IR 05000354/1999001
| ML20205S797 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 04/19/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20205S795 | List: |
| References | |
| 50-354-99-01, 50-354-99-1, NUDOCS 9904270023 | |
| Download: ML20205S797 (27) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket No:
50-354 License Nos:
NPF-57 Report No.
50-354/99-01 Licensee:
Public Service Electric and Gas Company l
Facility:
Hope Creek Nuclear Generating Station Location:
P.O. Box 236 Hancocks Bridge, New Jersey 08038 Dates:
January 24,1999 - March 7,1999 Inspectors:
S. M. Pindale, Senior Resident inspector
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J. D. Orr, Resident inspector T. F. Burna. Reactor Engineer J. T. Furia, Senior Radiation Specialist l
Approved by:
Glenn W. Meyer, Chief, Projects Branch 3
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Division of Reactor Projects
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9904270023 990419
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PDR ADOCK 05000354
PDR I
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t EXECUTIVE SUMMARY Hope Creek Generating Station NRC Inspection Report 50-354/99-01 This integrated inspection included aspects of operations, engineering, maintenance, and plant support. The report covers a six-week period of resident inspection; in addition, it includes the results of announced inspections by two regionalinspectors, one that reviewed radiological protection and the other that reviewed inservice inspection activities.
Ooorations.
PSE&G organized work coordination teams for major refuel outage activities, which included SROs, and these teams appeared to have contributed to improved PSE&G outage performance.
(Section 01.1)
The procedures and conditions for establishing altemate shutdown cooling were adequate. The inspectors identified minor problems that could have delayed establishing attemate shutdown
- cooling, and PSE&G promptly corrected the problems. (Section O3.1)
I Following operator actions to isolate RCIC in response to a blown fuse in isolation circuitry, the operations manager correctly detarmined that the technical specification action statement to trip the affected channel was more appropriate. PSE&G initiated corrective actions to improve procedural guidance and prevent recurrence. (Section O8.2)
Maintenance The D 4 kV vital bus was inadvertently de-energized due to a performance error by a relay technician while peiforming a periodic surveillance. PSE&G responded appropriately to this challenge, subsequently evaluated the event appropriately, and restored the affected plant equipment. (Section M1.1)
Due to several inattention to detail errors, an excess flow check valve was tested on a low pressure reactor recirculation pump seal rather than the desired high pressure excess flow check valves. As the conditions were not suitable for testing the low pressure line, the test failed and challenged plant staff and equipment. In responding to the test failure, equipment operators isolated the incorrect instrument line for several hours due to a labeling problem. No plant transient resulted from these errors, and PSE&G identified the errors and implemented acceptable corrective actions. (Section M1.2)
FSE&G safely performed numerous refuel floor a'ctivities. Supervisors, technicians and engineers all pursued error free operations during the performance of various tasks. (Section M1.3)
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The inspectors reviewed PSE&G's response to the NRC's identification of an inappropriate testing methodology of the standby liquid control system pumps, concluded that a violation had existed, and found that PSE&G's corrective actions were acceptable. (Section M8.1)
A senior reactor operator alertly identified that other senior reactor operators had failed to properly perform a technical specification flowpath verification for the safety auxiliaries cooling system. PSE&G appropriately evaluated and corrected this missed surveillance issue. (Section M8.3)
Enaineerjng Thorough follow up in refuel outage 8 on problems experienced during a control rod withdrawal in March 1998 identified a problem with the control rod blade. The control rod had remained fully inserted and disarmed. Reactor engineers identified a control rod blade blister. The safety significance was understood and the control rod blade vendor began a 10CFR21 evaluation.
(Section E2.1)
. PSE&G engineers carefully considered and minimized the plant risk during valve maintenance on the shutdown cooling suction line. The engineers were involved during the maintenance to alleviate a leakage problem and ensured that the maintenance was performed in accordance with vendor technical guidance. (Section E2.2)
The inspectors concluded that inservice inspection had been performed acceptably and included acceptable ASME program coverage, qualified personnel, approved procedures, proper implementation, appropriate examination documentation, and PSE&G oversight. The inspections were thorough and of sufficient extent to determine the integrity of the components inspected. (Section E2.3)
The application of the Mechanical Stress improvement Process (MSIP) and the suction strainer installation project were well planned, coordinated and being executed with PSE&G involvement and oversight. Control of the MSIP activity was thorough, including training, equipment placement, assembly and disassembly, and application of the pressure. Quality control and documentation were appropriate. (Section E2,4)
System engineers provided good support in developing investigation plans for observed equipment problems. (Section E2.5)
The inspectors reviewed PSE&G's actions in correcting the failure to operate the residual heat removal system consistent with the UFSAR assumptions during a prior refueling outage, and found the corrective actions to be acceptable. (Section E8.1)
Plant Suooort A generally effective radiation protection program existed during outage work. Exposure goals had been established based on reasonable assumptions of time to complete work tasks and the iii
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specific effective dose rates of the work areas. Extensive use of informational ALARA postings throughout the radiological controlled area ensured workers were aware of the radiological conditions all work areas. (Section R1)
PSE&G responded quickly and appropriately to an injury to a contractor performing underwater maintenance in the torus and effectively evaluated the causes. The injury was caused by human error by dive crews in that communications were inadequate. Causal factors that contributed to the incident were cross-channel interference and a missed opportunity by PSE&G supervisors to previously identify inadequate communications. (Section R4.1)
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TABLE OF CONTENTS EXECUTIVE SUMMARY........................
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TABLE OF CONTENTS.............................
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1 Ope ration s....................................................
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O1 Conduct of Operations...........
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01.1 General Observations......................
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O3 Operations Procedures and Documentation.
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03.1 Altemate Shutdown Cooling Method Walkdown................. 2
Miscellaneous Operations issue.....................
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08.1 INPO Evaluation Report Review
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08.2 (Open/ Closed) Licensee Event Report 50-354/99-001..
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II. Maintenance.....
