IR 05000354/1998010
| ML20196D117 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 11/23/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20196D077 | List: |
| References | |
| 50-354-98-10, NUDOCS 9812020158 | |
| Download: ML20196D117 (27) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket No:
50-354 License Nos:
NPF-57 Report No.
50-354/98-10 Licensee:
Public Service Electric and Gas Company
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Facility:
Hope Creek Nuclear Generating Station
Location:
P.O. Box 236
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Hancocks Bridge, New Jersey 08038 Dates:
September 20,1998 - October 31,1998 Inspectors:
S. M. Pindale, Senior Resident inspector J. D. Orr, Resident inspector T. H. Fish, Operations Engineer i
Approved by:
James C. Linville, Chief, Projects Branch 3
Division of Reactor Projects
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i 9812020158 981123
PDR ADOCK 05000354 G
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EXECUTIVE SUMMARY Hope Creek Generating Station NRC Inspection Report 50-354/98-10 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covered a six-week period of resident inspection; in addition, it included the results of an announced inspection by a regional inspector, who reviewed several previously opened items.
Operations Operators effectively conducted a thorough pre-job brief for a first time special test involving a hydrogen water chemistry injection flow increase. The special test was appropriately stopped early and without consequence when system response was not as expected. Also, control room operators displayed high standards for communication and error-free equipment manipulation during a successful high pressure coolant injection pump inservice test. (Section 01.1)
A senior reactor operator performed a thorough review of the 31-day primary containment integrity valve verification and discovered that a valve had been inappropriately categorized as not requiring a hands-on position verification. PSE&G evaluated the extent of condition and identified three additional similar instances of inappropriate categorization. The surveillance procedure was corrected and enhanced to preclude repetition of this problem.
In all four cases, the valves were physically verified to be in the required locked-closed position. This issue was characterized as a minor violation. (Section O3.1)
i Operators failed to properly implement a safety tagging program requirement while developing and implementing a tagout associated with the 'A' emergency diesel generator starting air compressor. This administrative error was identified by a maintenance supervisor performing a pre-job walkdown. An isolation valve had been closed by an operating procedure but was not administratively tagged as an isolation boundary in accordance with PSE&G's safety tagging program. Since work had not actually started and the valve had already been closed, this was a violation of minor significance. (Section 04.1)
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Maintenance Maintenance technicians appropriately followed station procedures during the conduct of surveillances. However, three way communications and peer checks were not consistently applied during the conduct of a source range monitor surveillance. The maintenance
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technicians also did not question an open, unattended intermediate range monitor drawer at their job site. Operators subsequently re-closed the drawer. (Section M1.1)
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Electricians connected a battery charger to a degraded single cell of an operable safety related battery, which was contrary to procedure requirements. The battery remained in-place, but was electrically disconnected from the rest of the operable battery cells.
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Although the safety consequence was minimal due to some specific precautions implemented by PSE&G, the evolution was not properly evaluated and controlled. (Section M4.1 )
PSE&G implemented acceptable interim actions to address recent NRC-identified concerns associated with their testing methodology for the two standby liquid control system pumps. Specifically, PSE&G revised the associated testing procedures so that the test duration specification of the ASME in-service testing document was satisfied while further review continued. (Section M8.1)
Enaineerina PSE&G was slow to determine the failure cause for an emergency diesel generator electronic speed switch, a critical component that controlled some emergency diesel generator auxiliary components necessary for engine startup and shutdown. PSE&G was also slow to understand the potential failure modes and associated impact on EDG operation. Once the failure modes and impact were understood, an adequate operability determination was completed. However, control room operators did not ensure that developed compensatory actions were completed to ensure continued EDG operability.
(Section E2.1)
System managers considered several potential problems and accurate!y resolved a spurious equipment deficiency with the reactor core isolation cooling system 'B' room cooler. Also, PSE&G remained committed to developing an extensive system performance monitoring program and held each system manager accountable for knowledge of their respective system and overall system health by the use of individual / system review boards. (Section E2.2)
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TABLE OF CONTENTS EXECUTIVE SUMM ARY.............................................ii
~ TA8 LE O F CO NT E NT S.............................................. iv
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l. O per a tio n s................................................... 1
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< Conduct of Operations.................................... 1 i
01.1 General Observations................................ 1 O3
. Operations Procedures and Documentation...................... 2 O3.1 (Closed) Licensee Event Report 50-5 54/98-06............... 2 e
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Operator Knowledge and Performance......................... 3
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l 04.1 Tagging Deficiency Associated with Emergency Diesel Generator Air L
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System..........................................3
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Quality Assurance in Operations............................. 4 L
07.1 Nuclear Review Board Meeting.........................4 l
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Miscellaneous Operations issues............................. 4
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l 08.1 (Closed) Unresolved item 50-354/98-03-01
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08.2 (Closed) Unresolved item 50-3 54/98-03-02................ 5
il. M ai nte n a nc e................................................... 5
M1 Conduct of Maintenance................................... 5 i
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M 1.1 Conduct of instrumentation and Controls Surveillances........5
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M4 Maintenance Staff Knowledge and Performance.................. 6 -
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l M4.1E Improper Single Cell Charging of Safety Related Battery........ 6
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l M8 Miscellaneous Maintenance issues............................. 8
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M8.1 (Open) Unresolved item 50-354/98-08-01.................. 8 M8.2 (Closed) Violation 50-354/E97-144-02013................ 10
. M8.3 (Closed) Violation 50-354/E97-144-02023................ 10 M8.4 (Closed) Violation 50-354/E97-144-02033.................,11-
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M8.5 (Closed) Violation 50-354/E97-144-02043................ 11 l.
