hydrostatic test conditions. This issue resulted in part from the use of an operations department log procedure (HC.OP-DL.ZZ-0026) which failed to reference the appropriate operational conditions to ensure that the noted instrumentation would be verified operable. This procedure is utilized by operations personnel as operational condition specific guidance to ensure that routine surveillance are properly completed. Additionally, operators failed to perform an adequate review of TS 3.10.8 required surveillance status prior to performing the reactor coolant system hydrostatic test.
The second example also involved a failure to perform a " conditional" TS requirement to conduct channel checks on the " reactor vessel water level - low low" instrumentation. In this case, instrumentation TS 3.3.2 mandates that this surveillance be performed when handling irradiated fuel in the secondary containment, during core alterations, and during operations with the potential to drain the reactor vessel. Again, the above noted operations department procedure l
failed to reference the appropriate operational conditions for performing this required I
surveillance. This second example was also self-identified during the follow up investigation for the first noted example.
The inspectors discussed these issues with cognizant PSE&G personnel and reviewed the corrective action program documentation associated with events, l
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including the root cause analyses and corrective actions. The inspectors verified that the required surveillance tests were promptly and satisfactorily completed after discovery of these issues which verified past operability of the required instrumentation. Corrective actions initiated or completed appropriately addressed the causal factors. The LER accurately described the noted circumstances and follow up activities. Additionally, the report was issued within thirty days of issue discovery as required.
The inspectors questioned why the technical specification surveillance improvement program (TSSIP), completed in December 1996, failed to identify the inadequacies-in the operations department log procedure. Based on discussions with PSE&G management and licensing personnel, the inspectors learned that the TSSIP did not verify the adequacy of lower-tier implementing procedures such as the noted operations procedure as part of its review. These licensee-identified and corrected violations are being treated as Non-Cited Violations, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-354/98-01-03,NCV 50-354/98-01-04)
M8.2 (Closed) LER 50-354/97-34: operation in a technical specification (TS) prohibited condition due to both subsystems of main steam isolation valve sealing system j
(MSIVSS) inoperable. On December 26,1997, PSE&G discovered that a TS l
surveillance requirement for inservice testing of ASME Code Class 1,2, and 3 -
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components was not performed within its specified surveillance interval for portions of the "D" emergency diesel generator (EDG) air start system. This was a violation of TS 4.0.5. Operators declared the "D" EDG, which is the emergency power source for the "B" primary containment instrument gas (PCIG) compressor, inoperable at 2:25p.m., on December 26,1997. At that time, the "A" PClG compressor was already inoperable due to planned maintenance. With both PCIG I
compressors inoperable, operators considered both PClG-supported MSIVSS's I
inoperable, which required an entry into TS 3.0.3.
j The inspectors verified by onsite inspection that PSE&G had corrected the self-identified scheduling errors that led to this specific overdue inservice testing
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requirement. When questioned, PSE&G also determined that Hope Creek had l
previously exceeded the same surveillance interval requirement for the "A" EDG air
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start system excess flow check valves. The licensee intended to report this latter issue to the NRC as a supplement to this LER. The inspectors determined that PSE&G's corrective actions for this issue were adequate. This licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-354/98-01-05)
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111. Enaineerina E2 Engineering Support of Facilities and Equipment E2d Filtration, Recirculation, and Ventilation System Troubleshooting a.
Inspection Scooe (62707,37551)
The inspectors observed troubleshooting efforts to resolve a repeat condition involving the "F" filtration, recirculation, and ventilation system (FRVS) recirculation unit.
b.
Observations and Findinas On January 2,1998, the "F" FRVS recirculation unit tripped on a low flow condition during a technical specification (TS) required monthly surveillance test. Operators properly declared the unit inoperable and tracked its status in accordance with operations department procedures. PSE&G personnel immediately recognized that a similar surveillance test failure had occurred on this unit less than one month prior,'
on December 13,1997. The inspectors reviewed the condition report issued
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following that earlier event, including the associated root cause evaluation and i
proposed corrective actions. The inspectors noted that troubleshooting following this earlier event was inconclusive, i.e. no deficient conditions were identified.
After extended uneventful test operation, the FRVS unit was declared operable on l
December 17,1997. PSE&G concirded that the problem was intermittent and
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documented the occurrence for trending purposes.
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i Following the subsequent January 2,1998 event, a more exhaustive I
troubleshooting effort was completed. During this effort, the "F" FRVS unit
maintenance work history was evaluated. PSE&G determined that this recirculation unit had experienced six " low flow" trips over the past ten years of Hope Creek operation, three of which occurred within the past seven months. The inspectors l
reviewed the condition report evaluation of a May 30,1997 low flow trip identified during this historical review. Again, no specific cause for the recirculation unit trip was identified and no further action was taken following this earlier occurrence.
Troubleshooting following the most recent event was systematic and thorough, and
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resulted in the identification of three degraded conditions within the FRVS unit control circuitry. These included a loose service module conraction, a nicked wire, and a faulty relay. The unit was declared operable after all three of these cond;tions were repaired and the unit completed a successful test run. Additionally, the next monthly surveillance test in February 1998 was directly witnessed by maintenance department supervisors and was completed without incident. The associated condition report evaluation was comprehensive and provided an appropriate extent-of-condition analyses, historical trends, and corrective actions.
The inspectors determined that, until January 2,1998, previous indications of intermittent failures associated with the "F" FRVS recirculation unit were not
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sufficiently tracked, trended, or corrected to prevent additional future surveillance test failures. Specifically, at least two condition report evaluations following earlier low flow trip events did not explore the previous maintenance work history on the unit, and troubleshooting efforts lacked the detail necessary to identify and resolve the problam's root causes. As such, the inspectors concluded that this was a violation of 10 CFR 50 Appendix B, Criterion XVI (Correctivo Action) in that corrective actions for this condition adverse to quality were neither promptly implemented nor sufficient to prevent repetition. However, these issues were not evident until PSE&G's thorough review efforts following the January 2,1998 FRVS unit failure. These efforts were extremely thorough and were indicative of recently improved management focus with respect to troubleshooting activities. The root cause evaluation was of good quality, and the FRVS unit was promptly and properly restored to an operable status. As such, this licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-354/98-01-06)
c.