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M1 Conduct of Maintenance.....
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M1.1 Vital Bus inadvertently De-energized During Surveillance.....
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M1.2 Surveillance Test Failure...
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M1.3 Refuel Floor and Under Vessel Activities..........
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M8 Miscellaneous Maintenance issues.................
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M8.1 (Closed) UnrescIved item 50-354/98-08-01....
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M8.2 (Open) Violation 50-354/98-80-02........
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M8.3 (Open/ Closed) LER 50-354/99-002....
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Ill. Engineering.......
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E2 Engineering Support of Facilities and Equipment.
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E2.1 Control Rod Blade Cracking and Blister............
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E2.2 Shutdown Cooling Suction Line isolation Valve Repairs
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E2.3 Inservice inspection
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E2.4 Modifications and Mechanical Stress improvement
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E2.5 System Engineering Support of Station Activities..
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E8 Miscellaneous Engineering issues...
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E8.1 (Closed) Violation 50-354/98-05-05...
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IV. Plant Support......
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R1 Radiological Protection and Chemistry (RP&C) Controls.
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.R4 Staff Knowledge and Performance in RP&C......................... 17 R4.1 Diver Injured During Modification Work..................... 17 V. Management Meetings.......................
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X1 Ept Meeting Summary................................
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X2 Management Meeting Summary...........
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i Report Details l
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Summarv of Plant Status i
Hope Creek operated continuously until February 13,1999, when refueling outage 8 (RF08)
commenced.
1. Operations
Conduct of Operations 01.1 General Observations a.
Insoection Scope (71707)
The inspectors observed numerous control room activities associated with the plant shutdown, core offload, and refuel outage.
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Observations and Findinos PSE&G organized work coordination teams for each of the major evolutions associated with refuel outage 8. The work coordination teams were led by senior reactor operators (SROs) and included reactor operators (ROs), equipment operators and engineers. The work coordination teams were not normally assigned shift duty coverage. The teams'
responsibilities included preparing for and executing each assigned major evolution.
The inspectors observed some of the evolutions performed by the work coordination teams. The inspectors judged that PSE&G had improved outage work performance compared to previous outages, and organizing the teams appeared to have contributed to this improvement. Each team was well prepared many hours before conducting an evolution. Good coordination existed between the operators assigned shift duties and the work coordination teams. Each evolution team was able to incorporate lessons
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learned into repetitive and lengthy activities.
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Conclusions PSE&G organized work coordination teams for major refuel outage activities, which
included SROs, and these teams appeared to have contributed to improved PSE&G outage performance.
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03 Operations Procedures and Documentation 03.1 Alternate Shutdown Coolina Method Walkdown a.
Inspection Scope (71707)
l The inspectcrs performed a detailed walkdown of procedures and portions of the residual heat removal (RHR) system to verify availability of the designated attemate shutdown cooling method using the RHR heat exchanger cross-tie.
b.
Observations and Findinos The RHR subsystems are provided with large cross-tie and manual valves that allow flow from the C RHR pump to be aligned through the A subsystem RHR heat exchanger. A
- similar modification was installed for the D RHR pump in the B RHR subsystem. At times
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operators considered this ahemate method of shutdown cooling available for technical specification requirements.
l The inspectors verified that the operating procedure for establishing attemate shutdown cooling (SDC) was adequate. The NRC inspectors identified minor problems that could have delayed establishing alternate SDC. Interlock override keys for RHR pump suction valves were not well labeled or controlled in the work control center. Scaffold installation was necessary to operate a large manual valve,1BC-V043, above the torus for
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attemate SDC from the B RHR subsystem. The scaffold was present, but had been
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temporarily installed for unrelated work activities The inspectors discussed these problems with the operations staff superintendent (OSS). The OSS initiated administrative controls to ensure that scaffold would be installed when the B RHR subsystem is credited for attemate SDC. The OSS also initiated corrective actions to l
improve the control of interlock override keys.
c.
Conclusions The procedures and conditions for establishing alternate shutdown cooling were adequate. The inspectors identified minor problems that could have delayed establishing alternate shutdown cooling, and PSE&G promptly corrected the problem?
Miscellaneous Operations issue 08.1 INPO Evaluation Report Review (71707)
The inspectors reviewed the report issued by the Institute for Nuclear Power Operations (INPO). The December 31,1998, report documented the results of an onsite evaluation conducted on November 9 - 19,1998. No safety issues were identified as a result of this review.
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i 08.2 (Open/ Closed) Licensee Event 3gport 50-354/99-001: Unolanned RCIC Inocerability:
a.
Insoection Scope (92700. 71707)
The inspectors reviewed the conditions surrounding and the intended corrective actions for a reactor core isolation cooling (RCIC) system inoperability.
b.
Observations and Findinas
On January 11,1999, control room operators received an annunciator associated with l
the RCIC system isolation actuation instrumentation. Maintenance technicians l
responding to the problem discovered a blown logic circuitry fuse. SROs entered l
technical specification action statement 3.3.2, b.2, action 23, isolated the RCIC steam
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supply, declared RCIC inoperable, and made a four hour event notification to the NRC.
The operations manager determined that complying with technical specification action
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statement 3.3.2, b.1.c would have been more appropriate and with less plant risk.
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Action statement b.1.c. required the affected isolation logic channel be placed in a trip condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Following the attemative action statement b.1.c would have maintained the steam supply valves open and RCIC operable.
PSE&G initiated a corrective action item to revise the technical specification administrative procedure with guidance on inoperable isolation actuation instrumentation.
Maintenance technicians promptly identified and replaced a faulty circuit power supply that caused the blown fuse.
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. Conclusions i
Following operator actions to isolate RCIC in response to a blown fuse in isolation circuitry, the operations manager correctly determined that the technical specification i
action statement to trip the affected channel was more appropriate. PSE&G initiated corrective actions to improve procedural guidance and prevent recurrence.
