IR 05000354/1998011
| ML20198L371 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 12/22/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20198L361 | List: |
| References | |
| 50-354-98-11, NUDOCS 9901040178 | |
| Download: ML20198L371 (24) | |
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i U. S. NUCLEAR REGULATORY COMMISSION
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REGION I
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Docket No:
50-354 License Nos:
NPF-57 Report No.
50-354/98-11 l
Licensee:
Public Service Electric and Gas. Company Facility:
Hope Creek Nuclear Generating Station l
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l Location:
P.O. Box 236 Hancocks Bridge, New Jersey 08038
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Dates:
November 1,1998 - December 12,1998 l
Inspectors:
S. M. Pindale, Senior Resident inspector J. D. Orr, Resident inspector J. T. Furia, Senior Radiation Specialist
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Approved by:
James C. Linville, Chief, Projects Branch 3 Division of Reactor Projects
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9901040178 981222 i
PDR ADOCK 05000354 e
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EXECUTIVE SUMMARY Hope Creek Generating Station NRC inspection Report 50-354/9811
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This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a six-week period of resident inspection. In addition, it includes the results of an announced inspection by a regional radiation specialist inspector.
l Ooerations The material condition of the plant was acceptable, however, the material condition of l
some areas had degraded. Specifically, general lighting in several plant areas was poor, and a pump seal leakoff line was leaking on two elevations in the serv!"e water intake structure. Operators did not recognize and identify that frequent actions taken to compensate for an equipment deficiency involving pressurization of the shutdown cooling l
system suction piping due to shutdown cooling system valve leakage was an operator burden. (Section 01.1)
Operators promptly stabilized the reactor plant in hot shutdown after an automatic turbine trip and reactor scram from 95% power. Control room operators were prompt to stabilize the plant in hot shutdown and to expedite technical specification surveillance requirements for hot shutdown. However, the operators did not recognize that the 'D' safety / relief valve l
had lifted unexpectedly. Also, PSE&G identified that the operators failed to cycle the torus-to-drywell vacuum breakers within two hours after SRV actuation, which was a Non-Cited violation of technical specification requirements. (Section 04.1)
Operators performed an error free startup. Reactor operators were assigned and dedicated i
l to critical tasks. Professionalism and standards ensured that each evolution was thoroughly understood before proceeding. Supervisors were appropriately focused on activities and management oversight was apparent. (Section 04.2)
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.In a meeting to discuss the root causes of the November 15,1998, automatic reactor
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shutdown and associated technical issues, the Station Operations Review Committee (SORC) demonstrated a strong safety perspective by posing challenging and relevant questions to the responsible PSE&G personnel. The presenters were well prepared to discuss technicalissues and were responsive to the SORC concerns. (Section 07.1)
l Maintenance PSE&G developed a forced outage maintenance scope that considered outstanding equipment problems and new problems that were identified during the plant trip and shutdown. Operators, engineers, and maintenance supervisors were thorough in resolving
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l or identifying problems to ensure that the repairs were complete and the plant was returned to power safely. (Section M2.1)
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Enaineerin_g l-Engineering promptly and thoroughly reviewed the details related to an unexpected actuation of a safety relief valve during a turbine trip and reactor scram transient.
Engineering appropriately supported the associated operability determination for the
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' automatic depressurization function of the valve. (Section E2.1)
PSE&G identified a step increase in the tritium concentration in the reactor coolant system, and attributed the most likely cause for the increase to minor degradation (cracking) of one or more control rods. In response, PSE&G promptly completed an operability determination
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and planned inspection activities for vulnerable control rods during the February 1999 refueling outage.- (Section E2.2)
PSE&G identified that components supplied by an outside vendor for the nuclear instrumentation system were not in conformance with manufacturing specifications.
PSE&G ' ompleted instrument repairs to the affected components prior to installation in the c
plant, and engineering and licensing personnel were completing an evaluation to determine the impact and extensiveness of the degraded components.- (Section E2.3)
l A senior reactor operator demonstrated a good questioning attitude and identified l
inadequate inservice testing requirements for check valves associated with the 'B' primary i
containment hydrogen-oxygen (H202) analyzer. PSE&G completed thorough corrective actions for this self-identified Non-Cited violation and verified that similar problems did not exist with other valves within the scope of the inservice test program. (Section E2.4)
Plant Sucoort Effective radiation protection programs have been established for centrolling high, locked
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t high and very high radiation areas; planning and maintaining occupational exposures as low l
as is reasonably achievable; and minimizing contamination in the radiologically controlled area. (Section R1)-
- An effective training program for radiation protection technicians and contractor
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l technicians has been established. Lesson plans and material presentations reviewed were appropriate. (Section R5)
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TABLE OF CONTENTS
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EX ECUTIV E S U M M AR Y.............................................. ii i
TA BLE O F CO NTENTS.............................................. iv l
l 1. O pe ra t i o n s..................................................... 1 l.
Conduct of Operations.................................... 1 l
01.1 General Observations................................ 1 l
. Operator Knowledge and Performance......................... 2 04.1 Automatic Turbine Trip and Reactor Scram................. 2 l-0 4. 2 Pla nt St a rtu p...................................... 4 l
Quality Assurance in Operations............................. 5 07.1 Station Operations Review Committee Meeting.............. 5 11. M a i n t e n a n c e................................................... 6 M1 Conduct of Mainte na nce................................... 6 M1.1 - New Fuel Receipt and Inspection........................ 6 M2 Maintenance and Material Condition of Facilities and Equipment........ 6 M2.1 Forced Outage Maintenance........................... 6 (-
M8 Miscellaneous Maintenance issues............................ 8 M8.1 (Closed) Licensee Event Report 50-3 54/98-007.............. 8 l
111. E ng in e e ri ng.................................................... 9
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E2 Engineering Support of Facilities and Equipment.................. 9 E2.1 - Unexpected Actuation of Safety / Relief Valve During Plant Transient i-
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E2.2 Elevated Tritium Level in the Reactor Coolant due to Control Rod i
Blade Degradation................................. 1 1 -
E2.3 Nuclear Instrumentation Component Deficiencies........... 12 E2.4 (Closed) LER 50-3 54/9 8-00 5.......................... 13 E8 Miscellaneous Engineering issues............................ 15 E8.1 - (Closed) Violation 50-3 5 4/9 8-06-04..................... 15 E8.2 (Closed) Violation 50-3 54/9 8-06-0 5.....................