Conclusions Several earlier opportunities to identify and correct causal factors associated with intermittent failures of the "F" filtration, recirculation, and ventilation system unit were missed, increasing the overall unavailability time of the unit. However, PSE&G's efforts following a recent surveillance test failure of this unit were of excellent quality, and reflected a renewed management focus on the conduct of troubleshooting activities.
E22 Safety Svsom Performance Monitorina a.
Insoection Scope (62707. 37551)
The inspectors performed an independent review of reliability and unavailability data for the Hope Creek radiation monitoring system (RMS), required by 10 CFR 50.65 (maintenance rule). Additionally, cognizant system engineering and speciality engineering staff were interviewed to determine the extent of their knowledge
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regarding this system. Lastly, the inspectors attended an " expert panel" meeting to assess whether chartered responsibilities were being met.
l b.
Observations and Findinas
The inspectors reviewed RMS performance data accumulated during the past year of Hope Creek operation. The inspectors questioned why PSE&G had not included i
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all portions of the RMS within the scope of the maintenance rule. Specifically, the liquid radioactive waste (LRW) and the cooling tower blowdown (CTB) radiation monitors, both required by technical specifications, were not "in scope." Based upon a review of the noted regulation, PSE&G's documented process for implementing this regulation, and interviews with cognizant engineering personnel,
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the inspectors found that PSE&G's determination not to include these subsystems within the scope of the rule was appropriate. The primary basis for reaching this conclusion was that the functions provided by these systems are not safety-related,
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do not mitigate the consequences of an accident, and are not used in emergency operating procedures. All of the other RMS subsystems were included within the scope of the rule.
The inspectors reviewed a condition report (970918304) initiated on September 18, 1997 which stated that RMS performance criteria for unavailability had been exceeded, requiring a root cause evaluation and the establishment of RMS-specific performance goals in accordance with section a(1) of the maintenance rule. The evaluation resulting from this report determined that the data used to establish total system unavailability time was inaccurate. For example, unavailability times for the not-in-scope LRW and CTB RMS subsystems were inappropriately included the total accumulated time data. Additionally, calculated system unavailability times were sometimes inaccurate due to mis-interpretations of control room narrative logs. The inspectors noted that a separate action request was generated to address these issues. When the data re-validation effort was complete, PSE&G engineers determined that RMS performance criteria had in fact not been exceeded.
The inspectors noted that the radiation protection (RP) department maintained a separate performance indicator for RMS. While use of this indicator demonstrated an internal RP department desire to maintain scrutiny on RMS performance, the inspectors determined that there was no correlation between the performance goals utilized in the RP department indicator and the criteria established to demonstrate compliance with 10 CFR 50.65.
A review of the RP RMS performance indicator highlighted recent equipment deficiencies associated with the LRW and CTB radiation monitors. This issue was validated during a discussion with the cognizant system manager. The inspectors I
verified that action requests and work orders had been generated to ensure that these noted deficiencies were addressed.
Lastly, the inspectors attended a maintenance rule " expert panel" meeting to -
evaluate whether this panel satisfied its chartered intent. Minutes of the meeting l
were recorded, and appropriate representatives from eaca required Hope Creek department were present, including operations, maintenance, engineering, and risk i
assessment. The system manager's presentation was thorough and well supported.
The panel's review was sufficiently independent and consistent with PSE&G's program requirements.
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C.
Conclusions PSE&G engineering personnel properly monitored the performance of the radiation monitoring system at Hope Creek. Appropriate root cause evaluations and corrective actions were either proposed or initiated for identified problems. An.
expert panel meeting review was thorough and satisfied its chartered requirements.
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R3 Core Flow Miscalculation Durina Operatina Cvele Seven a.
Inspection Scooe (37551)
The inspectors reviewed an engineering evaluation which supported the rationale for retracting a 10 CFR 50.72 event notification made on January 15,1998.
b.
Observations and Findinas Hope Creek reactor engineers perform procedure HC.RE-RA.BB-OOO2(O)," Core Flow Determination," near the beginning of each operating cycle to maintain the accuracy of core flow instrumentation and to determine actual drive flow from the reactor recirculation loops. The drive flow is an input to the average power range monitoring (APRM) system to determine flow-biased scram setpoints. On January 15,1998, a reactor engineer discovered non-consecutive errors in the calculations and APRM gain adjustments during the previous operating cycle. PSE&G, considering the inaccurate flow bias to the APRM system, initially declared all six channels of the APRM system inoperable. A non-emergency event notification was made to the NRC on January 15,1998. PSE&G took prompt action to restore the recirculation flow units to conservative values and subsequently adjusted the APRM flow-biased scram setpoints according to TS requirements.
.The PSE&G reactor engineer discovered the earlier calculation error while reviewing the previous performance of core flow determination prior to the upcoming activity.
The error resulted when reactor engineers inadvertently input data from the double-tapped jet pump instruments as opposed to the single-tapped jet pump instruments into a calibration equation. The inspectors determined that this was a violation of TS 6.8.1.a in that the governing procedure noted above was not properly implemented or adequately reviewed. As a result, the core flow instruments were calibrated with incorrect gain adjustments on April 13,1996. The core flow instruments were successfully re-calibrated on January 23,1998, after PSE&G fully understood the cause(s) of the errors introduced in April 1996.
l On January 27,1998, PSE&G determined that, even with the error introduced in April 1996, the APRM's had never operated outside of the TS-required limiting safety settings. As such, PSE&G retracted the January 15,199810 CFR 50.72
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event notification.
l Engineering also considered all other plant systems and equipment effected by the l
core flow miscalculation during their follow up review. No other system operated I
outside its design basis as result of this issue. However, the core flow error from
operating cycle seven introduced an error that potentially affected the fuel load l
behavior for operating cycle eight. PSE&G engineers contacted the fuel vendor to more fully understand the potential impact.
i PSE&G management disciplined the individuals involved with original calculation error in accordance with station policy. Additionally, PSE&G initiated a corrective
action item to evaluate and improve the quality of the core flow calculation i
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procedure. The inspect < s found these corrective actions and future plans to be adequate. This licensu ;-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy.
(NCV 50-354/98-01-07)
c.