M8.6 (Closed) Inspector Followup item 50-354/97-80-06.......... 12
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p M8.7 (Closed) Inspector Followup item 50-3 54/97-80-08.......... 13
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lli. Engineeri ng................................................... 13
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E2-Engineering Support of Facilities and Equipment................. 13 i
E2.1 Emergency Diesel Generator Electronic Speed Switch Failures.. 13-
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E2.2 System Engineering Support of Equipment................ 17
- lV. Pl a nt S u pp o rt................................................. 1 8
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P3 Emergency Preparedness Procedures and Documentation........... 18 P3.1 Non-Emergency 1-Hour Report to NRC for inoperable South Plant Vent l_
Radiation Monitor................................... 18 V. M anagement Meeting s...........................................
4 X1 Exit Meeting Sum m ary................................... 18 l
l X2 IN PO Report Review..................................... 18
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1 INSPECTION PROCEDURES USED.....................................
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ITEMS OPENED, CLOSED, AND DISCUSSED.............................
l LIST O F ACRO NYM S U SED.......................................... 21 l
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Report Details Summarv of Plant Status Hope Creek was operated at or near full power for the duration of the inspection period.
Weekend load reductions were initiated to between 60% and 95% power during this inspection period in order to perform planned maintenance, primarily associated with balance of plant components and control rod drive hydraulic control units.
l. Operations
Conduct of Operations 01.1 General Observations a.
Insoection Scope (71707)
The inspectors reviewed ongoing activities and conducted plant tours throughout the inspection period in accordance with Inspection Procedure 71707.
b.
Observations and Findinas On September 26,1998, the NRC inspectors observed a pre-job brief for a hydrogen water chemistry injection system (HWCl) test. The test was intended to support a design change to increase the hydrogen injection flowrate in order to improve the reactor coolant dissolved oxygen content. The test was performed in accordance with PSE&G's station procedure for infrequently performed evolutions.
The pre-job brief was attended by operators, radiation protection technicians, chemistry technicians, instrument technicians, the test engineer, the system engineer, and management. The NRC inspectors considered the pre-job brief to be thorough and detailed. Allindividuals present participated in the pre-job brief and the test director ensured that each individual understood his/her responsibilities during the evolution. The test was suspended when the hydrogen injection flow rate could not be raised above the normal maximum operating level. PSE&G resolved the problems with the HWCl flow controllers at a later date and subsequently performed the test. Operators similarly conducted a thorough pre-job brief associated with a standby liquid control system surveillance that was conducted on October 16,1998. That pre-job brief was also well-attended by the appropriate station personnel.
On October 20,1998, the NRC inspectors observed the control room operators perform HC.OP-IS.BJ-0001(O), High Pressure Coolant Injection (HPCI) Main and BoosterPump Set-Inservice Test. Duties, such as torus temperature monitoring were assigned such that the reactor operator operating HPCI was not distracted.
The control room atmosphere was quiet and established to support error free operation of HPCI. Communications and peer checks among the control room operators were excellen _
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Conclusions Operators effectively conducted a thorough pre-job brief for a first time special test involving a hydrogen water chemistry injection flow increase. The special test was appropriately stopped early and without consequence when system response was not as expected. Also, control room operators displayed high standards for communication and error-free equipment manipulation during a successful high pressure coolant injection pump inservice test.
O3 Operations Procedures and Documentation O3.1 (Closed) Licensee Event Report 50-354/98-06:Inadeauate Performance of Primarv Containment Intearity Verification a.
Insoection Scope (71707,92700,92901)
The inspectors performed an onsite inspection and reviewed PSE&G's corrective actions for problems involving inadequate performance of Technical Specification surveillance requirement 4.6.1.1.b for primary containment integrity verification.
b.
Observations and Findinas
Technical Specification surveillance 4.6.1.1.b requires that primary containment manualisolation valves that must be closed during accident conditions be verified closed at least once per 31 days. PSE&G developed a surveillance procedura that categorized valves in two lists; non-high radiation area valves requiring a hands-on verification, and high-radiation area valves requiring an administrative review using valve lineup sheets.
On September 16,1998, PSE&G discovered that a hands-on valve position verification had not been performed for valve 1BHV-031, a test valve on the standby liquid control system discharge line. The surveillance procedure had included 1BHV-031 on the list for valves in high radiation areas. However, a senior reactor operator reviewing the surveillance prior to the monthly performance, recognized that 1BHV-031 was actually not in a high radiation area. An equipment operator promptly performed a hands-on verification for 1BHV-031. PSE&G then reviewed the remainder of the valves identified in the procedure as being in high-radiation areas, and discovered three additional valves that were in fact, not in high radiation areas. All four valves that previously had not been position verified were physically verified to be in the required locked cled position. PSE&G had used a computer based plant valve lineup that established these valves in the correct position as the means to conduct the administrative position review. The inspectors determined that PSE&G's failure to perform a complete the 31-day primary containment integrity valve verification constitutes a violation of minor significance and is not subject to formal enforcement action.
The inspectors verified that PSE&G had correctly revised the surveillance procedure for the valves discovered in error. The inspectors also compared several radiation l
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survey maps and the surveillance procedure high-radiation area valve list, and confirmed that PSE&G accurately corrected the high-radiation area valve list.
c.
Conclusions A senior reactor operator performed a thorough review of the 31-day primary containment integrity valve verification and discovered that a valve had been inappropriately categorized as not requiring a hands-on position verification. PSE&G evaluated the extent of condition and identified three additional similar instances of inappropriate categorization. The surveillance procedure was corrected and enhanced to preclude repetition of this problem. In all four cases, the valves were physically verified to be in the required locked-closed position.
Operator Knowledge and Performance 04.1 Taaaina Deficiency Associated with Emeraency Diesel Generator Air System a.
Insoection Scope (62707,71707)
The inspectors reviewed PSE&G's follow-up of a self-identified tagging deficiency associated with an emergency diesel generator (EDG) air system tagout. The inspectors walked down portions of the system and reviewed the associated Action Request.
b.