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IV. Pla nt S u p p o rt................................................. 1 6 L
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R1 Radiological Protection and Chemistry (RP&C) Controls............ 16 R5 Staff Training and Qualification in RP&C....................... 17 R8 Miscellaneous RP&C issues................................ 18 l
R8.1 (Closed) lFI 5 0-3 54/97-04-03......................... 18 V. M a nagement Meeting s........................................... 18 X1 Exit Meeting Summ ary................................... 18 l-INSPECTION PROCEDURES USED..................................... 19
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t ITEMS OPENED, CLOSED, AND DISCUSSED.............................. 19
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LIST O F AC RO NYM S US ED.......................................... 20 i
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Report Details Summary of Plant Status Hope Creek was operated at or near full power until November 15,1998, when an automatic turbine trip and reactor shutdown occurred following a balance of plant transient. After a short outage for testing and maintenance, operators took the reactor critical on November 22, and placed the unit on-line or' November 24.
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l. Operations
Conduct of Operations 01.1 General Observations e
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Insoection Scone (71701)
The inspectors conducted frequent plant tours and observations of ongoing activities, and reviewed applicable operator logs and other documentation.
b.
Observations and Findinas The inspectors observed that the overall material condition of the plant was acceptable, however, the inspectors noted that the material condition of the service water intake structure had declined over recent months. For example, the 'C'
service water pump seat leakoff was overflowing from its basin onto the floor and also through floor grating to the lower elevation. PSE&G was aware of the overall degraded conditions at the intake structure, and was planning activities in the near term and during the upcoming outage to improve the material condition. In addition, lighting in several plant areas was degraded due to burnt out light bulbs. PSE&G planned actions to improve the lighting near term and to ensure responsibility for plant lighting receives appropriate attention.
The inspectors observed that a control room annunciator associated with the residual heat removal-shutdown cooling system (high pressure) alarmed about every three to four hours. The annunciator was received when the isolated shutdown cooling (SDC) suction piping reached 130 psig. This has been a problem experienced previously by control room operators after the SDC system was secured (See NRC inspection 50-354/98-01). The cause for the high pressure in the SDC system is related to small feakage past isolation valves between the reactor coolant systern into the SDC system. Upon receipt of this alarm, operators open a drain valve to relieve the pressure in the SDC system in accordance with established procedures. In addition, operators perform procedure HC.OP-GP.ZZ-0004(Q),
Reactor Coolant System Pressure Isolation Valve Leakage Determination, which measures the leak rate from the reactor coolant system to the SDC system. The leak rate acceptance criteria past the two SDC isolation valves is 5 gpm, and actual measured leak rates were typically less than 0.1 gpm.
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The inspectors noted that although the leakage past the isolation valves was small, the actions required to be performed by the operators several times per shift represented a distraction from normal duties. The inspectors further noted that this condition was not identified by PSE&G as an operator work-around or operator concern. The inspectors questioned operators and operations management whether this condition should be so classified. PSE&G subsequently concluded that the actions required to respond to the SDC high pressure alarms constituted an operator concern. PSE&G also informed the inspectors that both SDC isolation valves are planned to be repaired during the upcoming refueling outage, which begins in February 1999. The inspectors determined that the operators' lack of awareness and ownership of the operator burdens program is a continuing weakness from a similar recent inspection (NRC Inspection 50-354/98-07),and continued
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management focus in this area is appropriate.
c.
Conclusions The overall material condition of the plant was acceptable, however, the material
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condition of some areas had degraded. Specifically, general lighting in several plant areas was poor, and a pump seal leakoff line was leaking on two elevations in the service water intake structure. Operators did not recognize and identify that frequent actions taken to compensate for an equipment deficiency involving pressurization of the shutdown cooling system suction piping due to SDC valve leakage was an operator burden.
Operator Knowledge and Performance 04.1 Automatic Turbine Trio and Reactor Scram a.
Insoection Scope (93702. 71707)
The inspectors interviewed control room operators and reviewed plant indications following an automatic turbine trip and reactor shutdown (scram) from 95% reactor power.
b.
Observations and Findinas On November 15,1998, Hope Creek plant experienced an automatic turbine trip on high level in the 'A' moistur separator. The reactor automatically scrammed on turbine control valve fast ch.ure. Equipment operators were hanging a tagout that isolated instrument air to tu 6: ready secured 'A' feedwater heater string. The piping diagram used to deve,;up the tagout did not accurately identify all the instrument air loads. Unbeknownst to the operators, the instrument air isolation valve also secured booster control air to all the normallevel control valves for the
'A' and 'B' moisture separator drain tanks. The alternate level control valve for the
'B' moisture separator drain tank maintained adequate level control. System engineers later determined that the 'A' moisture separator drain tank alternate level control valve stuck closed during the transient causing the automatic turbine trip.
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See Section M2.1 for further discussion on the 'A' moisture separator drain tank
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level control and the instrument air piping diagram problems.
Control room operators were cognizant of the tagout in the field and attempted to have the equipment operators reopen the instrument air isolation valve as soon as
the moisture separator level problems were noticed. Within about 65 seconds after the moisture separator level alarms, the main turbine automatically tripped. In addition to the reactor scram; the recirculation pumps tripped as designed on End-of-Cycle -- Recirculation Pump Trip, all condensate flow isolated due to feedwater heater high level conditions, the reactor feed pumps subsequently tripped on low suction pressure, the low-low set safety / relief valves (SRV) lifted due to a valid high pressure condition, and the 'D' SRV unexpectedly lifted. All systems operated as expected except for the 'D' SRV. See Section E2.1 for further discussion on the 'D'
SRV actuation.