Conclusions Upon discovery, engineering department personnel conducted a thorough and accurate analysis of the impact of a core flow miscalculation completed in operating cycle seven. Corrective actions were timely and appropriate.
l E2 4 Residual Heat Removal System in leakaae i
a.
Inspection Scope (37551)
l The inspectors reviewed engineering department support to eliminate or reduce reactor coolant system in-leakage to the residual heat removal (RHR) shutdown cooling system.
b.
Observations and Findinas Since the Hope Creek startup from refueling outage seven, the RHR shutdown I
cooling (SDC) suction line has experienced elevated pressure conditions due to seat leakage past the reactor vessel pressure isolation valves. The SDC piping design pressure rating is significantly lower than the reactor coolant system and it is isolated from the reactor vessel during a plant startup, well before the reactor vessel reaches normal operating pressure. Control room operators are alerted to an
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abnormally high pressure condition in the SDC system when a pressure switch i
activates an annunciator in the control room.
The inspectors, through a review of control room logs, noticed that plant operators promptly cleared the high pressure condition each time it occurred. The inspectors also determined that operators quantified the leakage at least twice per day to ensure that it does not exceed technical specification (TS) identified leakage requirements. Because this elevated pressure condition occurred on a frequent basis (as often as every 45 minutes), equipment operators received additional radiation exposure when they cleared the high pressure condition and when they l
measured the leakage into the SDC system. These tasks were performed in high l
radiation area.
l Hope Creek system and design engineering personnel were responsive in their
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attempts to eliminate the in-leakage, however they had not been successful by the
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end of the report period. Engineering' personnel were also sensitive to the additional i
radiation exposure being received, and provided an alternative method to clear the
high pressure condition from outside the high radiation area. PSE&G was
I considering other methods to eliminate or reduce the frequency of the elevated
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pressure condition, but had not yet determined whether those methods will be
acceptable for safe plant operation. The inspectors verified that work orders were
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i initiated to inspect the pressure isolation valves during the next refueling outage and I
perform repairs as necessary. The inspectors considered the licensee's actions to date as acceptable.
c.
Conclusions
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The engineering department provided effective support to operations staff in an attempt to minimize frequent elevated pressure conditions in the residual heat removal system shutdown cooling suction piping. Engineering also supported radiation protection technicians by providing a method to minimize the radiation dose received during the course of clearing the elevated pressure condition.
l E2d Enaineered Safety Feature Svstem Review i
a.
Insoection Scope (71707)
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The inspectors performed a detailed walkdown of the filtration, recirculation and ventilation system (FRVS). Design basis documentation was reviewed and system i
engineer interviews were performed during the conduct of this assessment.
I b.
Observations and Findinas The inspectors verified that the FRVS system was properly aligned in a standby I
condition. The inspectors observed extensive use of tape sealant on the FRVS recirculation unit duct work, particularly the ductwork between the FRVS recirculation fans and the filter housings. The inspectors determined that this tape sealant, referred to as "hardcast," was installed as a design change between 1987 and 1988. The design change installed stiffeners on the flow distribution vanes in that portion of the ductwork to prevent vibration-induced cracking of the ductwork.
Hardcast was applied over the stiffeners and at other mechanical joints on the FRVS ductwork. The inspectors reviewed Bechtel Specification 10855-M-735(O)and Hope Creek Generating Station Environmental Design Criteria, D7.5, and determined that hardcast did not affect the operability of FRVS. Further, the use of hardcast was discussed with the FRVS system engineer. In part because the use of hardcast was not explicitly described in the UFSAR, the system engineer initiated an action request to fully evaluate its application on the FRVS recirculation units.
The inspectors did not identify any new equipment deficiencies and verified that previously documented and currently uncorrected deficiencies did not adversely affect the ability of the FRVS system to fulfillits intended safety function.
c.
Conclusions The configuration and material condition of the filtration, recirculation, and ventilation system was adequate.
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E3 Engineering Procedures and Documentation E3.1 Turbine Buildina Batterv Exhaust System Review a.
Inspection Scope (71707,37551. 71750)
During a routine tour of the Hope Creek facility, the inspectors identified a potential unmonitored offsite radioactive release path from the turbine building. The inspectors reviewed applicable design and licensing basis information, walked down the associated ventilation system, and discussed the issue with both cognizant PSE&G engineering and NRC Region I specialist personnel, b.
Observations and Findinas The turbine building battery exhaust ventilation (TBBE) system draws air from an enclosed non-Class 1E 250VDC battery room, located in a radiologically controlled area of the turbine building, and discharges it directly to the environment through unfiltered and unmonitored ductwork. The inspectors questioned the acceptability of this design given the requirements of 10 CFR 50 Appendix A, General Design Criterion (GDC) 60 which mandates that nuclear power plant designs include the
"means to control suitably the release of radioactive materials in gaseous effluents..."
The inspectors observed that the Hope Creek UFSAR does not explicitly describe the acceptability of the TBBE with respect to GDC 60. Additionally, NRC NUREG-1048 (Hope Creek Safety Evaluation Report) is silent regarding this ventilation system. However, based on a review of the system drawing in the UFSAR and the system operating procedure, the inspectors (in conjunction with NRC specialist inspectors) determined that the enclosed battery room ventilation design included a dedicated outside supply air system with an air flow rate identical to the exhaust flow rate. Additionally, these two systems are interlocked to ensure that the room is maintained at outside air pressure. Since the turbine building is maintained at a slightly negative pressure with respect to the outside environment, any leakage from the enclosed room would be into the general turbine building air space, which the inspectors verified is exhausted to the monitored and controlled south plant vent effluent release path.
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The inspectors reviewed the conclusions and recommendations of an independent PSE&G design engineering evaluation, documented in a condition report (971119237),which was initiated after the inspectors first surf aced this issue in November 1997. PSE&G engineers performed a thorough review of this issue, and arrived at a similar conclusion to the inspectors. PSE&G engineers stated that the TBBE design was acceptable given the other design features of the facility.
However, they also initiated minor plant modifications to further enhance the
design and integrity of the TBBE. Specifically, actions were initiated to add foam sealing material to battery room wall penetrations and to install door spring return mechanisms to ensure that the battery room enclosure was positively maintained.
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Conclusions PSE&G design engineering personnel performed a quality design and licensing basis review of the turbine building battery exhaust ventilation system to validate its acceptability with respect to effluent release path requirements. Minor modifications were developed to further enhance the design.