II. Maintenance M1 Conduct of Maintenance M1.1 Vital Bus inadvertentiv De-eneraized Durina Surveillance
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Inspection Scooe (62707. 71707)
The inspectors reviewed PSE&G's response and follow-up after a technician error during testing inadvertently de-energized a safe +v related 4 kV vital bus. The inspectors interviewed operators and technicians, and reviewed and observed portions of PSE&G's recovery action plan.
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Observations and Findinas On February 19,1999, during a degraded voltage test for a supply brsaker on the D 4 kV vital bus, the bus was inadvertently de-energized. The breaker trip was the result of a
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human performance error during the 18 month degraded voltage test. While connecting an ohm meter to a second set of test points, the relay technician incorrectly disconnected one test lead and reconnected it to the next (desired) location but he left the other lead still connected to the first set of test points. PSE&G subsequently confirmed that this con'iguration simulated a trip signal to the supply breaker.
l At the time the plant was in operational condition 5 (refueling), core offload activities were in progress, and the A and C electrical and safety equipment channels were protected and were operable consistent with the outage risk plan. The redundant supply l
breaker for the D 4 kV vital bus did not close due to the planned maintenance on a DC
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bus that provided control power for the breaker, and the associated emergency diesel generator was tagged out of service for scheduled maintenance. Accordingly, when the l
primary supply breaker tripped due to the error, no attemate power supply was available to maintain the bus energized. Several components were affected by the loss of this vital bus including the reactor building ventilation system, the reactor water cleanup system and the control rod position indication system. The operating RHR pump (A) remained in shutdown cooling configuration and was not affected by the loss of the vital bus.
The inspectors determined that PSE&G actions in response were appropriatc. The reactor building ventilation system had been in service to maintain a negative pressure in j
the reactor building, thereby assuring secondary containment integrity. Upon loss of the ventilation system (due to damper isolation), operators suspended core alterations in accordance with the action requirements of technical specification 3.6.5.1.b. Operators j
placed the filtration, recirculation, and ventilation system in service to maintain a negative
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pressure in the reactor building. PSE&G formed a team led by an operations supervisor to develop a plan to restore the D 4 kV bus and associated loads. The plan was successfully implemented and core alterations resumed on February 20.
The inspectors reviewed the operator response to the electrical bus trip and toured the affected areas of the plant. The relay technicians had properly terminated the surveillance activity and backed out of the test procedure. The inspectors also observed portions of PSE&G's troubleshooting and recovery activities, and found them to be systematic and well controlled. In response to the initial performance error, PSE&G discussed this event including self-checking techniques with relay technicians.
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Conclusions
' The D 4 kV vital bus was inadvertently de-energized due to a performance error by a l
relay technician while performing a periodic surveillance. PSE&G responded appropriately to this challenge, subsequently evaluated the event appropriately, and restored the affected plant equipmen.
M1.2 Surveillance Test Failure a.
Inspection Scope (62707)
i The inspectors reviewed a failed surveillance performed on a reactor recirculation (RR)
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system excess flow check valve. The inspectors interviewed personnel and reviewed PSE&G's evaluation and corrective actions.
b.
Observations and Findinas On February 2,1999, instrument technicians performed a surveillance for an excess flow check valve (EFCV) associated with the B RR pump high pressure seal. The test failed to meet the acceptance criteria. Upon further review, PSE&G identified several performance problems, including some problems while implementing corrective actions for the failed surveillance.
The inspectors reviewed the details associated with the test planning, coordination, and performance. The performance problems are summarized below.
Operators recognized that flow from the low pressure (upper) RR pump seal
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might be insufficient to seat the EFCV in the existing plant configuration (full power) and that only the high pressure (lower) seal EFCV should be tested. The operators deferred the low pressure seal test. However, the instrument i
technician and his supervisor incorrectly assumed that the upper seal was the high pressure seal. Accordingly, they retrieved the work order associated with the low pressure seal EFCV.
An operations supervisor failed to adequately review the incorrect work order
presented to him and authorized work to be performed on the low pressure RR pump seal EFCV.
The low pressure RR pump seal EFCV failed to close during the test. In
response, operators were directed to close the affected EFCV isolation valve in accordance with technical specification action requirements. However, the isolation valve labels for the high and low pressure EFCVs were reversed and the operator isolated the instrument line associated with the high pressure RR pump seal. Operators observed the high pressure RR seal pressure indication drifting from about 1000 psig to about 800 psig over several hours and recognized that the wrong instrument line had been isolated.
In response to the abnormal pressure indication on the high pressure RR pump seal, operators unisolated the high pressure seal instrument line and isolated the low pressure instrument line. The labeling deficiency was corrected. Also, operators checked the labels for an additional 32 EFCV isolation valves and found no additional labeling deficiencie !'
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6 After the test failure and proper isolation, system engineering evaluated the test and prior history. A similar test failure occurred in 1996 during an on-line test. The check valve is designed to close if flow exceeds 1.5 gpm. However, while operating at power and with the high pressure seal intact, the expected flow in the low pressure seal line would be less than 1.0 gpm. Therefore, the EFCV would not have been expected to isolate, and the test for these particular valves during operation (without the use of a test device)
would be invalid. Engineering recommended to consider the EFCV operable and fully capable of performing its design function.
The inspectors found PSE&G's evaluation of this event to be thorough and accurate.
The corrective actions taken and planned were appropriate. Although technical specification action statements were entered, no technical specifications were exceeded.
The inspectors determined that the testing of low pressure RR pump seal demonstrated poor attention to detail.
c.
Conclusions Due to several inattention to detail errors, an excess flow check valve was tested on a low pressure reactor recirculation pump seal rather than the desired high pressure excess flow check valves. As the conditions were not suitable for testing the low pressure line, the test failed and challenged plant staff and equipment. In responding to the test failure, equipment operators isolated the incorrect instrument line for several hours due to a labeling problem. No plant transient resulted from these errors, and PSE&G identified the errors and implemented acceptable corrective actions.
M1.3 Refuel Floor and Under Vessel Activities a.