The inspectors determined that control room operators adequately maintained reactor water level with control rod drive pumps during the event. Reactor feed pumps were promptly restored af ter the condensate system was unisolated.
Control room operators restored the reactor recirculation pumps about two hours after the trip. The inspectors noted that the operators had failed to cycle all torus-to-drywell vacuum breakers within two hours after SRV actuation as required by Technical Specification 4.6.4.1. About three hours and thirty minutes had elapsed before all torus-to-drywell vacuurn breakers were cycled. Control room operators were already aware that the surveillance time requirement was not met. At the time of the scram and during recovery actions, the operators had not considered the surveillance time requirement and became focused on other priority activities for plant stabilization. The inspectors reviewed PSE&G's corrective actions for the torus-to-drywell vacuum breaker problem and considered the actions to be appropriate. This licensee-identified and corrected violation of Technical Specification 4.6.4.1 is being treated as a Non-Cited Violation, consistent with Section Vll.B.3 of the NRC Enforcement Policy. (NCV 50-354/98-11-01)
During a review of control room instruments following the scram, the inspectors noticed on the SRV acoustic monitors that the 'D' SRV had lifted. The 'D' SRV had an actuation setpoint of 1130 psig +/- 1 %, but had lifted at about 1080 psig. The inspectors discussed the 'D' SRV with the operators, but five hours after the event, the control room operators had not realized that the 'D' SRV lifted unexpectedly.
Operators maintained the plant in hot shutdown, controlling reactor pressure with the electro-hydraulic control system and the turbine bypass valves. The control room supervisor expedited intermediate range monitor (IRM) and source range monitor (SRM) detector surveillances to comply with technical specification requirements for hot shutdown. Subsequently, on November 16,1998, Hope Creek senior plant management decided that the plant should be cooled shutdown for repairs on the IRM and SRM detector systems due to operational problems with some of the IRMs and SRMs.
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The NRC inspectors later discussed with the Operations Manager whether an opportunity existed for the operators to anticipate the turbine trip and to initiate a manual scram before the automatic turbine trip. The inspectors agreed, based on the short time involved and the lack of remote monitoring capability for moisture separator level, that the operators acted conservatively and could not likely have anticipated the problems that led to the sudden automatic turbine trip.
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Conclusions Operators promptly stabilized the reactor plant in hot shutdown after a an automatic turbine trip and reactor shutdown from 95% power. Control room operators were prompt to stabilize the plant in hot shutdown and to expedite technical specification surveillance requirements for hot shutdown. However, the operators did not
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recognize that the 'D' safety / relief valve had lifted unexpectedly. Also, PSE&G identified that the operators failed to cycle the torus-to-drywell vacuum breakers within two hours after SRV actuation, which was contrary to technical specification i
requirements.
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l 04.2 Plant Startup a.
Inspection Scope (71707)
The inspectors observed control room operators take the reactor critical, increase power through the intermediate range, and continue plant heatup. The inspectors also observed control room operators roll the main turbine.
b.
Observations and Findinas On November 22,1998, control room operators took the reactor critical following the November 15,1998, automatic shutdown. The reactor operator who withdrew control rods to criticality was dedicated to the task and did not allow other activities to distract his attention. The nuclear engineer closely assisted the reactor operator j
and accurately adjusted the ustimated critical position for slowly increasing i
moderator temperature. Reactor water temperature was slowly increasing due to decay heat and shutdown cooling had been secured in preparation for the reactor startup. The inspectors observed a pre-activity brief on November 22,1998, for the approach to criticality. The brief was led by a senior reactor operators and provi'ded strong emphasis on conservative, deliberate and error free operations.
The inspectors noticed multiple control room activities occurring during the approach to criticality. One reactor operator was placing the residual heat rernoval system in suppression pool cooling in preparation for a high pressure coolant injection system surveillance test. Although the reactor operator withdrawing control rods did not appear to t>e distracted, the activity generated alarms and communications that could have presented a distraction to pulling control rods to criticality. Similarly, another reactor operator was inerting the containment. The containment inerting likewise increased potential distractions for the reactor operator pulling control rods. Once the reactor had entered the intermediate range,
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the Operations Manager reminded one of the operators involved in other activities to assist the reactor operator pulling control rods with ranging the intermediate range monitors (IRM). Ranging IRMs involved selecting the appropriate monitor switch scale position for each of eight IRM monitors so that the monitor reads on scale as reactor power increases through about five decades. Ranging IRMs improperly could lead to an unnecessary reactor scram.
The NRC inspectors observed a different control room crew continue the reactor plant heatup. The inspector again observed that the reactor operator assigned to pulling control rods was dedicated to the task and did not allow other activities to distract his attention. On November 24,1998, the inspectors observed the main turbine roll from the control room. The control room professionalism and standards for ensurir.g that the reactor plant was continuously monitored by dedicated reactor operators were consistent with other observed evolutions during the startup.
The NRC inspectors noted that management oversight was continuous. Engineering personnel were also assigned around-the-clock to monitor major equipment starts and to assist in resolving any equipment issues.
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Conclusions Operators performed an error free startup. Reactor operators were assigned and dedicated to critical tasks. Professionalism and standards ensured that each evolution was thoroughly understood before proceeding. Supervisors were appropriately focused on activities and management oversight was apparent.
O7 Quality Assurance in Operations 07.1 Station Ooerations Review Committee Meetina a.
Inspection Scope (40500,71707)
The inspectors attended a Station Operations Review Committee (SORC) meeting on November 19,1998, which focused on technical and potential safety issues related to the November 15,1998, automatic shutdown. The SORC also reviewed the root cause determination for the initiating transient.
b.
Observations and Findinas The inspectors observed the deliberations at SORC meeting No.98-068 on November 19,1998. The SORC reviewed the completed Post-Scram / Emergency l
Core Cooling System Actuation procedure (HC.OP-AP.ZZ-1-1(Q)) and several
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technicalissues related to the November 15,1998, automatic reactor shutdown (scram). The technical issues included 1) the instrument air system configuration deficiencies, causes and corrective actions,2) the early and unexpected actuation of the 'D' safety relief valve,3) a reactor protection system anomaly associated with the timely actuation of one of the high reactor pressure scram sensors, and 4)
the failure of a moisture separator drain tank dump valve.