E12 Inservice Testina of Core Sorav Subsystem Pumos and Valves i
a.
Insoection Scope The inspectors reviewed "A" core spray subsystem surveillance procedures for
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pump and valve tests to determine tyhether established acceptance criteria meet i
L technical specification (TS) and applicable design document requirements.
b.
Observations and Findinas i
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Hope Creek personnel use procedure HC.OP-IS.BE-OOO1(Q),"A&C Core Spray l.
Pumps-AP206 and CP206 - In-Service Test," to ensure that both "A" core spray subsystem TS surveillance requirements and ASME Boiler and Pressure Vessel Code Section XI inservice testing requirements are satisfied. The inspectors verified that Hope Creek has established the correct TS surveillance requirements for the core spray subsystem flow rates and discharge pressures. The inspectors also verified i
that the surveillance procedure properly implementsSection XI of the ASME Boiler
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and Pressure Vessel Code for inservice testing (IST) of the core spray pumps.
I Hope Creek personnel use HC.OP-IS.BE-0101(Q)," Core Spray Subsystem "A"
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Valves - Inservice Test," to establish ASME Boiler and Pressure Vessel Code Section i
i XI inservice testing of the "A" core spray subsystem valves. The tests described j
l for "A" and "C" core spray pump minimum flow check valves require the operator l
to listen for an audible sound of the valve disc contacting the seat. However, Hope l
Creek has not qualified the audible sound method as a positive means to verify
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l-valve position in accordance with the Code, nor is any special equipment used to l
measure the audible sound. The inspectors questioned the use of this method to -
l verify valve position, particularly in locations with high background noise. However, i
the inspectors also recognized that the noted surveillance procedure requires valve
. position verification using an external position indicator for the core spray pump minimum flow check valves. This method is acceptable for ASME Section XI l
testing. Upon questioning, the inservice test program manager initiated an action j
. request to eliminate the unqualified procedure requirement to detect an audible sound.
c.
Conclusions Hope Creek properly transcribed technical specification surveillance and ASME Section XI testing requirements for core spray system pumps and valves into implementing procedures. However, the surveillance test procedure for core spray system check valve inservice testing also made use of an unqualified audible sound detection methodology.
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E8 Miscellaneous Engineering issues Egd Service Water System Operational Performance Inspection Follow UD Review a.
jnsoection Scoce (37551. 40500)
The inspectors reviewed the status of action items generated as a result of PSE&G's independently conducted service water system operational performance inspection (SWSOPI), completed in July 1997. Additionally, the inspectors reviewed the PSE&G engineering department response to the SWSOPl final report.
b.
Observations and Findinos PSE&G performed a SWSOPl after an earlier design basis review of the station service water (SSW) and safety auxiliaries cooling system (SACS) was completed, in order to validate the comprehensiveness of that prior effort. During the independent SWSOPI, numerous discrepancies were identified and documented in condition reports in accordance with PSE&G's corrective action program. Over one hundred condition reports were written. The inspectors sampled fifteen of these condition reports to determine whether satisfactory progress had been made in resolving the associated discrepancies.
In general, the actions stemming from the reviewed condition reports were completed as assigned. In addition, most of the condition report action items were independently reviewed after completion by quality assurance (QA) department auditors to verify proper resolution. However, the inspectors identified one notable discrepancy involving the follow up to a SWSOPl question regarding SACS pump auto start cheuit overlap testing. An action request documenting the potentialissue was initiated on July 16,1997, but was rejected because the operations department determined that the issue did not involve a condition adverse to quality as defined by PSE&G's corrective action program. PSE&G records indicated that engineering personnel were to either revise the action request or provide an appropriate response to the SWSOPl team. This activity was not completed until questioned by the inspectors during the review. Based on a review of technical specifications and the UFSAR, the inspectors independently determined that this SWSOPlissue did not result in a degraded condition or the need for a SACS system operability determination, nor was it required to be documented in PSE&G's response to NRC Generic Letter 96-01 regarding logic system functional testing.
The SWSOPl final report also summarized general areas of weakness observed by the independent inspection team. These areas of weakness included configuration and design control,10 CFR 50.59 safety evaluations, NRC Generic Letter 89-13 implementation, and SACS functional testing. On December 1,1997, the PSE&G engineering department issued a memorandum to the QA department (responsible i
l for tracking completion of SWSOPl action items) which provided detailed action plans to address each of the identified general weakness areas. The inspectors reviewed these action plans and determined that appropriate progress had been made in achieving the stated milestones.
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Conclusions in general, resolution of the specific deficiencies identified by the service water
- system operational performance inspection (SWSOPI) has been timely and appropriate. Engineering management response to broad-based conclusions of poor programmatic performance was of good quality in that specific, detailed action plans were developed and implemented to address each of the issues.
ERJ (Closed) VIO 50-354/E97-160-01013: inadequate safety evaluation for residual heat removal (RHR) cross-tie modification. The inspectors performed an on-site review
- of PSE&G's November 18,1997 letter in response to the subject 10 CFR 50.59 violation. In the letter, PSE&G agreed with the cited violation and committed to completing several corrective actions aimed at preventing recurrence of the issue.
The inspectors independently verified that these corrective actions have either been implemented or initiated. Specifically, the noted safety evaluation for the cross-tie modification was revised to meet the standards of the 10 CFR 50.59 regulation.
The Hope Creek TS were revised via Amendment 109 (dated November 6,1997) to include a specific surveillance requirement to verify, on a monthly basis, that the RHR cross-tie valves are closed. A systematic review and validation of the design and licensing basis of Hope Creek safety systems, in response to a 1996 NRC request per 10 CFR 50.54(f), was in progress. Lastly, PSE&G's internal process which implements the requirements of 10 CFR 50.59 was upgraded to include additional peer and supervisory reviews and quality checks.