Insoection Scope (62707. 71707)
The inspectors observed maintonance activities on the refuel floor and control rod drive mechanism (CRDM) exchanges from the CRDM control room.
I b.
Observations and Findinos The inspectors observed portions of:
reactor vessel head lift
fuel moves to the spent fuel pool
control rod guide tube vacuuming
control rod drive mechanism exchanges
control rod blade inspections
local power range monitor detector replacements a
in each evolution, the inspectors determined the activities were closely supervised by both PSE&G first line supervision and contractor supervision, system engineers were very involved, and coordination with the main control room was evident. Each evolution was performed in accordance with plant procedures and the Updated Final Safety
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Analysis Report was consuited when questions developed regarding fuel handling and refuel floor activities.
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Conclusions PSE&G safely performed numerous refuel floor activities. Supervisors, technicians and engineers all pursued error free operations during the performance of various tasks.
M8 Miscellaneous Maintenance issues
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l M8.1 (Closed) Unresolved item 50-354/98-08-01: Inservice Testina of Standbv Liauid Control Pumps a.
Inspection Scope (92902)
The inspectors reviewed PSE&G's actions following the NRC's identification of a testing methodology discrepancy associated with the standby liquid control (SLC) system pumps.
b.
Observations and Findinas in NRC Inspection 50-354/98-10, the inspectors had documented updated information for this item including PSE&G's corrective actions. PSE&G had implemented acceptable
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corrective actions to fully comply with Section 5.6 of ASME Operation and Maintenance of Nuclear Power Plants (OM - 1987), by establishing a two minute stabilization period before measuring the pump flow rate data for the SLC pumps. PSE&G implemented procedure changes and had satisfactorily conducted subsequent pump tests.
The inspectors determined that PSE&G had previously failed to meet Section 5.6 of ASME OM - 1987. Follow-up testing using the proper methodology confirmed prior and continued operability of both SLC pumps. This Severity Level IV violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the Hope Creek corrective action program as Action Request 981021253. (NCV 50-354/99-01-01)
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Conclusions The inspectors reviewed PSE&G's response to the NRC's identification of an inappropriate testing methodology of the standby liquid control system pumps, concluded that a violation had existed, and found that PSE&G's corrective actions were acceptable.
i M8.2 (Open) Violation 50-354/98-80-02: Item #3 of this violation was the failure of PSE&G's corrective action program to preclude repetition of hydrogen-oxygen containment analyzer reagent gas bottle pressures falling below minimum allowed values. The inspector verified that PSE&G developed sufficient controls in surveillance procedures to prevent this problem from recurring. Item #3 of this violation is close.
M8.3 (Open/ Closed) LER 50-354/99-002: Missed Technical Soecification Surveillance a.
Inspection Scope (62707. 90712)
The inspectors performed an onsite inspec' ion and verified PSE&G's corrective actions described in a licensee event report (LER) nr a missed technical specification surveillance, b.
Observations and Findinos On February 6,1999, a senior reactor operator identified that a monthly flowpath verification surveillance required by technical specification 4.7.1.1.a for the B safety auxiliaries cooling system (SACS) was not performed as required. The inspectors determined that the senior reactor operator displayed good attention to detail in identifying this issued and PSE&G responded promptly and appropriately to evaluate and correct the problem. Upon identification on February 6, operators declared the B SACS loop inoperable. Within about one hour, operators satisfactorily completed the flowpath verification and declared the system operable.
PSE&G's evaluation identified that both the December 1998 and the January 1999 flowpath verifications were not performed for the B SACS loop. They determined the cause to be personnel error in that operations shift personnel misinterpreted the work package component identification and component description to apply to only the A SACS loop. The December and January verifications had been scheduled during work
weeks dedicated to channels A and C (loop A), and the operators incorrectly believed that only the section related to the A SACS loop was to be performed. The same operations shift missed the two consecutive flowpath verifications, and the particular individuals had not been hvolved with this surveillance prior to the December 1998 performance.
PSE&G reviewed similarly scheduled and identified surveillances for the prior six
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months. No additional discrepancies were identified. In addition, PSE&G made changes to recurring task items to clarify whether single or multiple loop testing is required. Also, the shift personnel were held accountable for their inappropriate actions.
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The inspectors determined that PSE&G's corrective actions were appropriate for this violation of technical specification 4.7.1.1.a. This non-repetitive, PSE&G identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-358,199-0102)
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Conclusions
' A senior reactor operator alertly identified that other senior reactor operators had failed to properly perform a technical specification flowpath verification for the safety auxiliaries cooling system. PSE&G appropriately evaluated and corrected this missed surveillance issu.
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Engineering Support of Facilities and Equipment E2.1 Control Rod Blade Crackina and Blister a.
Insoection Scope (62707. 37551)
The inspectors reviewed PSE&G's inspection program for Asea Brown Boveri (ABB)
control rod blades (CRB) and observed control rod blade inspections from the refuel floor, b
Observations and Findinas PSE&G has performed visualinspections on ABB CRBs each refueling outage in accordance with ABB service guidelines. The visual inspections were intended to identify CRB cracking that developed from neutron exposure. If cracks were identified, the CRB was replaced. CRB cracking on ABB blades had been experienced in the industry since 1991. The cracking had no safety significance provided the service guidelines were followed and CRB replacements made.
PSE&G performed a CRB inspection on the center control rod, position 30-31. Rod 30-31 experienced difficulties in withdrawing on March 28,1998, and control room operators, not knowing the source of the problem, conservatively fully inserted rod 30-31.
(See NRC Inspection Report 50-354/98-02 Section 04.1 for further details). Rod 30-31 remained fully inserted and disarmed for the remainder of the operating cycle. The CRB visual inspection on rod 30-31 was intended to identify cracks as well as any other problems that may have been related to the March 28 event. An ABB representative.
was also present. The reactor engineers identified blade cracHng as well as a raised blister on both sides of one wing. The reactor engineers and the ABB representative recognized the safety significance of the blister, but could not readily explain its presence. The engineers also could not immediately relate the blister to the March 28, 1998 problems with moving rod 30-31. ABB be0an an evaluation on the CRB blister in accordance with 10CFR21.