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The inspectors observed that the SORC raised several probing and challenging questions and provided a strong safety focus. For example, the SORC challenged the presenters to more fuhy understand and then explain the failure mode of the l
moisture separator drain tank dump valve after several reasonable causes were
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postulated (valve was tested satisfactorily after the scram). Subsequently, the presenters recommended, and the SORC concurred, to stroke the valve during the plant startup to establish confidence in successful valve operation. The SORC reviewed each item in detail and ensured that each technical issue was thoroughly evaluated and appropriate corrective actions were implemented and/or planned.
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Conclusions in a meeting to discuss the root causes of the November 15,1998, automatic reactor shutdown and associated technicalissues, the Station Operations Review
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and relevant questions to the responsible PSE&G personnel. The presenters were well prepared to discuss technical issues and were responsive to the SORC concerns.
11. Maintenance M1 Conduct of Maintenance M 1.1 New Fuel Receiot and Inspection (60705. 71750)
The NRC inspectors observed maintenance technicians and reactor engineers receive, inspect and transfer new fuel to the spent fuel pool for use during the upcoming refuel outage in February 1999. The reactor engineers were actively involved in the new fuel receipt and ensured that facility operating license l
conditicn; for new fuel storage and handling were met. Maintenance technicians followed procedures and performed carefulinspections. Radiation protection i
technicians performed thorough contamination and radiation surveys. The inspector concluded that PSE&G technicians and engineers safely performed new fuel receipts
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and inspections, f
M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Forced Outaae Maintenance a.
inspection Scope (62707)
l The inspectors reviewed PSE&G's forced outage maintenance scope to support plant restart from the automatic turbine trip and reactor scram that occurred on November 15,1998. The inspectors also reviewed details associated with several plant issues.
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b.
Observations and Findinas I
On November 16,1998, PSE&G plant management decided to place the plant in cold shutdown to relax primary containment restraints and allow entry into the drywell for intermediate range monitor (IRM) and source range monitor (SRM)
detector repairs. Initial troubleshooting of problems identified on the SRMs and IRMs after the reactor scram indicated that the 'A' SRM, the 'E' IRM and the 'F'
IRM would require detector replacements. The 'G' IRM was also exhibiting erratic l
behavior related to range switch operation. Although technical specification requirements would have allowed a plant restart with reduced IRM and SRM channels, PSE&G management strongly supported delaying plant restart in order to return all neutron monitoring system channels to a fully operable status. The inspectors verified that the neutron monitoring system was an (a)(1) system in the scope of the Maintenance Rule. PSE&G intended to consider changing the established system goals because of the recent IRM and SRM f ailures.
System engineers worked with design engineers and performed an exhaustive review of chronological and historical data to evaluate the moisture separator level control during the November 15,1998, automatic turbine trip and reactor scram.
The engineers determined that the 'B' moisture separator alternate level control valve had performed as expected and maintained proper level controlin the 'B'
moisture separator. The automatic turbine trip from high 'A' moisture separator level resulted when the associated alternate level control valve,1 ACLV-1039A, failed to close. During subsequent field testing, valve technicians noted that the 1 ACLV-1039A initially " popped" off the valve closed seat. System engineers did not identify any other problems with the 1 ACLV-1039A valve that would have caused the valve to remain closed during the moisture se:
"or level transient.
The 1 ACLV-1039A valve was cycled after plant restart t nure that the alternate level control was functional during power operations. Thi spectors verified that the 1 ACLV-1039Ais in the scope of the Maintenance Rule. and is in an (a)(2)
system. The Maintenance Rule Coordinator intended to develop goal setting criteria for the 1 ACLV-1039A valve pending completion of the root cause evaluation for the automatic turbine trip.
System engineers performed a root cause investigation for the instrument air system piping diagram errors. The instrument air drawings provided by the construction architect engineer for non-safety related applications did not identify detailed system loads. PSE&G updated the drawings in 1990 to include system load details to assist PSE&G during operations and maintenance related to the instrument air system. The drawing updates were accomplished by performing plant walkdowns.
After the November 15,1C38 plant trip, PSE&G system engineers performed configuration verification walkdowns for the instrument air system. The instrument air system was depicted on 14 sheets. All safety-related applications and all non-safety-related applications in the turbine building whose loss of function could cause a plant transient were verified. With one minor exception, additional errors were only identified on the one sheet which had contained the original problem associated with the November 15 plant trip. PSE&G developed appropriate short term corrective actions for the additional errors that were identified, including
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j establishing guidance to operators for tagging activities for the instrument air system (physical component verification required until drawings are j
updated / corrected). PSE&G also intended to develop long term corrective actions to ensure that the instrument air drawings are revised and accurate.
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During the current operating cycle, Hope Creek operators measured plant leakage I
into the reactor building main steam tunnel on a weekly basis during power
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operations. The source of the leakage was from secondary plant valves, such as a i
main steam drain line valve packing leak. The leakage collected in the steam tunnel had slowly increased to about 1500 gallons per week. Maintenance engineers monitored the trend and entries at power into the steam tunnel were considered if leakage measurements were significant. PSE&G maintenance supervisors toured
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the reactor building steam tunnel while the plant was in hot shutdown and identified a significant manual valve packing leak. The packing repair was completed before the plant was restarted. A previously identified motor operated valve packing leak was also repaired during the forced outage. Steam tunnelleakage after the plant j
restarted and subsequent to the packing leak repairs was reduced to about 250 i
gallons per week.
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Off-shift Hope Creek senior reactor operators (SRO) performed HC.OP-AP.ZZ-0101(O), Post Reactor Scram /ECCS Actuation Review and Approval Requirements.