Observations and Findinas On September 21,1998, PSE&G identified a tagging deficiency associated with planned maintenance on the 'A' EDG starting air compressor. The work associated with the compressor required cylinder head disassembly. However, operators involved with developing and implementing the tagout did not recognize that the work was intrusive to the compressor, which would have required isolating the compressor from the two receiver tanks. Accordingly, the tagout did not identify a particular isolation valve as part of the tagout boundary to require a red blocking tag.
Since the work was to be performed while the 'A' EDG remained operable, the 'A'
EDG's two compressed air receiver tanks were cross connected with the 'C' EDG air compressor in accordance with station procedures. During a pre-job walkdown, the maintenance supervisor identified that the valve,1 KJ-V707, was not part of the tagout. This valve isolated the compressed air receiver tanks and the backup air supply ('C' EDG air compressor) from the 'A' EDG starting air compressor. In response to this identification, operations personnel added the valve as part of the isolation boundary and installed the required red blocking tag. The valve was already in its appropriate closed position thereby achieving the necessary isolation.
In addition, the work had not actually started on the 'A' air compressor.
The inspector reviewed PSE&G's actions and found that the maintenance job supervisor demonstrated good attention to detailin identifying this discrepanc l l
l PSE&G responded promptly and appropriately to this issue. The inspectors concluded that PSE&G's f ailure to follow the administrative requirements of the i
i safety tagging program procedure constituted a violation of minor significance not l
subject to formal enforcement action.
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Conclusions Operators failed to properly implement a safety tagging program requirement while
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developing and implementing a tagout associated with the 'A' emergency diesel
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generator starting air compressor. This administrative error was identified by a maintenance supervisor performing a pre-job walkdown. An isolation valve had
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been closed by an operating procedure but was not administratively tagged as an isolation boundary in accordance with PSE&G's safety tagging program.
Quality Assurance in Operations 07.1 Nuclear Review Board Meetina (71707)
On September 30 and October 1,1998, the Nuclear Review Board held a quarterly meeting at the Salem / Hope Creek site. The inspectors attended portions of the meeting, including the chemistry report and the maintenance report. The discussions observed by the inspectors were characterized by probing questions and reflected a strong safety focus.
Miscellaneous Operations issues 08.1 (Closed) Unresolved item 50-354/98-03-01: Information on License Acolication Form Potentially Not Complete and Accurate a.
Insoection Scoce (92901)
This item discussed whether the information the licensee supplied on NRC Form 398, Personal Qua///ication Statement - Licensee, regarding significant reactivity control manipulations was complete and accurate. The inspectors performed an on-site inspection and reviewed PSE&G's follow-up and corrective actions associated with this issue, b.
Observations and Findinas The NRC had noted the preliminary applications indicated that PSE&G gave the applicants multiple credit for one reactivity manipulation. Also, the applicants had followed the initiallicense program requirements, which were not clear. In response to NRC questions, the applicants re-performed reactivity manipulations. The inspe,ctors determined that subsequent submittal of final applications reflected
l manipulations that were done satisfactorily. In addition, the inspectors verified that PSE&G clarified program requirements regarding reactivity rnanipulations. This item is closed.
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Conclusions NRC investigators reviewed this item and could not substantiate that there was any intent by the applicants or the licensee training management to deceive the NRC regarding the number of manipulations the applicants completed. In addition, PSE&G clarified program requirements regarding reactivity manipulations.
08.2 (Closed) Unresolved item 50-354/98-03-02: Potential Inadeauacy of Time Spent on Shift a.
Insoection Scooe (92901)
This item discussed the adequacy of the licensed operator initial training program requirements for time on shift. The inspectorE performed an on-site inspection and reviewed PSE&G's follow-up and corrective actions associated with this issue.
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Observations and Findinas NRC investigators reviewed this itern and determined that the applicants had completed their on shift time, as documented by the applicants' qualification cards.
During the inspection, the inspectors determined that PSE&G clarified program requirements for time on shift to be 13 weeks or 520 hours0.00602 days <br />0.144 hours <br />8.597884e-4 weeks <br />1.9786e-4 months <br />, whichever is longer.
This item is closed.
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Conclusions Based on the results of the NRC investigation and review of the above, no violations occurred, and PSE&G responded appropriately to the issue.
11. Maintenance M1 Conduct of Maintenance M1.1 Conduct of instrumentation and Controls Surveillances a.
Insoection Scope (71707,61726)
The inspectors observed portions of surveillance testing for the 'A' source range monitor and the' south plant ventilation (SPV) radiation monitor.
b.
Observations and Findinas On October 9,1998, instrumentation and controls (l&C) maintenance technicians performed a leak test on the particulate and iodine portion of the SPV radiation monitor using surveillance procedure HC.lC-FT.SP-0021(Q), functional Test Process Radiation Monitoring - South Plant Vent. The leak test was not successful. The l&C maintenance technicians re-performed the steps with the same results. The
12-hour maintenance supervisor was notified for problem resolution. The technicians and the supervisor were aware that frequently in the past, cover seals were the source of leaks. The covers were opened on a frequent basis to access the filters and samples. Radiation protection technicians were involved to inspect and tighten the seals on the SPV radiation monitor. The leak test results were still unsuccessful and the cover seal for the particulate filter required replacement. The inspectors determined that the I&C technicians approprie.ely stopped the surveillance when problems were encountered and inve.ved maintenance supervision. The radiation protection technicians were careful to use procedures to inspect and re-tighten portions of the SPV radiation monitor. l&C technicians kept the control room informed of problerns encountered during the surveillance.
I On October 23,1998,l&C maintenance technicians performed a channel check on the 'A' source range monitor (SRM) using surveillance procedure HC.lC CC.SE-0001(G), Channel Calibration Nuclear Instrumentation System - Channel A Source Range Monitor. The I&C technicians deliberately used the surveillance procedure, but three-way communications between the two technicians were inconsistent.