The inspectors observed the reactor engineers perform the visual examination on CRB 30-31. The inspectors considered the engineers' examination techniques to be thorough. Followup actions for the cracking and blister were conservative and appropriate, c.
Conclusions Thorough follow up in refuel outage 8 on problems experienced during a control rod withdrawal in March 1998 identified a problem with the control rod. blade. The control rod had remained fully inserted and disarmed. Reactor engineers identified a control rod
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blade blister. The safety significance was understood and the control rod blade vendor began a 10CFR21 evaluation.
E2.2 Shutdown Coolina Suction Line Isolation Valve Recairs a.
Inspection Scope (37551. 62707)
The inspectors reviewed PSE&G's corrective maintenance efforts to eliminate the source of leakage past pressure isolation valves from the reactor coolant system to the shutdown cooling suction line. The inspectors attended the maintenance pre-evolution brief and reviewed contingency actions for restoring the shutdown cooling line and the fuel pool cooling assist mode.
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Observations and Findinos i
Seat leakage past pressure isolation valves (PlV) from the reactor coolant system to the shutdown cooling suction line caused pressure to increase in the residual heat removal (RHR) system. The RHR system is rated at a lower pressure and the PlVs are designed to isolate the RHR system and SDC suction line from the higher reactor coolant system pressure while the plant is at power. The operators were alerted to the increased
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pressure by a control room annunciator. The pressure was vented locally using manual valves in the RHR system. These conditions persisted for several days after Hope
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Creek returned to power operations and after using the RHR system in the SDC mode.
The frequency of the high pressure conditions decreased and eventually did not exist several days after the plant started up. The details of these problems after returning to power from refuel outage 7 were discussed in NRC Inspection Report 50-354/98-01.
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PSE&G developed work orders and a work plan for both shutdown cooling line PlVs to be worked in refuel outage 8. The work was scheduled during the full core offload.
Work performed on the outboard PlV presented the greatest plant risk; the fuel pool cooling assist mode of RHR would not be available while the outboard PlV was disassembled.. The engineers developing the work plan considered the additional risk
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while the outboard PlV was unavailable. Work was not allowed to begin on the outboard PlV unless as-found seat leakage tests positively indicated a problem. The seat leakage tests indicated that the inboard PlV needed repairs, but the outboard PlV did not need work. Engineers could not yet explain how the leakage went past the outboard PlV to increase SDC suction line pressure, but considered thermal effects to be a factor.
PSE&G engineers closely followed the inboard PlV maintenance and ensured that the maintenance was performed in accordance with vendor technical guidance.
The pre-evolution brief was attended by multi-disciplined team of technicians and supervisors, who would have had a part in restoring the shutdown cooling suction line during a sustained loss of the normal fuel pool cooling system. The engineers were well prepared for an effective pre-evolution briefin.
c.
,Qonclusions PSE&G engineers carefully considered and minimized the plant risk during valve maintenance on the shutdown cooling suction line. The engineers were involved during the maintenance to alleviate a leakage problem and ensured that the maintenance was performed in accordance with vendor technical guidance.
E2.3 Inservice insoection (ISI)
a.
Inspection Scope (73753)
The inspectors reviewed plans and schedules for the current ISI interval (first outage, first period, second interval) to verify compliance with the requirements of ASME Section XI,1989 edition, and 10 CFR 50.55a(g). Areas inspected included ASME Section XI ISI program coverage, qualifications and certifications of the nondestructive examination (NDE) personnel, NDE procedures, results of NDE, and oversight of NDE contractors. In addition, the inspectors observed selected NDE activities.
b.
Observations and Findinas The ISI procedures being used were approved by the ISI contractor, PSE&G and the authorized nuclear inspector, and were in accordance with the ASME Code requirements. The work performed was thorough and of sufficient extent to determine the integrity of the components inspected. The inspectors reviewed the ultrasonic, penetrant and magnetic particle test procedures used by NDE personnel and found them to be adequate for the NDE tasks performed. NDE contractors performed the ISI examinations and provided oversight, which included and approval of personnel and procedure qualifications, monitoring of activities and acceptance of test results. The inspection implementation was consistent with the approved procedures except as noted below. The inspector reviewed Personnel qualification records for six NDE inspectors and found them to be in compliance with the ASME Code requirements. The inspectors evaluated oversight of contractor NDE and Mechanical Stress improvement Process (MSIP) activities by review of the oversight reports, weld travelers and the summary logs which documented appropriate PSE&G involvement and control of the NDE and MSIP contractor activities.
The inspectors noted that during the calibration process in preparation for UT examination of the recirculation pipe-to-elbow weld, the examiner commenced the calibration using a couplant material from a container which had no markings or identification of any kind. The inspectors called this to the attention of the examiner, who ceased the calibration process and procured couplant material which was fully identified and traceable to larger bulk containers that had been tested in accordance with specified requirements. The identification was sufficient to permit verification that the couplant was in compliance with procedure requirements. The identification requirement is specified in the NDE contractors procedures (54-1S1-836-00, calibration data sheet and 54-ISI-60-11, control of consumables).
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An action request was promptly initiated to identify the condition. The unmarked containers were removed from the location where the calibration activity was being performed. Corrective actions included further examination of other consumable products used in the examination processes. This resulted in the discovery that one lot of penetrant material being used was not listed as acceptable for use. A second action request was also promptly initiated. The inspectors concluded that PSE&G and contractor had reacted promptly and appropriately to address these conditions. The failure to properly control calibration material is a violation of minor significance and is not subject to formal enforcement action.