The procedure is used to verify the proper response of key safety-related equipment. SROs identified a reactor pressure vessel high pressure scram signal j
that was received about 1.259 seconds after the other channel signals were received. The reactor actually scrammed as expected on turbine control valve fast closure before the high pressure scram signal was received. PSE&G replaced the pressure transmitter and associated relay prior to plant startup. The inspectors determined that the SROs performed a thorough review of the sequence of events report and procedure HC.OP-AP.ZZ-0101(O)
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Conclusions PSE&G developed a forced outage maintenance scope that considered outstanding equipment problems and new problems that were identified during the plant trip and
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shutdown. Operators, engineers, and maintenance supervisors were thorough in resolving or identifying problems to ensure that the repairs were complete and the plant was returned to power safely.
M8 Miscellaneous Maintenance issues M8.1 (Closed) Licensee Event Report 50-354/98-007: Standbv Liauid Control Pumo Lnoperability Due to incorrectiv Performed inservice Test n
The inspectors reviewed this Licensee Event Report (LER) and concluded that it accurately described the testing methodology deficiency for the standby liquid control pumps. The inspectors previously conducted a field inspection and documented the technical details associated with this item in NRC Inspection 50-354/98-10 (Section M8.1), and unresolved item 50-354/98-08-01 remains open pending additional review. This LER is closed.
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Ill. Enaineering E2 Engineering Support of Facilities and Equipment E2.1 Unexpected Actuation of Safetv/ Relief Valve Durina Plant Transient a.
Inspection Scpoe (71707,937Q9)
The inspectors reviewed PSE&Gi follow-up and evaluation associated with a premature actuation of a safety /def valve (SRV) during the November 15,1998, automatic shutdown. The inspedon reviewed control room recorder traces, reviewed design basis documents, md interviewed operators and engineers, b.
Observations and Findinas During the November 15,1998, transient associated with the automatic reactor scram, the 'D' SRV opened below the nominallift setting of 1130 psig. During the increase in reactor pressure immediately following the turbine trip, the 'D' SRV opened at about 1080 psig, concurrent with the two low-low set SRVs ('H' and
'P'). This 'D' SRV closed at its normal reseat pressure of about 1000 psig within nine seconds.
Hope Creek uses 14 two-stage Target Rock pilot operated SRVs. Five of the 14 ('A' through 'E') perform a dual automatic depressurization system (ADS) relief function. The valves are mounted on the four main steam line headers. The two low-low set SRVs are designed to reduce the challenges to SRVs by having a lower setpoint with a wider spread between actuation and reset in comparison with the mechanicallift and reseat setpoints. The 'H' and 'P' SRVs are designed to automatically open when reactor pressure reaches 1047 psig (relief-mode actuation). Normal operating reactor pressure is 1005 psig, and the nominal
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mechanical setpoints for the SRVs are 1108 psig (4 SRVs),1120 psig (5 SRVs),
and 1130 psig (5 SRVs).
During the November 15,1998, turbine trip transient, reactor pressure increased as expected, and the low-low set SRVs actuated. The 'H' and 'P' SRVs opened concurrently as expected, and the 'D' SRV opened one second later. The 'D' SRV closed at about 1000 psig nine seconds after it opened. The 'P' SRV closed next, 14 seconds after it opened, and the 'H' SRV closed last,17 seconds after it opened.
The operators did not notice that the 'D' SRV had actuated during the transient until identified by the inspectors. PSE&G's post-transient review identified that the SRV l
lifted at 1080 psig, which was 50 psig below its nominal setpoint of 1130 psig.
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Technical Specification 3.4.2.1 requires the SRVs to be operable with the lift settings within 1 % of the nominallift setpoint (between 1118.7 and 1141.3 psig
for this SRV). The valve lifted outside its expected range. However, the reseat t
pressure observed for the 'D' SRV was consistent with the normal reseat pressure l
(1000 psig).
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PSE&G evaluated the unexpected 'D' SRV lift, and concluded that the cause was attributed to " sympathetic" actuation. This phenomenon is related to the creation of vibration in the main steam line as a result of lifting of adjacent SRVs, and ultimately can cause inadvertent SRV lifting at lower than expected pressures, in fact for this situation, the 'H' SRV is located adjacent to the 'D' SRV, and had lifted as expected for its low-low set relief function. The vibration excites the setpoint spring in the pilot assembly and effectively reduces some of the spring force. This then results in lifting the pilot and the valve depressurizes.
PSE&G identified that this phenomenon had previously occurred at Hope Creek following a similar plant transient involving a turbine trip / reactor scram from full power. During that transient in October 1994, the 'K' SRV unexpectedly lifted at a low pressure (also around 1080 psig). The 'K' SRV is adjacent to the other low-low set SRV ('P'). Subsequent setpoint verification of the 'K' SRV identified that the lift setpoint was about 3% higher than the nominal 1108 psig setpoint.
The inspectors reviewed relevant design and industry information related to SRVs.
In addition, the inspectors discussed the above phenomenon with NRC technical experts. The inspectors determined that PSE&G's conclusion with respect to the lifting of the 'D' SRV was consistent with prior experience and industry information.
The 'D' SRV also functions as an ADS valve, which means that the valve can receive an independent actuation signal from the ADS logic system. The actual operation of the SRV from an ADS signalis independent of the mechanicallift (safety valve) operation. PSE&G declared the safety valve function of the 'D' SRV inoperable, however, the ADS function remains operable. Accordingly, PSE&G completed an operability determination to document the bases for continued ADS operability for this valve. The inspectors reviewed the operability determination and found it to be acceptable. The operabiFty determination was applicable to plant operation until the next refueling outage (February 1999), at which time this SRV pilot assembly will be removed, tested, and replaced with a pre-tested spare.
PSE&G also plans to continue further efforts to evaluate other possible causes and corrective actions for the sympathetic actuation phenomenon. Specifically, PSE&G plans to evaluate whether SRV discharge line snubber removal efforts during Hope Creek's fourth refueling outage (about 1988), had significant impact on the dampening of the SRV discharge lines.
c.