Some switch positions or adjustments were made as the repeat / verification part of the three-way communication was being performed rather than after this last part of the three-way communication. The inspectors also noticed that peer check, a practice of verifying correct component identification before its operation, was not consistently used.
The inspectors questioned the l&C technicians about an open, instrument range monitor (IRM) drawer. The I&C technicians did not recognize that the open IRM drawer was unnecessary and should have been closed.
c.
Conclusions Maintenance technicians appropriately followed station procedures during the conduct of surveillances. However, three way communications and peer checks were not consistently applied during the conduct of a source range monitor surveillance. The maintenance technicians also did not question an open, unattended intermediate range monitor drawer at the job site. Operators subsequently re-closed the drawer.
M4 Maintenance Staff Knowledge and Performance M4.1 Imorocer Sinole Cell Charaina of Safety Related Batterv a.
Insoection Scooe (62707)
The inspectors reviewed PSE&G's actions in response to a degraded cell on 125 Vdc safety related battery 1C-D-447. The inspectors observed portions of the associated maintenance activities, and reviewed the applicable procedures, technical specifications, a temporary modification, and other relevant documentatio..-
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Observations and Findinas On September 28,1998, electricians conducted a quarterly surveillance for the 1C-D-447 safety related battery. This surveillance was being conducted on an accelerated frequency (monthly) due to recent performance problems with the
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station batteries. During the surveillance, electricians identified that one of the 60 cells (No. 31) was below the allowable voltage level of 2.13 volts. Actual voltage was 2.08 volts. Operators entered the applicable technical specification (3.8.2.1),
which required that all battery parameters be restored to specification within 31 days. Since the voltage was above the Category C limit for each cell (2.07 volts),
the battery was considered operable, consistent with the technical specifications.
In response to the low cell voltage, PSE&G placed the battery on an equalize charge in an attempt to restore the voltage to normal. However, because cell voltage was
not improving, on September 30, PSE&G implemented a temporary modification
(No.98-014) to electrically jumper (isolate) the degraded cell from the battery.
PSE&G planned to conduct a single cell charge of the disconnected cell, and to I
replace the cell with a new one as a contingency if the cell could not be charged.
On October 1, the inspectors toured the battery room and observed that cell No. 31 was electrically jumpered but remained in its physical position, adjacent to other l
battery cells, and was connected to a battery charger.
The inspectors reviewed existing documentation to determine whether single cells could be charged while still physically adjacent to other operable cells but electrically disconnected. The inspectors reviewed procedure HC.MD-GP.ZZ-0014(O), Single CellBattery Charge and/or CellReplacement. Section 5.6 (Charging Single Cell) provides instructions for charging single battery cells, but had a caution that stated "This Section SHALL ONLY be USED for Non 1E Batteries or 1E Battery Banks that have been declared inoperable. Charger leads should be fused." The inspectors found that this application of the single cell charge was inconsistent with procedure HC.MD-GP.ZZ-0014(O) because the 1E (safety-related)
battery remained operable. PSE&G then informed the inspectors that procedure j
section 5.7 (Charging Spare or Stored Multiple Cells) had been used to charge the single cell. However, the inspectors determined that this procedure section was also inappropriate because 1) the degraded cell was not a spare cell, and 2) there was no associated evaluation that considered consequences of connecting a non-Class 1E charger to a cell that was still adjacent to other operable cells. In response to the inspector's questions and the discovery that the single cell charge was not in accordance with an approved procedure, PSE&G promptly disconnected the battery charger from cell No. 31 and removed the charger from the battery room.
The inspector concluded that the actual and potential consequences were minimal because of specific precautions and actions implemented by PSE&G. For example, the non-Class 1E charger was adequately fused to provide electrical isolation in the event of an electrical fault, and the charger's physical design and construction wos inherently stable (minimizing seismic concerns). Notwithstanding the low actual safety impact, PSE&G's failure to properly control and oversee this activity was cause for concern. Specifically, the wrong section of the procedure was used
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(electricians incorrectly considered the installed cell to be a spare). Also, section l
5.6 of the procedure did not allow such an operation because there was no associated evaluation to identify and bound the potential failure modes for charging a cell associated with an operable safety related battery. In addition to these concerns, the inspectors concluded that PSE&G did not take appropriate corrective
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actions for a similar concern (violation) at Salem Unit 1 on May 4,1998 (See NRC l
Inspection 50-272/98-05).
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in response to this issue, PSE&G disconnected and removed the charger, and
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discussed this concern with the responsible maintenance and engineering personnel.
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In addition, PSE&G initiated efforts to enhance procedure HC.MD-GP.ZZ-0014(Q) to evaluate and allow in-place charging of single safety related battery cells that are
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electrically disconnected.
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The inspectors concluded that the electricians failed to follow procedure HC.MD-GP.ZZ-0014(Q), which contained a caution that prohibited single cell charging of an operable 1E battery. Technical Specification 6.8.1 requires that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Appendix A of NRC Regulatory Guide 1.33, which includes safety related maintenance procedures. PSE&G's failure to follow
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l procedure HC.MD-GP.ZZ-0014(O)is a violation. (VIO 50-354/98-10-01)
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Conclusions
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Electricians connected a battery charger to a degraded single cell of an operable j
l safety related battery, which was contrary to procedure requirements. The battery l
remained in-place, but was electrically disconnected from the rest of the operable j
battery cells. Although the safety consequence was minimal due to some specific precautions implemented by PSE&G, the evolution was not properly evaluated and controlled.
i M8 Miscellaneous Maintenance issues M8.1 (Open) Unresolved item 50-354/98-08-01: In-service Testina of Standbv Liould Control Pumos a.
Inspection Scope (92902)
The inspectors performed an onsite inspection and reviewed PSE&G's actions following the NRC's identification of a testing methodology question associated with the standby liquid control (SLC) system pumps.