The inspectors reviewed the video recordings of in-vessel inspection of the core spray piping, piping welds, T boxes, spargers and structural supports of these members. The inspectors reviewed the indications identified and reported as " cracks" in the core spray header bracket (lower tack weld). The crack in the lower tack weld of the core spray header bracket was originally identified in January 1995 (RFO 6). The condition was determined to be acceptable as is at that time based on the analysis that the bolt is the structural member and the tack welds (one upper and one lower) are installed to prevent the bolt from backing out. There was no evidence this has occurred. The disposition provided for subsequent inspection of the tack welds at each outage for the next two
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cycles (RFO 7 and 8). The condition was evaluated during this outage by PSE&G with j
the conclusion that the condition had not deteriorated further and continued to be I
acceptable as is. The indication was identified for examination during each subsequent outage. The inspectors reviewed the original disposition and technical justification for acceptance of the original condition and concluded that the initial disposition was i
appropriate at this time.
The inspector found examination data and documentation to be in accordance with the ISI procedures and ASME Code requirements. NDE personnel performing inspections had properly identified and recorded indications and, where applicable, had processed and re-examined those indications evaluated as nonrelevant. The tracking of ISI examination results indicated that the ISI program was in compliance with the ASME Code,Section XI for the specified period.
c.
Conclusions The inspectors concluded that inservice inspection had been performed acceptably and included acceptable ASME program coverage, qualified personnel, approved procedures, proper implementation, appropriate examination documentation, and PSE&G oversight. The inspections were thorough and of sufficient extent to determine the integrity of the components inspected.
E2.4 Modifications and Mechanical Stress Imorovement a.
Insoection Scope (73753)
The inspectors reviewed the procedures developed for the application of the Mechanical Stress Improvement Process (MSIP). This process was planned for application at 17
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weld locations during the outage. The locations included nozzle to safe end welds primarily of core spray and recirculation inlets. The inspectors also reviewed training i
records for personnel trained in the application of the process, interviewed applications i
personnel, and examined the tools and equipment used to exert the controlled hydraulic force on the components.
The inspectors also observed the installation of new core spray (CS) and residual heat removal (RHR) pump suction strainers in the torus.
b.
Observations and Findinas The MSIP process improves the residual stress distribution in a weldment by reducing or l
eliminating the residual tensile stresses at welded regions susceptible to stress corrosion
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cracking. The process is accomplished by a slight permanent contraction of the pipe in the vicinity of the weldment. This is achieved by using hydraulic activated tools.
The procedures for this special process presented a good description of the process and clearly stated the objectives, including adequate provisions to perform the process with precautions and prerequisites spelled out prior to advancing subsequent steps.
Documentation and tracking mechanisms were in place with hold points established at
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critical steps. Training requirements were extensive with emphasis on the mock up training. This was appropriate because the success of the process was dependent on accurate instalhtion of the equipment prior to the application of pressure at the designated location.
The inspectors observed the application of the process on two recirculation inlet nozzles
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and found the work to be well planned, coordinated and executed. Oversight of the work was very good with an appropriate emphasis on accuracy of equipment placement, verification of hold points, and verification that application of the pressure was below the
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maximum specified in the record. Appropriate measures were evident to reduce the
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radiological personnel exposure when in close proximity to the reactor pressure vessel.
. The results of the process were verified and documented on the MSIP Performance and Verification Record. The inspectors verified that personnel who executed the process had been trained, all haid points had been recognized, and the required change in pipe circumference had been achieved.
The suction strainer hatallation project was in progress and was evaluated by the inspectors. The inspt ctors observed the control and coordination of activities in the staging areas and wittin the torus proper. The work underway at the time was orderly and well controlled witn significant PSE&G involvement evident at the work locations.
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Conclusions
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The application of the Mechanical Stress improvement Process (MSIP) and the suction strainer installation project were well planned, coordinated and being executed with PSE&G involvement and oversight. Control of the MSIP activity was thorough, including
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training, equipment placement, assembly and disassembly, and application of the pressure. Quality control and documentation were appropriate.
t E2.5 System Enaineerina Support of Station Activities a.
Inspection Scope (37551)
The inspectors reviewed several activities requiring system engineering support. The inspectors observed portions of the activities and reviewed associated documentation.
b.
Observations and Findinas The inspectors reviewed several station activities that were supported by system engineers, including technical evaluation of the following:
Control rod drive pump trip;
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Emergency diesel generator indicated load swings during a surveillance; and
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In-service test failure on the A service water system pump.
a The inspectors observed implementation of investigation plans developed by system engineering and reviewed the associated engineering evaluations. In each instance the plan developed was systematic and focused a proper safety perspective related to component and system operability. The inspectors found the plans to be implemented safely, and the system engineers properly evaluated the results obtained. The inspectors noted that some of the above problems were repeat problems for which causes and corrective actions have not yet been identified. For example, the continued control rod drive pump trip investigation did not identify any problems, although the
. pumps had experienced this trip phenomenon for several months. The inspectors found that continued monitoring and investigative efforts were being developed by system engineering.
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Conclusions System engineers provided good support in developing investigation plans for observed equipment problems.
E8.
Miscellaneous Engineering issues E8.1 (Closed) Violation 50-354/98-05-05: RHR System Not Available Durina Refuelina to Auament Fuel Pool Coolina as Stated in UFSAR a.
Inspection Scope (92903)
l The inspectors reviewed PSE&G's actions following the NRC's identification that PSE&G f
did not maintain the residual heat removal (RHR) system in operation or available to l
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augment the fuel pool cooling and cleanup (FPCC) system during a refueling outage (RFO3) in December 1990. The inspectors reviewed documentation and decay heat removal activities for the current refueling outage (RFO8).
b.
Observations and Findinas PSE&G attributed the cause for this violation to be inadequate outage reviews and controls procedures. PSE&G did not compare the attemate decay heat removal methods with those described in the UFSAR.