ERJ (Closed) VIO 50-354/97-01-06: temporary scaffolding not installed or maintained in accordance with established procedures. The inspectors performed an on-site review of PSE&G's letter in response to this violation, dated May 13,1997. PSE&G determined that the causes of the failure to maintain adequate control of scaffolding in safety-related and seismically-qualified areas of the Hope Creek facility were -
several, including: inadequate program development, poor implementation of procedure requirements, insufficient training for scaffold builders, and a lack of program ownership. As a result of these findings, PSE&G initiated several corrective actions, also stated in the noted letter. The inspectors verified that these actions were completed by conducting procedure reviews, personnel interviews, and plant walkdowns. Examples of these actions include:
- centralization of all scaffolding functions under one maintenance sub-organization
- creation of a new scaffolding construction and control program
- focused training for maintenance personnel on proper construction techniques Periodic inspector walkdowns of the facility indicated that PSE&G has adequately implemented the new scaffold construction requirements. Additionally, a review of the scaffold tracking log indicated that the status of active scaffolds were appropriately monitored.
Ejd (Closed) LER 50-354/97-31: engineered safety feature actuation - reactor core isolation cooling (RCIC) system isolation. The inspectors performed an on-site review of this LER, which describes an automatic isolation received during the i
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warm-up of the RCIC system. The RCIC system was being placed in service during a plant startup following Hope Creek's seventh refueling outage. The inspectors verified that instrumentation was in place to determine the cause of these isolations during a system warmup, which was a commitment made in a previous LER (50-354/96-25) describing a RCIC system isolation. PSE&G confirmed that the isolations were due to steam line low pressure conditions resulting from rapid steam condensation as the steaniline is warmed. PSE&G intended to modify the low pressure isolation with a time delay as a design change package. The NRC considered the licensee actions and future plans appropriate.
IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls R 1.1 Radiological Source Term Effects of a Condensate Filter Modification a.
Inspection Scoce (83728)
PSE&G has elected to reduce the concentration of feedwater iron in the condensate system by installation of a full flow prefilter system which was planned for installation during the current Hope Creek operating cycle during 1998. The inspector reviewed the licensee's plans for startup of the system and its expected effects on radiological source term and corrosion of plant systems. This review consisted of in-plant work observations, interviews with licensee personnel, and review of applicable documents, b.
Observations and Findinas PSE&G has not identified what plant components contain cobalt (the most significant contributor to the plant's radiological source term) and, therefore, does not know if cobalt input is upstream or downstream of the condensate profilter.
This may be important as the reactor water has exhibited high cobalt-60 levels as compared to other boiling water reactors. PSE&G believes the high feedwater iron concentrations have bound up the available cobalt-60 and minimized its availability for plating out and, therefore, minimized the radiological source term in the past.
When the condensate prefilter removes the feedwater iron, there may be cobalt-60 available to become integrated into the corrosion film on plant piping systems causing an increase in the radiological source term.
Currently, the iron levels in the condensate /feedwater range from 5 to 8 ppb. The Electric Power Research Institute (EPRI) guidelines recommend 1.0 + /- 0.5 ppb for the condensate feedwater. The prefilter is expected to reduce the iron levels to below 0.1 ppb. PSE&G anticipates three time periods after the prefilters are installed. The first will be the transition period that willlast for several months.
The reactor coolant system and condensate /feedwater system will have a large iron inventory since a large amount of iron is in the system. As the excess iron is consumed, the soluble nickel concentration willincrease to several ppb. The
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second stage will be the iron control period. During this period, iron will be injected into the feedwater after the prefilter at a level of 0.3 to 0.5 ppb so that crud containing high cobalt levels will not be released into the coolant. This period will continue until all of the fuel exposed to the high iron levels has been removed from the core, which is two fuel cycles after start up of the prefilter system. The third stage will be the low iron stage where iron injection will be terminated. This will minimize the fuel crud deposits. Nickel and zine injection may be utilized to minimize dose rates.
The prefilter system consists of four filters comprised of 430 filters that are 70 inches long and 21/4 inches in diameter. The filters will operate at 140* F maximum at a differential pressure of 18 psi. The filters are designed to operate at 200 F and a differential pressure of 30 psi. Three of the filters can handle full flow.
There is also a bypass valve that will operate on increased pressure if two filters are out of service. The filters are expected to last four years before they have to be replaced. The prefilter system has been designed to handle a power uprate.
PSE&G has replaced portions (about 50%) of the extraction steam heater drain lines i
as a result of erosion / corrosion. The lines original lines, made of carbon steel, were replaced with 21/4 chromium steel which has a higher resistance to erosion / corrosion. PSE&G uses EPRI's CHECKWORKS computer program to predict locations where erosion / corrosion is expected. PSE&G also uses engineering judgement to select areas to be monitored for erosion / corrosion. Areas selected by CHECKWORKS and areas selected by engineering judgement or industry experience
were ultrasonically examined on a routine basis. All replacement piping was l
upgraded to 21/4 chromium steel.
The inspectors questioned how the change in coolant chemistry will affect the I
l susceptibility of the core internals to inttrgranular stress corrosion cracking (IGSCC). PSE&G engineers anticipate a decrease in susceptibility since the installation of the prefilters will result in a decreased frequency of backwashing which will result in a decrease in the amount of sulfate in the coolant. Also, the licensee currently controls the hydrogen water chemistry to 21 standard cubic feet i
per minute (SCFM) but plans to increase it to 28 SCFM. This should reduce the
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l susceptibility to IGSCC. Hope Creek is a category B plant in terms of core shroud cracking and 100 percent of the available areas of the core shroud were inspected i
during the last refueling outage. No cracks were found. However, a leak was detected in a reactor vessel core spray nozzle during the last outage. The crack
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initiated in the butt of inconel 182 weld and propagated through the weld. (See i
NRC Inspection Reports 50-354/97-07 and 97-09 for details).
At the end of the inspection period, the condensate filter system design was complete, and the 10 CFR 50.59 safety evaluation were being prepared.
c.
Conclusions The design of a condensate prefilter system at Hope Creek appeared capable of reducing the radiological source term of the plant and of acting to reduce corrosion
cracking.
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HL2 Acolied RP Performance During the inspection period, the licensee provided RP coverage for a reactor water
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cleanup (RWCU) pump seal replacement. The inspector reviewed the RP controls for this work through interviews and documentation examination.
l Radiological precautions were well planned utilizing job history recommendations for
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shielding and ventilation, and notably included headset communications between experienced maintenance and RP personnel. At the completion of the job,572 mrem was expended without any contamination incidents. in general, the radiation work permit (RWP) was very detailed, with RP control instructions specified for each work evolution step.