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Observations and Findinas l
The inspectors questioned whether PSE&G had tested the SLC pumps in a fashion
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consistent with Part 6 of ASME Operation and Maintenance of Nuclear Power Plants (OM - 1987). Specifically, Section 5.6 of OM - 1987 stated that after pump
conditions art as stable as the system permits, each pump shall be run at least two
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minutes, and at the end of this time, at least one measurement or observation of each of the quantities required shall be made and recorded. Pump flow rate data was not made and recorded following this two minute stabilization period without interruption. That is, the pump was stopped and restarted, then flow rate data was made and recorded without re-establishing a two minute stabilization period.
During this inspection period, the inspectors informed PSE&G that the existing testing methodology did not appear to be consistent with Section 5.6 of OM -
1987. PSE&G's initial actions included modifying the existing surveillance procedures for the two SLC pumps, HC.OP-lS.BH-0001(Q) and HC.OP-IS.BH-0002(Q). The procedure changes incorporated a two minute stabilization period just prior to initiating the flow rate measurement. The flow rate was then measured and calculated as it was previously, by observing and recording the test tank level change for one minute of pump operation. The test tank contents were pumped to 55-gallon barrels located outside the SLC system room.
The inspectors reviewed the revised test procedure and observed the perMrmance of the revised test for the 'B' SLC pump on October 16,1998. There were some minor difficulties in performing the test. One example was a pressure gauge that was temporarily installed for the test was placed in a location in the overhead area that was difficult to see while making valve manipulations while establishing pump discharge pressure. The first pressuie gauge was broken due to the severe pressure oscillations during the test. The second pressure gauge was placed in a better position to conduct the test. The inspectors observed that the operator was required to make adjustments to 1-BH-VO43 (discharge drain valve) while in the two minute stabilization period to maintain discharge pressure at the required 1260 psig.
No additional adjustments were required or were made while the pump was operating during the one rninute flow rate data collection period. The 'A' SLC pump test was performed on October 19,1998. Both surveillances achieved acceptable results, with the flow rates above the 41.2 gallon per minute minimum flow requirement identified in the technical specifications.
At the end of this inspection period, PSE&G was planning to further investigate the basis for the two minute stabilization period in Section 5.6 of OM - 1987, including a determination as to whether the test procedure was in conformance with the test duration statement by contacting ASME. For the interim, PSE&G will continue to conduct the quarterly pump surveillances using the revised procedures. This item will remain open pending completion of PSE&G's ongoing review.
c.
Conclusions PSE&G implemented acceptable interim actions to address recent NRC-identified concerns associated with the testing methodology for the two standby liquid control system pumps. Specifically, PSE&G revised the associated testing procedures so that the test duration specification of the ASME in-service testing document was satisfied while further review continue.. _ _ _
M8.2 (Closed) Violation 50-354/E97-144-02013: Failure to include Certain Systems.
Structures, and Components (SSCs) and Functions Within Maintenance Rule Scope a.
Insoection Scope (92902)
Inspectors assessed PSE&G's response to issues the NRC identified during inspections of the facility's implementation of the Maintenance Rule (NRC Reports 50-354/97-09,97-80, and 97-81).
l b.
Observations and Findinas This violation - previously numbered VIO 50-354/97-80-01-discussed the failure of PSE&G to include eight SSCs or SSC functions (e.g., the nuclear fuel assemblies-the drywell ventilation system) within the scope of the maintenance program.
PSE&G determined this violation was caused by inadequate implementation of the maintenance rule requirements in response, PSE&G re-validated scoping decisions.
These decisions included a review by the system manager and an additional independent UFSAR and emergency operating procedure review. The facility's expert panel then reviewed and subsequently concurred with the revised scoping decisions. The eight SSCs identified by the NRC were added to the scope.
Additional SSCs, which PSE&G identified during the associated extent of condition review, were added to the scope. PSE&G also revised the maintenance rule scoping procedure, c.
Conclusions The inspectors reviewed the responses to this item, determined they were acceptable, and selectively verified that PSE&G had appropriately completed the actions and enhancements associated with each issue. This item is closed.
M8.3 (Closed) Violation 50-354/E97-144-02023:No Unavailability Performance Criteria Established For Several Safety Sianificant SSCs j
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Insoection Scope (92902)
Inspectors assessed PSE&G's response to issues the NRC identified during inspections of the facility's implementation of the Maintenance Rule (NRC Reports 50-354/97-09,97-80, and 97-81).
b.
Observations and Findinas This violation - previously numbered and part of VIO 50-354/97-80-04-discussed the failure of PSE&G to establish unavailability performance criteria for seven safety significant systems (e.g., the reactor protection system; the control rod drive system). PSE&G determined this violation was caused by inadequate implementation of maintenance rule requirements. In response, PSE&G re-validated performance criteria. The validation included a review by the system manager and the expert panel. Perforrrance criteria (condition monitoring:
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unavailability and reliability, as appropriate) were added to the SSCs identified by the NRC. During the extent of condition review, PSE&G identified additional SSCs that lacked performance criteria and subsequently added them to the affected SSCs.
PSE&G also revised the procedure that provides guidance on establishing performance criteria.
c.
Conclusions The inspectors reviewed the responses to this item, determined they were acceptable, and selectively verified that PSE&G had appropriately completed the actions and enhancements associated with each issue. This item is closed.
M8.4 (Closed) Violation 50-354/E97-144-02033:No Reliability Performance Criteria l
Established For a Safety Sionificant SSC
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a.
Insoection Scope (92902)
Inspectors assessed PSE&G's response to issues the NRC identified during inspections of the facility's implementation of the Maintenance Rule (NRC Reports
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50-354/97-09,97-80, and 97-81).
b.
Observations and Findinas This violation - previously numbered and part of VIO 50-354/97-80-04-discussed PSE&G's failure to establish reliability performance criteria for the main steam non-automatic depressurization system (ADS). PSE&G determined the cause of this violation was inadequate implementation of maintenance rule requirements and subsequently established reliability measures for the main steam non-ADS.
c.