Conclusions Engineering promptly and thoroughly reviewed the details related to an unexpected actuation of a safety relief valve during a turbine trip and reactor scram transient.
l Engineering appropriately supported the associated operability determination for the automatic depressurization function of the valve.
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E2.2 Elevated Tritium Level in the Reactor Coolant due to Control Rod Blade Dearadation a.
insoection Scoce (37551,71707,71750)
The inspectors reviewed activities related to PSE&G's identification and follow-up of an elevated tritium levelin the reactor coolant system. The inspectors reviewed l
I documentation, and interviewed chemistry, engineering and operations personnel, b.
Observations and Findinas On December 5,1998, chemistry personnel identified the presence of higher than normal tritium and boron levels in the reactor coolant system (RCS). This was identified and documented in Action Request 981205113. Subsequently, chemistry j
determined that several recent boron ar 3lyses were incorrect, and the RCS as well as the spent fuel pool boron concentration had actually remained stable and in specification. The December 4,1998, RCS tritium concentration was 1.36 E-2 microCuries/ milliliter ( Ci/mi), a step increase from the recent 6.0 E-3 Ci/ml concentration measured in late November 1998. Hope Creek procedure HC.CH-Tl.ZZ-0012(O), Chemistry Sampling Frequencies, Specifications, and Surveillances,
specified controllimits for various parameters at which certain actions are to be taken. The RCS tritium controllimit is 1.0 E-2 pCi/ml. PSE&G defines a control limit as the lowest value of a parameter that is desired to be maintained long-term by application of good operating practices. In the case of RCS tritium, the control l
limit is related to the basis for liquid effluent radiation monitor setpoints. Above a
tritium concentration of 1.O E-2 pCi/mi, the default setpoint for the liquid effluent
radiation monitor must be recalculated.
Elevated tritium concentration in the RCS is also an indication of a potential degradation of control rod blades. Reactor engineering and chemistry personnel evaluated the recent tritium results and concluded that the most likely source of the
tritium was from some control rod blade degradation. Control rod blade cracking
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has been experienced in the nuclear industry. Hope Creek previously (1994) found crack indications in six control rods (185 total control rods in the reactor core) in the control rods manuf actured by Asea Brown - Boveri (ABB). The crack indications were identified and confirmed by visual inspection.
Hope Creek currently has a combination of General Electric (GE) and ABB control rods in the core. Thirty seven of the 185 control rods were manufactured by ABB; two of these are ABB model CR82 and 35 are the newer ABB model CR85M, which L
are more crack resistant. The GE control rods are designed with a sheath such that l
visualinspection hampers the identification of minor blade cracking.
The ABB control rods are used in control cells, which are subject to higher neutron flux. The GE control rods are in non-contrri cell locations, including the core periphery. As such, PSE&G believes that the ABB centrol rods may be the cause for the elevated tritium due to minor cracking. Therefore, the reactor engineers selected several ABB control rods to be visually inspected during the next refueling outage in February 1999. At least 13 ABB control rods with the highest exposures
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will be inspected, and the inspection scope will be modified based upon the inspection results.
PSE&G determined that the operational concern associated with operating with control rod blade cracking degradation is related to the ability of the control rod to i
perform its intended safety function of controlling reactivity, in response to this concern, operations completed an operability determination. The determination documented the prior Hope Creek and industry experiences with control rod blade cracking, and discussed recent control rod testing and performance.
The inspectors determined that PSE&G was responsive to the increased tritium concentration in the reactor coolant system, and appropriately assessed operability of control rods currently in place in the reactor core.
c.
Conclusions PSE&G identified a step increase in the tritium concentration in the reactor coolant system, and attributed the most likely cause for the increase to minor degradation (cracking) of one or more control rods. In response, PSE&G promptly completed an operability determination and planned inspection activities for vulnerable control rods during the February 1999 refueling outage.
E2.3 Nuclear Instrumentation Component Deficiencies a.
Inspection Scone (37551. 71707)
The inspectors reviewed PSE&G's actions following the identification of two issues associated with nuclear instrumentation parts supplied by a vendor. The inspectors reviewed documentation and interviewed PSE&G personnel.
b.
Observations and Findinas A discussed in Section M2.1 of this report, there were several equipment problems associated with source range and intermediate range monitors (SRM and IRM). As part of the planned maintenance, several new parts were retrieved from the warehouse. However, two notable issues were identified with the replacement components during tiu conduct of maintenance.
The first issue was that the new IRM and SRM detector pins were oversized such that the center pin of the detector would not fit into the adapter piece. Further inspection by PSE&G identified that the pin diameters were out of tolerance by 0.008 inches (required diameter is 0.120 + /- 0.001 inch). The 0.129 inch diameter pins would not pass through the 0.125 inside diameter of the adapter piece.
The second materialissue identified by PSE&G was related to a defective solder joint at the detector to pin interface. This was identified when PSE&G attempted a repair of the oversized pins.
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l PSE&G contacted the vendor for both of these problems. The vendor subsequently
confirmed that measurements of the stock of pins were also oversized. PSE&G I
stated that the vendor determined the second issue was due to poor soldering practices during the manufacturing process including poor surface preparation and incorrect solder iron. PSE&G documented these concerns in an Action Request (No.
981119268)and initiated several actions to restore the detectors to an acceptable condition. PSE&G expressed a concern with the vendor's quality control and manufacturing work practices. Accordingly, PSE&G plans further review in this area, to include meeting with the vendor and visually observing the pin soldering
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procedure at the vendor's facility. PSE&G repaired all defective components prior to field installation activities, and satisfactorily tested the detectors following maintenance. In addition, PSE&G's evaluation associated with the Action Request will confirm the PSE&G purchase order specification and receipt inspection documentation.
At the end of this inspection, PSE&G was completing a 10 CFR Part 21 evaluation regarding the defective components supplied by the vendor. To date, PSE&G determined that the physical dimension of the first problem involving over-sized pins was such that the components could not have been installed in the plant, and a backup nuclear instrumentation system (average power range monitors) would have provided a backup reactor protection system signal in the event that a solder joint were to fail and render IRMs or SRMs inoperable. The results of PSE&G's 10 CFR Part 21 evaluation will be reviewed during a subsequent inspection (IFl 50-354/98-11-02)
The inspectors monitored PSE&G's identification, repairs, and evaluation of the IRM and SRM component deficiencies and concluded that the efforts were acceptable.
c.