PSE&G implemented corrective several steps to address the violation. The interaction among the responsible departments (nuclear fuels, system engineering, outage management) was proceduralized to specify the development of decay heat load estimates and heat-up curves for outage planning. The procedure guidance also included verification of sufficient decay heat removal capability for the duration of the outage schedule. In accordance with 10 CFR 50.59, PSE&G also evaluated the decay heat removal method for the full core offload during refueling outage RFO7 that was completed in December 1997. The safety evaluation concluded that an unreviewed safety question was not involved.
The inspectors reviewed PSE&G's corrective actions and found them to be acceptable.
In addition, the inspectors reviewed PSE&G's decay heat removal analysis summary and associated graphs for the full core offload activities for the current refueling outage (RFO8). The inspectors also verified proper operation and availability of decay heat removal systems (residual heat removal, fuel pool cooling and cleanup) during RFO8.
The inspectors concluded that PSE&G's actions properly addressed this item. This item
!s closed.
c.
Conclusions The inspectors reviewed PSE&G's actions in correcting the failure to operate the residual heat removal system consistent with the UFSAR assumptions during a prior refueling outage, and found the corrective actions to be acceptable.
IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls l
a.
Inspection Scope (83750)
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A health physics inspection during refueling outage RF08 was conducted. Areas of inspection focus were based on the following regulatory requirements from 10 CFR Part 20:
20.1101 Radiation protection program 20.1601 Control of access to high radiation areas
16 20.1602 Control of access to very high radiation areas l
20.1902 Posting requirements 20.1904 Labeling containers 20.2103 Records of surveys The inspectors directly observed in-process work in the radiologically controlled areas (RCA), reviewed pertinent documents including surveys, radiation work permits (RWPs)
and as low as is reasonably achievable (ALARA) reviews, and interviewed with cognizant personnel. Emphasis was placed on direct observations of outage related work, especially work on the refueling floor, and in the drywell, torus and turbine building.
b.
Observations and Findinos For the RF08 a station occupational exposure goal of 206.626 person-rem was established by the station ALARA committee. Work incorporated into this exposure psal included: reactor disassembly, full core off-load, refueling and reactor reassembly; emergency core cooling system (ECCS) suction strainer replacement; and, replacement of control rod drives. The outage goal was based on a calculation of identified work, hours in the radiologically controlled area (RCA), and the effective dose rate for the work area. No contingency dose was included in the outage goal for emergent work.
The radiation protection department placed a supervisory level employee into the outage planning organization, helping to ensure that appropriate radiological controls were incorporated into the outage planning process. ALARA technicians were assigned prior to the outage to prepare work reviews, and during the outage were first assigned to supervise the installation of shielding packages, and then to perform in-process work reviews at designated areas. Both of these activities were notable improvements in the
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radiological outage planning and implementation process, as compared to the previously
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noted program in place during RF07 (See NRC Inspection Report 50-354/97-07).
Refueling work was budgeted for 36 person-rem for RF08. Work on the refueling floor was being performed by a contractor, who also provided their own radiation protection technicians. Contractor performance was being monitored by assigned station personnel overseeing this work. During reactor disassembly, one airborne contamination event occurred inside the cavity. Similar problems liad occurred during previous outages, and were believed to have been caused in part by repeated recontamination of insulation packages and vessel surfaces. No internal uptakes of radioactive material occurred as a results of this event. For the outage a budget of approximately 7 person-rem had been included for cavity decontamination during reactor reassembly.
Work for replacement of the ECCS suction strainers principally involved diving operations in the torus. While general area dose rates on the torus internal platform ranged as high as 40 millirem per hour, more significant dose ~ rates ranging up to several hundred millirem per hour were identified in portions of the torus under water, coming
' from debris deposits, especially along the inner annulus. Effective radiological controls were established to minimize radiation exposure for both the divers and platform Io
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workers, with the divers utilizing teledosimetry systems for dose monitoring. The established dose goal for this work was approximately 31 person-rem.
Y'ork in the 6;ywell, including under-vessel replacement of CRDs was effectively udtrolled but generally hampered by the crowded conditions inside the drywell. Plant design for this facility necessitated extensive climbing over and on plent equipment and piping in order to reach work locations. Shielding was difficult in part oue to physical limitations. Shielding effectiveness was limited by the close proximity of multiple radiation sources in a confined space. Generally effective controls were utilized to control work and minimize exposures. These controls included detailed survey maps of drywell areas, pre-job briefings given by dedicated radiation protection technicians, and extensive use of informational postings for exposure minimization.
Minor contamination control issues identified by the inspectors were promptly resolved by PSE&G. Osee problem in the foreign material exclusion (FME) program was also identified on the refueling floor. In the midst of the outage, responsibility for manning the FME control desk on the refueling floor was taken over by the radiation protection staff.
When questioned by the inspectors, one of the FME attendants was not aware of where the FME zone was located on the refueling floor. A review of the training package presented to each person assigned to the FME program revealed that while the training included a detailed review of the FME program and its implementation, it did not show the exact location of the FME zone on the refueling floor. PSE&G undertook actions to ensure that all personnel assigned this task were aware of FME boundaries.
c.
Conclusi201
'A generally effective radiation protection program existed during outage work. Exposure
- goals had been established based on reasonable assumptions of time to complete work tasks and the specific effective dose rates of the work areas. Extensive use of informational Al ARA postings throughout the radiological controlled area erspred workers were awara of the radiological conditions all work areas.
R4 Staff Knowledge and Performance in RP&C R4.1 Diver Iniured Durina Modification Work
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a.
Insoection Scope (71707. 71750)
The inspectors reviewed PSE&G's response and follow-up activities for an injury to a j
diver in the suppression pool (torus) during emergency core cooling system (ECCS)
i stra;ner modification underwater work.
b.
Qhservations and Findin.g5 On Febnsary 25,1999, a contractor worker was injured while performing underwater maintenance in the torus using a high pressure torque wrench. The machine engaged and a support bar pinched the diver's finger. The diver lost the tip of his index finger and i
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immediately left the work area and was transported to a local hospital. This injury was caused by human error.