Conclusions The inspectors reviewed the responses to this item, determined they were acceptable, and selectively verified that PSE&G had appropriately completed the actions and enhancements associated with each issue. This item is closed.
M8.5 (Closed) Violation 50-354/E97-144-02043:No Performance Criteria Established at
I the System / Train Level For Standbv SSCs a.
Inspection Scoce (92902)
Inspectors assessed PSE&G's response to issues the NRC identified during inspections of the facility's implementation of the Maintenance Rule (NRC Reports 50-354/97-09,97-80, and 97-81).
b.
Observations and Findinas This violation - previously numbered and part of VIO 50-354/97 80-04-discussed PSE&G's inappropriate assignment of plant level performance criteria, instead of l.
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system / train level criteria, for three standby systems (e.g., the remote shutdown system). PSE&G determined the cause of this violation was inadequate implementation of maintenance rule requirements and subsequently assigned performance criteria at the system / train level for the affected systems.
c.
Conclusions The inspectors reviewed the responses to this item, determined they were acceptable, and selectively verified that PSE&G had appropriately completed the actions and enhancements associated with each issue. This item is closed.
M8.6 (Closed) Inspector Followuo item 50-354/97-80-06: Process for Risk Assessments When Takina Eauioment Out of Service a.
Inspection Scope (92902)
Inspectors assessed PSE&G's response to issues the NRC identified during inspections of the facility's implementation of the Maintenance Rule (NRC Reports 50-354/97-09,97-80, and 97-81).
b.
Observations and Findinas This item discussed an observation NRC inspectors made during the maintenance rule baseline inspection in that, although PSE&G had procedures to effectively manage risk when performing maintenance during Modes 3,4, and 5, risk assessments for maintenance performed in Mode 2 were not addressed.
PSE&G typically does not schedule planned maintenance for Mode 2 because Operations management expects the operators to focus on low power activities and reactivity control. Also, since procedures require all Mode 2-required equipment to be operable prior to entering Mode 2, there is a very slight chance that any maintenance would need to be done. Further, since the plant is in Mode 2 for a short time, there is little opportunity for any maintenance to be performed. Lastly, the inspectors noted the probabilistic safety assessment group is readily capable of assessing the risk of any planned Mode 2 maintenance, should it be necessary.
Based on these findings, the inspectors determined that PSE&G could perform an acceptable risk assessment in the unlikely event maintenance in Mode 2 was required.
c.
Conclusions The inspectors reviewed the responses to this item, determined they were acceptable, and selectively verified that PSE&G had appropriately completed the l
actions and enhancements associated with this issue. This item is closed.
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M8.7 (Closed) Insoector Followuo item 50-354/97-80-08: Review Comoleted Actions to Uoarade Maintenance Rule Proaram i
l a.
Insoection Scope (92902)
Inspectors assessed PSE&G's response to issues the NRC identified during inspections of the facility's implementation of the Maintenance Rule (NRC Reports i
50-354/97-09,97-80, and 97 81).
j b.
Observations and Findinas This item discussed pending actions that PSE&G was to implement in response to a maintenance rule program self assessment. At the time of the maintenance rule inspection, the actions had not been completed. Subsequently, PSE&G completed i
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the corrective actions associated with the assessment. On a sampling basis, the inspector verified that PSE&G had adequately completed all required activities and enhancements.
c.
Conclusions The inspectors reviewed the responses to this item, determined they were acceptable, and selectively verified that PSE&G had appropriately completed the actions and enhancements associated with each issue. This item is closed.
Ill. Enaineerina E2 Engineering Support of Facilities and Equipment E2.1 Emeraency Diesel Generator Electronic Soeed Switch Failures a.
Insoection Scoce (71707,37551)
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The inspectors reviewed PSE&G's follow-up corrective actions involving multiple electronic speed switch failures on the 'A' emergency diesel generator (EDG).
Discussions related to the failures were held with control room operators and system engineers.
b.
Observations and Findinas Backaround i
The EDG electronic speed switch is a device that controls the operation and sequence of various EDG auxiliary systems. The speed switch also drives two local EDG tachometers. The speed switch is a necessary component for successful emergency diesel generator startup. The speed switch remains de-energized during EDG standby conditions. Four contacts within the speed switch output to; the air start system, EDG room recirculation fans, motor driven fuel oil pump, EDG keep-i
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warm components, generator space heaters, exciter field flashing circuit, EDG cooling water temperature control valve, and numerous alarms and indications. The
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local tachometers are driven by an analog output from the electronic speed switch.
.The speed switch is a vendor supplied unit and four electronic circuit boards are contained within a single box.
During Hope Creek's seventh refueling outage (RF07), speed switches on the 'A'
and 'B' EDGs were damaged by retest activities for unrelated relay replacements.
The relay retests induced voltages in the speed switches, which failed the electronic components. PSE&G replaced the 'A' and 'B' EDG speed switches and revised the relay retests to eliminate any electronic communication with the speed switches.
Following the speed switch replacements on the 'A' and 'B' EDG speed switches, the 'A' EDG has experienced several speed related problems.
Soeed Switch Develooed 125 Vdc Svstem Ground On March 9,1998, during a scheduled monthly surveillance test of the 'A' EDG, an electrical ground developed on the 125 Vdc bus associated with the 'A' EDG. (See NRC Inspection Report 50-354/98-02, Section M2.1.) Subsequent troubleshooting discovered that the ground was within the electronic speed switch. Two resistors on one circuit board displayed severe overheating. System engineers were unable to determine the failure mode because of the complexity of the speed switch circuitry, and details were not provided by the vendor because of the proprietary design. The electronic speed switch was replaced and PSE&G intended to send the failed electronic speed switch to the vendor for failure analysis.