Conclusions PSE&G identified that components supplied by an outside vendor for the nuclear instrumentation system were not in conformance with manufacturing specifications.
PSE&G completed instrument repairs to the affected components prior to installation in the plant, and engineering and licensing personnel were completing an evaluation to determine the impact and extensiveness of the degraded components.
E2.4 (Closed) LER 50-354/98-OO5:Hydroaen-Oxvaen Analyzer inocerability Due to Missed Inservice Test a.
Inspection Scoce (92700. 37551. 61726)
The inspectors performed an onsite inspection and reviewed PSE&G's corrective l
actions associated with a failure to include inservice testing (IST) requirements for l
two nitrogen gas supply check valves in the containment atmosphere control system.
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Observations and Findinos On August 10,1998, PSE&G discovered that two nitrogen gas supply check valves in the 'B' hydrogen-oxygen (H2O2) primary containment analyzer were not being tested in the inservice test program. The discovery was made by a senior reactor operator who questioned the safety function of the check valves. If one of the two check valves were to have failed to close, the suction and discharge of the 'B'
H202 analyzer would have become cross-connected and affected the accuracy of the analyzer.
PSE&G previously discovered that the check valves should be included in the inservice test program when the second ten year interval IST program was developed in December 1997. However, PSE&G did not develop the appropriate test requirements or procedures for the two nitrogen gas supply check valves.
PSE&G determined that the nitrogen gas supply check valves were added to the IST program after a report of program additions, deletions and function changes was already used to develop test requirements for the second interval.
In response to this identification, PSE&G adequately tested the nitrogen supply check valves on August 11,1998. The test results were satisfactory. PSE&G reviewed the IST data base to assure appropriate test requirements were developed for all valves in the IST program. No additional problems were identified. The NRC inspectors reviewed IST program changes between the first and second ten year intervals for the main steam, containment atmosphere, and high pressure coolant injection systems. The inspectors did not identify any problems with inservice test requirements for the main steam, containment atmosphere, or high pressure coolant injection systems.
The failure to adequately perform inservice testing for the 1GSV-054 and 1GSV-055 check valves was a violation of Technical Specification 4.0.5. The inspectors determined that PSE&G completed thorough and timely corrective actions for the inservice testing problems. This licensee-identified and corrected violation of Technical Specification 4.0.5 is being treated as a Non-Cited Violation, consistent with Section Vll.B.3 of the NRC Enforcement Policy. (NCV 50-354/98-11-03)
c.
Conclusions A senior reactor operator demonstrated a good questioning attitude and identified inadequate inservice testing requirements for check valves associated with the 'B'
primary containment hydrogen-oxygen (H202) analyzer. The inservice tests were necessary to ensure the continued operability of the 'B' H202 analyzer. PSE&G completed thorough corrective actions for this self-identified Non-Cited violation and verified that similar problems did not exist with other valves within the scope of the inservice test program.
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Miscellaneous Engineering issues E8.1 (Closed) Violation 50-354/98-06-04: Emeroency Diesel Generator Fuel Oil Contamination Due to inadeauate Fuel Oil Samolina a.
Inspection Scope (92903)
The inspectors performed an onsite inspection and reviewed PSE&G's actions in response to a failure to properly sample and analyze the emergency diesel generator (EDG) fuel oil for particulate concentration.
b.
Qbservations and Findinas The EDG fuel oil particulate concentration testing was inappropriately discontinued at the direction of the previous Diesel Fuel Oil Program manager. In response to this item,' PSE&G changed program responsibility for Hope Creek diesel fuel oil testing to the system engineering department. The inepectors confirmed that the Hope Creek EDG system engineer assumed responsibility for this program, including data evaluation and trending.
PSE&G modified procedure HC.CH-AP.ZZ-OO41(Q), Hope Creek Generating Station Diesel Fuel Oil Testing Program, to require that particulate concentration testing be satisfactorily completed prior to off-loading individual diesel fuel oil tankers. The inspectors confirmed this procedure change was prc,perly implemented.
The inspectors determined that PSE&G's actions were acceptable and were
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completed in a timely fashion.
c.
Conclusiorg PSE&G implemented acceptable actions to address deficiencies associated with the Hope Creek diesel fuel oil testing program. This violation is closed.
E8.2 (Closed) Violation 50-354/98-06-05: Failure to Ensure Proper Desian Controls for the Reactor Core isolation Coolina System a.
Inspection Scone (92903)
The inspectors performed an onsite inspection and reviewed PSE&G's actions in response to issues that resulted in a rapid overspeed of the reactor core isolation cooling (RCIC) system during testing.
b.
Qhservations and Findinas
g PSE&G contractors had inadequately designed, reviewed and tested a modificubo that resulted in defeating a feature of the RCIC turbine steam admission stop..e control circuitry. 'The lack of the timing sequence feature caused the RCIC tuQne 1:
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to overspeed during a post-maintenance test during which the pump and turbine were uncoupled.
PSE&G reviewed other similar modification work performed by the contractor at Hope Creek and at Salem to determine whether similar deficiencies existed. No similar deficiencies were identified, and PSE&G determined that the RCIC turbine steam admission stop valve was unique in its operation and configuration. In
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addition, the engineering assurance organization performed a separate assessment of the modifications performed by the contractor, as well as two additional contractors, and similarly did not identify repetitive errors.
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As a result of this and previous design issues, PSE&G has instituted additional initiatives to improve the quality of modifications. These included the safety evaluation independent review team (SEIRT) and the Modification Review Board (MRB), which provide additional and independent reviews of 10 CFR 50.59 safety evaluations and modification packages.
The inspectors previously confirmed that PSE&G corrected the design deficiency, restored the timing sequence feature and corrected the controlling design change package. The additional committees for independent review of safety evaluations and modification packages provide additional barriers to prevent similar problems.
c.