During egress from the radiologically controlled area (RCA), the inspector's shoes alarmed the personnel contamination monitors at the 137' control point. The monitor alarm indicated the presence of low level contamination. Under RP technician guidance, the inspector was directed to the decontamination room and directed to walk on sticky pads in an attempt to remove the low level contamination. Thic was followed by a successful recount by the personnel
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contamination monitors and a release from the RCA. Procedure HC.RP-TI.ZZ-0201(Q), Revision 10, " Access Control Point Management," specifies that unless otherwise directed by RP supervision, RP control point technicians are required to perform a whole body frisk with an RM-14 frisker prior to decontamination or recount in a personnel contamination monitor. The inspector was not monitored with an RM-14 frisker as required by this procedure. RP department supervision indicated that RP personnel are expected to comply with all procedure requirements and committed to reinforce this expectation at a future staff meeting. The personnel contamination monitors (IPM-9s) have a more sensitive alarm threshold than the RM-14 frisker, therefore, skipping the RM-14 monitor step for a low level shoe contamination was considered to be of minor safety consequence. This failure constitutes a violation of minor significance and is being treated as a Non-Cited Violation, consistent with Section IV of the NRC Enforcement Policy. (NCV 50-354/98-01-08).
R1.3 As Low As is Reasonably Achievable (ALARA) Performance a.
Inspection Scope (83728)
.The inspector reviewed Hope Creek's collective exposure performance for 1997 and conducted plant tcurs of radiological source abnormalities. The inspector conducted independent surveys, interviewed licensee personnel and reviewed pertinent ALARA documents.
b.
Observations and Findinas l
The collective personnel exposures for Hope Creek in 1997 were 352 person-rem versus an annual goal of 270 person-rem, with the seventh refueling outage accruing 308 person-rem compared to a 220 person-rem goal. The originally
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scheduled 55 day outage extended to 94 days as a result of refueling delays,
- emergent work, and startup delays. Implementation of a comprehensive temporary shielding plan for the drywell helped to reduce drywell personnel exposures from l
197 person-rem to 159 person-rem (as estimated by the licensee). The 1998 site collective personnel exposure goal including both Salem units and the Hope Creek Station was 104 person-rem, with Hope Creek accounting for 60 person-rem.
During plant tours, the inspector observed instances of plant source buildup in accessible areas of the plant. One example involved the fuel pool cooling heat exchanger room, located on the reactor building 162 foot-elevation. The room was
designed with a permanent shield wall with two water shield windows for viewing the room equipment components from outside. During this inspection, dose rates on the heat exchanger were higher than design resulting in dose rates of 40 mr/hr on contact with one viewing window,15 mrem /hr on contact with the other window, and 10 mrem /hr on pntact with the wall itself. Both viewing windows were marked with ALARA caution and warning signs due to the elevated dose rates. According to discussions with RP personnel, this has been a chronic problem. The inspector determined that the crud buildup in the subject heat exchanger has become an exposure problem as evidenced by the licensee's ALARA i
warning postings and that this source has not been addressed by the licensee.
PSE&G personnel indicated that this issue was under review by the engineering department to determine a remedy.
Another accessible plant area at the 54 foot-elevation of the reactor building is the reactor building sump. This area had lead blankets placed over the sump and a high radiation barricade placed around this area. During the inspection, sump pump maintenance was required in this area. Due to the accumulation of debris in the sump, removal of the sump pump would require entry into a > 1R/hr area requiring high radiation access control and additional RP planning. A review of job history files indicated that this area had been last cleaned out approximately four years ago.
As a result of the inspector's questions and the current need to perform maintenance in the sump area, removal of the high radiation source (debris) is under evaluation by the licensee.
Located on the 54 foot-elevation of the reactor building is the 'D' RHR room. Inside the RHR equipment room, the cross-tie piping from the 'B' RHR system has developed a 200 mrem /hr hot spot. The licensee has provided temporary shielding materials over the hot spot and has written an Action Report dated February 4, 1998, requesting the subject hot spot to be flushed during the next available system outage window.
c.
Conclusions PSE&G maintained low collective exposures at Hope Creek as compared to other boiling water reactors, however, there were several areas of opportunity for reducing high exposure sources in the plant to maintain the plant in an as low as reasonably achievable condition.
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R1A Internal Exoosure Control a.
IDADAq1 ion Scone (83750)
The inspector reviewed the licensee's internal exposure control performance during the Fall 1997 Hope Creek refueling outage through a review of whole body count-measurements and assessments and respiratory protection usage. Interviews with licensee RP staff were also conducted.
i-b.
Observations and Findinas l
The inspector reviewed the whole body count investigations that would indicate internal exposures for the Fall 1997 Hope Creek outage. Only one individual (.
indicated a measurable internal exposure of approximately 15 mrem. The investigative whole body counts were performed utilizing the sodium-iodide detector whole body counter rather than the higher resolution germanium detector whole body counter. The inspector verified that 10 minute whole body counts in the germanium whole body counter reflected minimum detectable values for all the principal radionuclides found at Hcpe Creek to well within the licensee's 5 DAC-hour tracking level. PSE&G personnel indicated that future investigative counting would utilize the germanium whole body counter to ensure accurate radionuclides.
discrimination and measurement are performed. The inspector verified that 6 DAC-r.
hours were recorded in the licensee's dosimetry database. Such air concentration represents exposure below PSE&G's official reporting level of 50 mrem and below the NRC recording requirement of 10% of an ALI or 500 mrem. The licensee records indicated over 200 full-face respirators were utilized during the Hope Creek outage, c.
Conclusions PSE&G effectively controlled and prevented internal exposures at Hope Creek during i
refueling outage number seven.
B15 External Exoosure Measurement
The inspector reviewed documentation associated with thermoluminescent dosimetry (TLD) processing service performed for PSE&G by Pennsylvania Power and Light (PP&L) Company. The inspector verified that the TLD processor held current National Voluntary Laboratory Accreditation Program (NVLAP) accreditation in radiation categories 1-8. Additionally, the inspector reviewed results of
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independent TLD performance testing conducted during the second quarter of 1997 and reviewed the latest NVLAP onsite inspection assessment that resulted in very minor findings. The inspector concluded that PP&L provided reliable and quality TLD processing services.