Subseauent Soeed-related Anomalies On June 30,1998, during a scheduled monthly surveillance test of the 'A' EDG, operators noticed that the jacket water keep-warm pump and heater, and the generator space heater cycled on and off when the EDG was secured and coasting down. The operators also noticed that local speed indication was erratic. The control room operators wrote an action request (AR) and considered the 'A' EDG fully operable and not degraded. The control room operators' operability decision was based on observed symptoms and that the cycling auxiliary components did not affect emergency operation of the EDG.
Schedulina Errors Allowed the Soeed Switch Problems to Continue On July 27,1998, a maintenance work scheduler identified that the work order developed for the June 30,1998 problem had been improperly canceled. The work order was canceled, in part, because the individuals and system managers canceling the work order were unaware of the problems that occurred on June 30,1998 for l
the 'A' EDG. The work order was initially developed for a previous problem, and the system managers involved believed that problem had been resolved, but were unaware of the expanded work order scope.
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Failed Soeed Switch Lost and Failure Analysis Not Performed On about September 2,1998, PSE&G realized that the speed switch that had developed a 125 Vdc system ground on March 9,1998, and displayed severe localized overheating, had been lost on site. The intended vendor failure analysis was not performed. Without the detailed analy;is, PSE&G was unable to determine the failure mode because of the complexity of the speed switch circuitry and details were not provided by the vendor because of the proprietary design.
'A ' EDG Speed-related Anomalies Recurred On September 23,1998, during a scheduled monthly surveillance test of the 'A'
EDG, operators noticed that the EDG shutdown auxiliary components cycled on and off about six to eight times in several seconds while the EDG coasted down during
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shutdown. The speed indication also failed upscale on both local tachometers.
System engineers performed a visualinspection of the electronic speed switch and noticed that the same two resistors displayed severe overheating. The 'A' EDG j
electronic speed switch was replaced. PSE&G was still unable to determine the root cause, and again intended to send the damaged speed switch to the vendor for
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failure analysis.
PSE&G Slow to Collectivelv Evaluate Soeed Switch Problems On October 13,1998, the NRC inspectors discussed the history of speed switch j
problems with the Operations Manager. PSE&G had not yet determined a root cause for the 'A' EDG speed switch problems and had not completely evaluated the component overheating and its possible effects on the more critical functions of the speed switch. Additionally, PSE&G had just replaced a speed switch on the 'D'
EDG. The 'D' EDG was currently in a scheduled system outage and a visual inspection indicated slight, but possible overheating on one of the same two resistors. The inspectors believed that PSE&G had not collectively considered all the recent problems, nor appropriately developed an operability determination for the EDG speed switch problems. In response to the inspector's questions regarding EDG operability, on October 16,1998, PSE&G completed an operability determination for the EDGs and the related 'A' EDG speed switch problems. The i
inspectors reviewed and considered the operability determination to be adequate.
The operability determination included a compensatory action to have a system engineer present during scheduled EDG operation to observe any similar symptoms that had occurred for speed switch problems.
Operability Comoensatorv Actions Not Comoleted i
The NRC inspectors reviewed the results for a 'D' EDG surveillance test that had concluded on October 20,1998. The surveillance test was a post-maintenance test for a scheduled seven day 'D' EDG system outage. PSE&G replaced the 'D' EDG speed switch during the system outage. The inspectors noticed a note included in the remarks section of the surveillance that local EDG speed indication had f ailed upscale. The inspectors discussed the speed indication problem with system
engineers. The system engineers were unaware of the speed indication problems during the surveillance test and the operators had failed to ensure that the compensatory actions for the operability determination were completed.
Root Cause Determined On October 23,1998, a PSE&G system engineer traveled to the vendor and witnessed the failure analysis on the recently failed speed switch on the 'D' EDG.
The engineers determined that an incorrect resistor had been installed in the power supply circuit of the speed switch. An 82 ohm resistor was installed in place of the required 1200 ohm resistor. The reduced resistance had increased the power requirements of the speed switch and was consistent with the overheating failures that had been previously observed. PSE&G performed subsequent inspections of each EDG speed switch. The speed switch recently installed in the 'D' EDG contained the incorrect 82 ohm resistor. This was consistent with the speed indication symptoms that were observed on October 20,1998.
Corrective Actions On October 21,1998, PSE&G initiated a level one root cause evaluation, the most extensive problem evaluation, to address the speed switch problems since RF07.
Once the NRC inspectors identified that PSE&G had failed to perform the intended compensatory actions for EDG operation, PSE&G developea prompt and appropriate corrective actions to ensure that the compensatory actions would always be performed. The inspectors reviewed the engineering follow-up assessment for the operability determination and considered the follow-up assessment to be thorough.
The follow-up assessment developed additional compensatory actions to ensure that the speed switches remained operable and available after any EDG operation.
These additional compensatory actions included non-intrusive voltage measurements for the four contacts that provide switch functions. The follow-up assessment also provided additional assurance that some backup signals independent from the speed switch existed for a successful EDG start. The follow-up assessment postulated one possible speed switch failure that could render the EDG inoperable, but the non-intrusive voltage measurements performed after EDG operation provided assurance the condition was not likely to occur. The visual resistor value verification of all EDG speed switches was timely. PSE&G intended to develop long term corrective actions in the level one root cause evaluation.
10 CFR Part 21 Reoort PSE&G intended to evaluate reportability under 10 CFR 21 as part of the level one root cause effort. PSE&G initiated a corrective action item undar AR 981020075to track closure of the evaluation.
c.
Conclusions PSE&G was slow to determine the failure cause for an emergency diesel generator electronic speed switch, a critical component that controlled some emergency diesel
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was also slow to understand the potential failure modes and associated impact on EDG operation. Once the failure modes and impact were understood, an adequate operability determination was completed. However, control room operators did not i
ensure that developed compensatory actions were completed to ensure continued EDG operability.
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E2.2 System Enaineerina Sucoort of Eauioment a.