Conclusions PSE&G implemented acceptable corrective actions to address design control deficiencies associated with the RCIC turbine steam admission stop valve. This violation is cinsed.
IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls
a.
Insoection Scoce (83750j l
l A health physics inspection during routine operations 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 20.1602 Control of access to very high radiation areas 20.1902 Posting requirements 20.1904 Labeling containers 20.2103 Records of surveys l
The inspection was conducted via direct observation of in-process work in the l
radiologically controlled areas (RCA), review of pertinent documents including
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surveys, radiation work permits (RWPs) and as low as is reasonably achievable (ALARA) reviews, and discussions with cognizant personnel.
b.
Observations and Findinas
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Tours of the radiologically controlled areas, including the turbine, reactor, services and radwaste buildings indicated that an effective program har. been implemented for the control of high, locked high and very high radiation areas. All areas were found to be appropriately secured and posted. Key controls where applicable were the responsibility of the radiation protection staff. Key logs were reviewed, and indicated that all keys were appropriately accounted for.
All materials located in the RCA were properly identified and labeled. Contaminated area boundaries were maintained, while the size of contaminated areas was generally small.
j A reasonable unit occupational exposure goal was established for 1998, and through the end of November, the unit was on track to meet this goal. A goal for the 1999 refueling outage (RF08), scheduled to commence in February, has not yet been established, although the outage work scope has been frozen. An appropriate interface has been established to identify and coordinate work taking place in the RCA. A twelve week planning cycle for routine work has been established, which includes identification of work requiring general and specific radiation work permits and ALARA reviews.
c.
Conclusions Effective radiation protection programs have been established for cc,ntrolling high, locked high and very high radiation areas; planning and maintaining occupational exposures ALARA; and minimizing contamination in the RCA.
R5 Staff Training and Qualification in RP&C a.
lnsoection Scone (83750)
A review of the technical training program for radiation protection technicians, including continuing training, establishment of curriculum, and training of contractor technicians was conducted. The portion of the inspection was accomplished via interviews with cognizant personnel, review of lesson plans and other related documents, and observations of training in progress, b.
Observations and Findinas Management of the technical training program for radiation protection technicians has recently been transferred to the Radiation Protection Manager. Two instructors now report directly to the radiological support group and provide the development and presentation of lesson plans.
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Two sessions of formal coritinuing training were scheduled for 1998, with the second session ongoing at the time of this inspection. Lesson topics are reviewed and approved by the Training Review Group, which includes both technicians and supervisors, and is chaired by the Radiation Protection Manager. Direct observation
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of one training session, covering use of the new database system, was made. The presentation was professional, accurate and informative. Contract radiation protection technicians hired to support refueling outages are given the Northeast Training Association (NETA) examination, then provided site-specific and task-specific training.
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Conclusions
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An effective training program for radiation protection technicians and contractor
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technicians has been established. Lesson plans and material presentations reviewed were appropriate.
R8 Miscellaneous RP&C lasues i
R8.1 (Closed) IFl 50-354/97-04-03;t.av-uo of the Bituminous Waste System. The licensee has administratively tagged out the appropriate valves and drained down all
system components no longer in service. Long-tem plans include capping off the
l tagged out valves. This item is closed.
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t V. Manaaement Meetinas l
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. Exit Meeting Summary
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The inspectors presented the inspection results to members of licensee management at the
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i conclusion of the inspection on December 21,1998. The licensee acknowledged the findings presented.
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l INSPECTION PROCEDURES USED
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IP 37551:
Onsite Engineering.
IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems IP 60705:
Preparatior, for Refueling IP 61726:
Surveillance Observations IP 62707:
Maintenance Observations IP 71707:
Plant Operations IP 71750:
Plant Support Activities IP 83750:
Occupational Radiation Exposure l
IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92902:
Followup - Maintenance IP 92903:
Followup - Engineering IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors
ITEMS OPENED, CLOSED, AND DISCUSSED Doened/ Closed 50-354/98-11-01 NCV Failure to cycle the torus-to drywell vacuum breakers as required by technical specifications. (Section 04.1)
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50-354/98-11-02 IFl PSE&G to complete 10 CFR Part 21 evaluation.
(Section E2.3)
50-354/98-11-03 NCV Hydrogen-oxygen analyzer inoperability due to missed inservice test. (Section E2.4)
Close_d i
50-354/97-04-03 IFl Lay-up of the bituminous waste system. (Section R8.1)
50 354/98-06-04 VIO Emergency diesel generator fuel oil contamination due to inadequate fuel oil sampling. (Section E8.1)
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50-354/98-06-05 VIO Failure to ensure proper design controls for the reactor core isolation cooling system. (Section E8.2)
50-354/98-005 LER Hydrogen-oxygen analyzer inoperability due to missed
inservice test. (Section E2.4)
50-354/98-007 LER Standby liquid control pump inoperability due to
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incorrectly performed inservice test. (Section M8.1)
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LIST OF ACRONYMS USED -
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ABB Asea Brown - Boveri ADS Automatic Depressurization System ALARA As Low As is Reasonably Achievable -
l AR Action Request EDG Emergency Diesel Generator GE'
.H202 Hydrogen-Oxygen IFl.
Inspection Followup Item IRM Intermediate Range Monitor i.
IST Inservice Testing
.LER Licensee Event Report
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MRB Modification Review Board
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NF.TA Northeast Training Association
l-NRC Nuclear Regulatory Commission
PDR-
' Public Document Room l'
PSE&G Public Service Electric and Gas
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'RCA Radiologically Con. trolled Area
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RCIC Reactor Core isolation Cooling RCS Reactor Coolant System l
RP&C-
. Radiological Protection and Chemistry
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RWP'
_ Radiation Work Permit EDC Shutdown Cooling i
SElRT Safety Evaluation independent Review Team
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. Station Operations Review Committee -
-SRM Source Range Monitor-SRO
- Senior Reactor Operator
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SRV Safety / Relief Valves -
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