There were two dive stations in operation at the time of the incident. Each had a dive master (in charge of diving operation), a diver, and a tender. The tender helped the~ diver by moving hoses and masisting as requested. Prior to this injury, the tender also controlled the operation of the hydraulic pump and valves that energized the high pressure torque wrench. Communications were established with the dive master, diver, and tender via hard wire.to the diver and radio transmitter to the tender (dive master hcadset had a duplex communication device). Commands to the diver or tender could only came from the dive master. The diver and tender could not communicate directly.
The diver at dive station #1 was in the process of changing the socket for torquing operations. The tender at dive stction #1 heard a command over his communications headset to energize the machine, and did so without any further communication or verification. He apparently heard this command via cross channel interference from the dive station #2 dive master. The tender at dive station #1 en0 aged the high ;vessure torque wrench machine; however, the #1 diver was not prepared. This im er communications was the cause for the injury to diver #4 PSE&G later er
,ned intermittent cross channel interference between the two frequencies of rr.no communications, which was a contributing causal factor.
The injured diver was transported to a local hospital. Because radiological controls technicians were not able to do' a complete frisk of the injured finger, PSE&G reported the offsite transport of a potentially radioactively contaminated individual to the NRC in accordance with 10 CFR 50.72 reporting requirements. A subsequent survey found that the individual was not contaminated. His finger tip was later retrieved by co-workers and was transported to the hospital as if it were contaminated. A medical decision was made to not reattach the finger tip, and it was transported back to the site medical facility for a!>posal (finger tip was confirmed to be not radioactively contaminated).
The inspectors reviewed PSE&G's response and evaluation of this incident. All diving operations were suspended until the incident was evaluated arm discussed with all diving crews. PSE&G eliminated the tender from the communication process, so only the dive master and diver would communicate via a hard wire system and the dive master would operate the equipment. One radio set was removed from operation to prevent further interference. Also, PSE&G transmitted the details for this event as an operating experience report to others in the nuclear industry, and this event is planned to be -
included as part of contractor training for the upcoming 1999 Salem outages. PSE&G confirmed that the contractor personnel had received training regarding rules and expectations for work such as attention to detail and use of repeat backs in communications..The inspectors determined that PSE&G supervisors missed an -
j opportunity to identify the inadequate communications by the contractor workers as the i
post-event review identified that communications were weak during earlier stages of the i
maintenance activity. ~ The inspectors concluded that PSE&G respe nded appropriately to this incident.
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c.
Conclusions PSE&G responded quickly and appropriately to an injury to a contractor performing underwater maintenance in the torus and effectively evaluated the causes. The injurf was caused by human error by dive crews in that communications were inadequate.
Causal factors that contributed to the incident were cross-channel interference and a missed opportunity by PSE&G supervisors to previously identify inadequate communications.
V. Manaaement Meetinas X1 Exit Meeting Summary At the conclusion of the inspection on March 12,1999, the inspectors presented the inspection results to PSE&G management. led by Mr. Mark Bezilla, who acknowledged the findings.
X2 Management Meeting Summary i
On January 26,1999, a meeting was held between NRC and PSE&G management at the NRC Region I office to discuss major outage work activities and associated risk assessment planned for Hope Creek. Lessons leamed from previous outage work and initiatives taken by PSE&G to improve outage readiness and implementation of work were also discussed. The overhead transparencies used by PSE&G during this meeting are included as Attachment 1 to this report.
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INSF ECTION PROCEDURES USED iP 37551:
Onsite Engineering IP 61726:
Surveillance Observations IP 62707:
Maintenance Observations IP 71707:
Plant Operations IP 71750:
Plant Support Activities IP 73753:
Inservice inspection IP E3750:
Occupational Radiation Exposure i
IP S0712:
In-Office Review c.t written Reports of Nonroutine Events at Power Reactor Facilities IP 92700:
Onsite Followup of Written Reports of Nonroutine livents at Power Reactor Facilities IP 92901:
Followup - Plant Operations IP 92902:
Followup - Maintenance IP 92903:
Followup - Engineering IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors ITEMS OPENED, CLOSED, AND DISCUSSED Opened / Closed 50-354/99-01-01 NCV inappropriate testing methodology of the standby liquid control system pumps. (Section M8.1)
50-354/99-01-C 2 NCV Missed technical specification surveillance. (Section M8.3)
50-354/99-001 LER Unplanned inoperability of the reactor core isolation cooling system. (Section 08.2)
50-354/99-002 LER Missed technical specification surveillance. (Section M8.3)
C gned 50-354/98-05-05 VIO Residual heat removal system not available during refueling to augment fuel pool cooling as stated in UFSAR.
(Section EB.1)
50-354/98-08-01 URI Inservice testing of standby liquid c arol pumps. (Section M8.1)
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Discussed 50-354/98-80-02 VIO Failure of the corrective action program to preclude repetition of hydrogen-oxygen containment analyzer reagent gas bottle pressures falling below minimu.1 allowed values. (Section M8.2)
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LIST OF ACRONYMS USED ABB Asea Brown Boveri ALARA As Low As is Reasonably Achievable CRB Control Rod Blades CRDM Control Rod Drive Mechanism CS Core Spray ECCS Emergency Core Cooling System EFCV Excess Flow Check Valve FME Foreign Material Exclusion FPCC Fuel Pool Cooling and Cleanup INPO Institute for Nuclear Power Operations ISI inservice Inspection LER Licensee Event Report MSIP Mechanical Stress Improvement Process NCV Non-Cited Violation NDE Nondestructive Examine. tion NRC Nuclear Regulatory Commission OSS Operations Staff Superintendent PDR Public Document Room PlV Pressure Isolation Valves PSE&G Public Service Electric and Gas
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RCA Radiologically Controlled Area RCIC Reactar Core isolation Cooling RHR Residpal Heat Removal RP&C Radiological Protection and Chemistry RR Reactor Recirculation
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RWP Radiation Work Permit SACS Safety Auxiliaries Cooling System SDC Shutdown Cooling SLC Standby Liquid Control l
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