In_soection Scope (37551)
The inst ectors reviewed PSE&G's corrective actions for frequent reactor core
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isolation cooling (RCIC) 'B' room cooler trips, and attended a system engineering performance monitoring review board for the control room ventilation system.
b.
Observations and Findinas On September 8,1998, the RCIC 'B' room cooler tripped within 30 seconds of starting. This was a repeat occurrence and control room operators declared the RCIC 'B' room cooler inoperable. System engineering considered all potential problems and ultimately determined that the fan was operating at a reduced flow.
The system engineers determined that the room cooler was tripping on low flow l
after a 30 second startup time delay expired. With the reduced flow and setpoint drift on the low flow switch, the RCIC 'B' room cooler experienced spurious trips on startup. A fan blade pitch adjustment was made to the RCIC 'B' room cooler and the fan was retested satisfactory on September 29,1993. The redundant RCIC 'A'
room cooler remained fully operable during this time frame.
l The NRC inspectors attended a performance monitoring review board on October 13,1998 for the control room ventilation system. The system engineering department established performance monitoring review boards to validate each plant system's health, establish performance monitoring goals, and to challenge and hold accountable each system manager for the health of his/her assigned plant systems.
The NRC inspectors observed that the monitoring review board was attended by a high level of management. The system manager was very knowledgeable about the control room ventilation system operation and design. The system manager described a thorough performance monitoring plan and the board was also able to suggest additional performance monitoring plans.
c.
Conclusions System managers considered several potential problems and accurately resolved a spurious equipment deficiency with the reactor core isolation cooling system 'B'
l room cooler. Also, PSE&G remained committed to developing an extensive system performance monitoring program and held each system manager accountable for knowledge of their respective system and overall system health by the use of individual / system review boards.
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IV. Plant Support P3 Emergency Preparedness Procedures and Documentation P3.1 Non-Emeraency 1-Hour Report to NRC for Inoperable South Plant Vent Radiation Mor'.itor (71750)
On October 9,1998, PSE&G encountered delays during a functional test on the south plant vent (SPV) radiation monitor. (See Section M1.1 for details.) Afternate sampling was established in accordance with technical specification requirements.
After a portion of the SPV radiation monitor skid was inoperable for greater than eight hours, PSE&G made a non-emergency 1-hour report to the NRC Operations Center. PSE&G based the purpose of the report on 10 CFR 50.72(b)(1)(v) for an event that resulted in a major loss of emergency assessment capability. The inspectors reviewed the guidance in NUREG-1022 Rev.1, Event Reporting Guide /ines 10 CFR 50.72 and 50.73. The NRC inspectors considered that the report may have been conservatively categorized as a major loss of emergency assessment capability. Specifically, alternate sampling was provided for the SPV effluent pathway, and additional radiation monitors associated with the SPV were still available. The inspectors discussed PSE&G's reporting criteria for inoperable effluent monitoring instrumentation with the Hope Creek Plant Manager, Operations Manager, and Licensing Manager. PSE&G intended to evaluate the reporting action levels for inoperable effluent monitoring.
V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on November 18,1998. The I.icensee acknowledged the findings presented.
X2 INPO Report Review During this report period, the inspectors reviewed the most recent documented institute of Nuclear Power Operations (INPO) evaluation of Hope Creek activities.
The INPO evaluation was conducted in December 1996. The re.sults were generally consistent with the NRC assessments of PSE&G performance. No additional NRC follow-up was warranted or conducted in response to the INPO findings.
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INSPECTION PROCEDURES USED IP 37551:
Onsite Engineering IP 61726:
Surveillance Observations IP 62707:
Maintenance Observations IP 71707:
Plant Operations
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lP 71750:
Plant Support Activities IP 92700:
Event Reports IP 92901:
Followup - Plant Operations IP 92902:
Followup - Maintenance IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors l
ITEMS OPENED, CLOSED, AND DISCUSSED Opened 69-354/98-10-01 VIO Improper Single Cell Charging of Safety-Related Battery (Section M4.1)
Closed 50-354/98-06 LER Inadequate Performance of Primary Containment integrity Verification (Section 03.1)
50-354/98-03-01 URI information on license application for potentially not complete and accurate. (Section 08.1)
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50-354/98-03-02 URI Potentialinadequacy of time spent on shift. (Section 08.2)
50-354/E97-144-02013 VIO Failure to include certain systems, structures, and components and functions of SSCs within the scope of the maintenance rule. (Section M8.2)
50-354/E97-144-02023 VIO No unavailability performance criteria established for several high safety significant SSCs. (Section M8.3)
50-354/E97-144-02033 VIO No reliability performance criteria established for a high safety significant SSC. (Section M8.4)
50-354/E97-144-02043 VIO No performance criteria established at the system / train level for standby SSCs. (Section M8.5)
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'50-354/97-80-06 IFl Process for risk assessments when taking equipment out of service. (Section M8.6)
50-354/97-80-08 IFl Review completed actions to upgrade maintenance rule program. (Section M8.7)
Discussed 50-354/98-08-01 URI in-Service Test of Standby Liquid Control Pumps (Section M8.1)
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.i LIST OF ACRONYMS USED j
I AR Action Request
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ADS Automatic Depressurization System
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ASME American Society of Mechanical Engineers EDG Emergency Diesel Generator HPCI High Pressure Coolant injection HWCl Hydrogen Water Chemistry injection l&C Instrumentation and Controls INPO Institute of Nuclear Power Operations IRM Intermediate Range Monitor NRB Nuclear Review Board.
NRC Nuclear Regulatory Commission PDR Public Document Room
.PSE&G Public Service Electric and Gas RCIC Reactor Core isolation Cooling l
SLC Standby Liquid Control-SPV South Plant Vent SRM Source Range Monitor
.SSCs Systems, Structures, and Components UFSAR Updated Final Safety Analysis Report i
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