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R7 Quality Assurance in RP&C Activities R7.1 RP Proaram Review and Oversicht a.
Inspection Scope (83750)
The inspector reviewed recent results of radiological problem identification and correction, RP staff self-assessments, quality assurance (QA) department RP program surveillance, and the results of radiological services department RP assessments. This review consisted of interviews with licensee personnel and a review of licensee documentation.
b.
Observations and Findinas Radiological Occurrence Reports Radiological Occurrence Reports (RORs) reviewed by the inspector indicated a high volume, low threshold feedback process of recording radiological occurrences in the station. However, many of the RORs reviewed were either not completely investigated or corrective actions did not address the causes identified in the investigations. The station-wide corrective action program that is used for RORs, was an effective process for assigning rnultiple corrective actions and for assigning followup verifications of effectiveness. The inspector determined that the use of this process for RORs has not been entirely successful. Although followup verifications were assigned and completed, many RORs were incompletely investigated or the identified causes were not resolved by corrective actions. For at least one ROR reviewed, corrective actions were taken that were not documented.
Another example involved an ROR generated during the fall 1997 outage when workers required manual electronic dosimeter (ED) setpoint adjustments from a contractor RP technician at the radiologically controlled area access control point.
The setpoints had been manually adjusted, however, the RP technician did not manually sign the workers in on their RWP. This was identified on the ROR as a deficiency in the contractor RP technician training program. No followup on this issue was made. Also, in November 1997, during reactor vessel reassembly, an ED alarm was not audible to the worker and the investigation suspected a faulty ED.
However, the ROR did not address the cause of the condition.
The inspector noted two radiological issues that had been documented in repeat RORs and continued to not be addressed 4 to 6 months later. Although these issues did not represent violations of regulatory requirements, they do indicate a lack of timeliness in resolving chronic RP program issues, in approximately June 1996, PSE&G replaced their Betamax personnel contamination monitors with more sensitive IPM-9 monitors. Due to a detector summation algorithm, the same 5,000 dpm alarm setpoint will cause the IPM-9 monitors to alarm at lower detectable contamination levels than the previous instrumentation. Since June 1996, personnel who periodically alarmed the IPM-9 monitors were found to exhibit less than procedural release limits but were nonetheless decontaminated to lower levels to allow successful passage through the monitor. The licensee indicated that during the Fall 1997 refueling outage there were several " low level" IPM-9 alarms each
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day. After the outage, PSE&G has experienced about 1 or 2 " low level" alarms
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each day. Typically, the affected personnel had only traversed clean areas of the i
RCA. This issue continues to be reviewed by the licensee. The discrepancy between a lower sensitivity of personnel contamination monitors and a higher procedural contamination release limit has not been effectively resolved or addressed in a timely fashion. (See also section R1.2 of this report)
Another issue involved a series of RORs written for workers who exited their work areas with their ED alarming at the high alarm setpoint. The workers indicated that
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they did not hear the low alarm setpoint alarm due to working in a high noise area.
I Over a period of several months, there have been many instances where workers have exceeded the ED alarm setpoint due to insufficient audible alarm volume relative to the ambient noise le' vel at work sites. Although short term corrective action was taken to reaffirm worker accountability to check their ED reading periodically, the long term resolution of ED use in high noise areas of the plant has
not been resolved for at least four months. Technical Specifications allow the use of an alarming dosimeter for high radiation area entries. Implicit in this requirement is that the worker be able to hear the alarm. Although none of the past occurrences resulted in high radiation area violations, the potential for not having an effective alarming ED resulting in excessive exposure in high noise areas of the plant continued to exist.
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Both the chronic clean area contamination alarms produced by the higher sensitivity IPM-9 monitors and the multiple instances of ED alarms not being audible to workers are low safety consequence radiological issues that have persisted for many months without effective resolution.
RP Self-Assessments PSE&G's RP self-assessment program provided a check on program elements, which allowed reinstatement or adjustment of various program areas. No significant problem areas have been detected and no significant program recommendations have been suggested. The RP self assessments have been actively produced by department supervision which provided for self critical program review and evaluation. A review of recent RP self-assessments indicated a check on program
elements was made that resulted in a reinstatement of previous policy (i.e.
reinstating an ROR coord;nator), or readjustments in program implementation. No new recommendations or program developments were proposed, l
RP QA Oversiaht The RP program oversight includes a Salem / Hope Creek QA audit (previously I
reviewed in Salem inspection report no. 97-21), QA surveillance, and the
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Radiological Services independent assessment program. The inspector reviewed results of the QA surveillance for April through December 1997 and found that they were adequate to provide additional independent RP program oversight. As of yet, the surveillance have not produced any significant findings or recommendations.
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RP Radiological Assessment The latest Radiological Services assessment (December 1997) concerning contamination control was reviewed. This assessment identified several areas for improvement including further definition of contamination survey and posting levels at Hope Creek, further use of total effective dose equivalent (TEDE) respirator use evaluations, and better follow through on personnel contamination evaluations with regard to both causes and feedback to the workers. The inspector determined that
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the newly re-instituted Radiological Services Assessment program was effective.
Resulting corrective actions and program improvements will be followed to determine the impact of this independent RP program review tool.
c.
Conclusions PSE&G conducted several levels of RP program oversight with varying degrees of effectiveness. The Radiological Occurrence Report program did not provide consistently high quality results in that several low safety significance chronic issues remained unresolved after several months. The RP program reviews provided an adequate system of checks and balances, but did not contain significant recommendations for program enhancements.
P7 Quality Assurance in EP Activities P7.1 Quality Assurance Audit of Emeroency Preparedness The inspectors reviewed the formal report of a recent quality assurance (QA)
department audit of emergency preparedness (EP) activities, as well as discussed the various findings with QA personnel. Based on these reviews and discussions, the inspectors determined that the audit thoroughly assessed the effectiveness of
EP personnel and programs, as well as the status of associated facilities and equipment. As part of their review, QA auditors observed the conduct of an EP exercise held December 11,1997. The report noted good performance with respect to communications with offsite response agencies, self-assessment, and personnel qualification records. Deficiencies were noted in corrective av. an program implementation. As a result of this OA effort,46 action requests were generated to document identified issues and provide programmatic enhancement recommendations. The inspectors concluded that the QA audit provided an effective and timely assessment of EP performance. Identified deficiencies were properly entered into the corrective action process for resolution.
S1 Conduct of Security and Safeguards Activities S1.J Protected and Vital Area Access Control
l Throughout the period, the inspectors identified examples of both poor control and inadequate display of PSE&G site access badges. On several occasions, PSE&G personnel were observed in the facility not displaying their protected or vital areas access badges conspicuously as required. In all but one case, the noted individuals
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had simply covered their badges with outer clothing. However, in the one excepted l
instance, the individual failed to maintain positive control over his badge. When his l
site access was questioned by the inspectors, the individual recognized that he had
left his badge in his primary work area. Once the badge was found, the inspectors verified that the individual had authorized area access. Upon additional questioning, this individual challenged the need to contact security department personnel to inform them of the incident. The inspectors determined that this was a violation of section 2.8 of the site Security Plan, since the badge could have been compromised during the time it was not under positive control. The inspectors contacted site security to inform them of this incident.
Once informed, the inspectors observed that station and security department management acted promptly and appropriately in resolving this and the other issues.
A broader review of employee sensitivity and understanding of PSE&G security i
requirements was initiated and an action request was generated in accordance with i
the corrective action program to document findings and proposed follow up i
activities. The failure to adhere to site Security Plan access control requirements constitutes a violation of minor significance and is being treated as a Non-Cited
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Violation, consistent with Section IV of the NRC Enforcement Policy. (NCV 50-354/98-01-09)
. V. Manaaement Meetinas X1 Miscellaneous On January 12,1998, Mr. Harold W. Keiser was narned Executive Vice President of PSE&G's Nuclear Business Unit. Mr. Keiser is scheduled to relieve Leon Eliason, current President and Chief Nuclear Officer of the Nuclear Business Unit, upon his retirement in l
April 1998.
i From January 12-16,1998, two NRC contract inspectors were at the Hope Creek site l
conducting a specialized review of the applicability of the Human Performance
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investigation Process (HPIP) to routine NRC inspection activities. HPIP was developed for the NRC as an inspection tool and is described in detailin NUREG/CR-5455.
X2 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the i
conclusion of the inspection on March 9,1998. The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
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X3 Pre Decisional Enforcement Conference Summary On January 14,1998, two public pre-decisional enforcement conferences were held in the NRC Region i office. The first conference was held to discuss apparent reactivity manipulation procedure violations associated with control rod movements during a November 11,1997 reactor core shutdown margin demonstration. The second conference was held to discuss apparent violations of 10 CFR 50.65 regarding the monitoring of systems and components within the scope of PSE&G's " maintenance rule" program.
Slides used during the presentations are attached to this report.
X4 Management Meeting Summary On January 14,1998, a meeting between NRC and PSE&G management was held in the NRC Region I office to discuss maintenance and engineering department support issues which occurred during the recently completed refueling outage.
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INSPECTION PROCEDURES USED IP 37551:
Onsite Engineering IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems IP 61726:
Surveillance Observations IP 62707:
Maintenance Observations IP 71707:
Plant Operations IP 71750:
Plant Support Activities IP 83750:
Occupational Radiation Exposure IP 83728:
Maintaining Occupational Exposures ALARA IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities ITEMS OPENED, CLOSED, AND DISCUSSED
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Opene_cl none Open/ Closed 50-354/98-01-01 NCV Missed TS surveillance for HPCI isolation instrumentation 50-354/98-01-02 NCV Failure to follow SLC tank chemical addition procedure 50-354/98-01-03 NCV Missed TS surveillance for secondary containment isolation instrumentation 50-354/98-01-04 NCV Missed TS surveillance for secondary containment isolation instrumentation 50-354/98-01-05 NCV Missed TS surveillance for inservice testing of emergency diesel generator air start check valves 50-354/98-01-06 NCV Failure to promptly identify and correct condition causing repeat f ailures of "F" FRVS recirculation unit 50-354/98-01-07 NCV Failure to follow core flow calculation procedure 50-354/98-01-08 NCV Failure to follow RCA access management procedure 50-354/98-01-09 NCV Failure to follow site security procedures Closed 50-354/E97-160-01013 VIO Inadequate safety evaluation for RHR cross-tie modification.
50 354/97-01-06 VIO Temporary scaffolding not installed or maintained in accordance with established procedures.
50-354/97-31 LER Engineered safety feature actuation - RCIC isolation.
50-354/97-33 LER TS prohibited condition - failure to perform secondary containment isolation actuation instrumentation channel checks.
50-354/97-34 LER Operation in a technical specification prohibited condition due to both subsystems of main steam isolation valve sealing system inoperable
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LIST OF ACRONYMS USED ALARA As Low As is Reasonably Achievable ASME American Society of Mechanical Engineers APRM Average Power Range Monitoring CTB Cooling Tower Blowdown ED Electroute )osimeter EDG Emergea/ Diesel Generator EHC Electrohydraulic Control EP Emergency Preparedness FRVS Filtration, Recirculation, and Ventilation System GDC General Design Criterion HPCI High Pressure Coolant injection HPIP Human Performance investigation Process IST Inservice Testing LER Licensee Event Report LRW Liquid Radioactive Waste NRB Nuclear Review Board NRC Nuclear Regulatory Commission NVLAP National Voluntary Laboratory Accreditation Program PDR Public Document Room PP&L Pennsylvania Power and Ligi.:
PSE&G Public Service Electric and t u QA Quality Assurance RCA Radiological Controlled Area RCIC Reactor Core Isolation Cooling RFO7 Refueling Outage Number Seven RHR Residual Heat Removal RMS Radiation Monitoring System ROR Radiological Occurrence Report RP Radiation Protection RWP Radiation Work Permit RWCU Reactor Water Cleanup SCFM Standard Cubic Feet per Minute SLC Standby Liquid Control SSW Station Service Water SWIS Service Water Intake Structure l
SWSOPI Service Water System Operational Performance inspection TBBE Turbine Building Battery Exhaust TCV Turbine Control Valve l
TEDE Total Effective Dose Equivalent l
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TS Technical Specification
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TSSIP Technical Specification Surveillance improvement Program UFSAR Updated Final Safety Analysis Repor+
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