IR 05000293/1993013
| ML20046B908 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 07/27/1993 |
| From: | Eugene Kelly NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20046B905 | List: |
| References | |
| 50-293-93-13, NUDOCS 9308090009 | |
| Download: ML20046B908 (17) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket No.:
50-293 Report No.:
93-13 Licensee:
Boston Edison Company 800 Boylston Street l
Boston, Massachusetts 02199
t Facility:
Pilgrim Nuclear Power Station Location:
Plymouth, Massachusetts
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Dates:
June 8,1993 - July 12,1993
Inspectors:
J. Macdonald, Senior Resident Inspector A. Cerne, Resident Inspector D. Kern, Resident inspector i
Approved by:
M 7[Mk
E. Kelly, Chief Date i
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Reactor Projects Section 3A Scope: Resident safety inspections in the areas of plant operations, radiological controls, maintenance and surveillance, security, safety assessment and quality verification, and engineering and technical support. Initiatives selected for inspection included a review of j
radiation worker exposure limit controls and termination exposure reporting, an update of the switchyard betterment program, the preventive maintenance deferral process, HPCI and RCIC exhaust rupture disk reliability, and completion of the titanium SSW piping modification.
Inspections were performed on backshifts during June 8-10,14-18,28, 29 and July 2, 6-9, and 12.
Findings: Performance during this five week period is summarized in the Executive Summary.
One unresolved item was identified regarding the implementation of the preventive maintenance
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deferral process (UNR 50-293/93-13-01). Additionally, the failure to perform a Technical Specification required surveillance of specific components within the control room high efficiency air filtration system in 1990 was categorized as a noncited violation.
9308090009 930730 PDR ADOCK 05000293 PDR G
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i EXECUTIVE SUMMARY
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Pilgrim Inspection Report 93-13
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Plant Operations: Operators responded properly to a June 23,1993 hydraulic control unit
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component malfunction that resulted in an unplanned insertion of a single control rod. Reactor engineering verified that thermal limits had not been exceeded and that the event was bounded by existing safety analysis. Identification and repair of the failed component, the associated scram outlet valve diaphragm, were timely.
Radiological Controls: Contractor radiation exposure limits were properly established'and.
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controlled during the recent refueling outage. Outage personnel exposure was properly reported to individuals and to the NRC at the completion of their employment periods.
l Maintenance and Surveillance: Switchyard betterment program activities progressed and received appropriate management support. NRC review of the June 23, 1993 control rod
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insertion event identified an apparent programmatic weakness in the implementation of the preventive maintenance (PM) deferral process. Specifically, numerous PMs, including the procedure that would have replaced the failed scram valve diaphragm, were deleted from the
recent refueling outage schedule without completion of all required technical reviews.
Preliminary corrective actions have been initiated, however, continued attention is warranted to ensure resolution of this issue.
Security: The security force continued to perform assigned duties during routine and backshift work periods in a manner consistent with security plan requirements.
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Engineering and Technical Support: Independent inspector review determined the existing inspection and testing programs for the high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) system steam exhaust line rupture disks were adequate. This review
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was conducted following failure of a similar HPCI rupture disk at another NRC licensed power reactor.
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The major salt service water (SSW) titanium piping replacement was completed with good
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management oversight and appropriate objective measures of quality design and construction.
Implementation of this modification significantly enhances long term reliability of the SSW system.
i Safety Assessment and Quality Verification: Licensee event reports (LER) were of high quality and fully developed root causes of the events. All reporting criteria were appropriately addressed.
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SUMMARY OF FACILITY ACTIVITIES At the start of the report period Pilgrim Nuclear Power Station was operating at approximately 50% of rated pawer in the process of power ascension. The station achieved 100% power on June 9,1993.
Unidentified drywell leakage slowly trended upward from June 15 through the end of the reporting period. Operators closely monitored the leak rate which progressed from.2 gallons per minute (gpm) on June 15 to approximately 2.5 gpm on July 12. Management established administrative controls which would conservatively initiate a plant shutdown, before unidentified drywell leakage reached the 5.0 gpm limit established by Technical Specifications.
On June 23, reactor power was reduced to 70% in response to a single control rod scram which resulted from failure of a scram outlet valve diaphragm. Scram time testing was successfully completed following diaphragm replacement and power was restored to 100% on June 24.
On June 30, the HPCI system failed to achieve rated flow during a routine surveillance. The cause was foreign material blockage of the full flow test line restricting orifice. This blockage affected the test flow path, but did not affect the ability of the HPCI pump to ing:
rated flow to the reactor vessel.
Both the 'A' and 'B' recirculation pump motor generator set speed controllers exhibited intermittent instability during this report period. A temporary modification was implemented to install strip chart recorders to track the performance of both speed controllers and support evaluation oflicensee corrective actions.
The reactor plant was at 100% of rated power at the close of the inspection period.
2.0 PLANT OPERATIONS (71707,40500,90712)
2.1 Plant Operations Review l
The inspector observed the safe conduct of plant operations (during regular and backshift l
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hours) in the following areas:
Control Room Fence Line Reactor Building (Protected Area)
Diesel Generator Building Turbine Building
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Switchgear Rooms Screen House Security Facilities
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Control room instruments were independently observed by NRC inspectors and found to be in correlation amongst channels, properly functioning and in conformance with Technical i
Specifications. Alarms received in the control room were reviewed and discussed with the operators; operators were found cognizant of control board and plant conditions. Control
room and shift manning were in accordance with Technical Specification requirements.
i Posting and control of radiation contamination, and high radiation areas were appropriate.
Workers complied with radiation work permits and appropriately used required personnel
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monitoring devices.
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Plant housekeeping, including the control of flammable and other hazardous materials, was
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observed. During plant tours, logs and records were reviewed to ensure compliance with station procedures, to determine if entries were correctly made, and to verify correct i
communication of equipment status. These records included various operating logs, turnover sheets, tagout, and lifted lead and jumper logs.
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2.2 Single Control Rod Insertion Due to Scram Outlet Valve Diaphragm Rupture
At 7:36 am on June 23, the " Rod Drift" alarm for control rod 42-39 annunciated. Control
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room operators checked indicated rod position and observed continuous inward rod motion.
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In less than one minute control rod 42-39 had drifted from the full-out position (48 steps) to the full-in position (00 steps). Operators immediately reduced reactor power to 70 percent and stabilized plant parameters in accordance with procedure 2.4.11 " Control Rod Malfunctions." Plant personnel reported an air leak from the scram outlet valve associated with control rod 42-39. This was indicative of a diaphragm rupture which resulted in the scram outlet valve opening and control rod 42-39 being driven inward by reactor pressure.
i Reactor engineers confirmed that this single unplanted control rod insertion was bounded by
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previous analysis and that no thermal limits were exceeded. Procedure 2.4.11 states that a j
scram to the full in position of up to 5 control rods is an analyzed condition for which there is no thermal limits are violated. Control room operators subsequently raised recirculation I
flow to restore the plant to full power. The inspector determined that the licensee responded
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properly to the control rod malfunction and confirmed that this event posed no safety consequence.
As follow-up corrective action, the failed scram outlet valve diaphragm was replaced, post maintenance scram time testing of control rod 42-39 was satisfactorily completed, and the normal control rod pattern was restored on June 24. The licensee initially reported this event to the NRC under the criteria of 10 CFR 50.72.b.2.ii. Licensee compliance division personnel subsequently conducted a post event review and determined that the single rod
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insertion due to diaphragm failure was not an actuation of the Reactor Protection System and
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did not meet the criteria for reportability. The licensee subsequently withdrew the 10 CFR 50.72 report. The inspector concluded that licensee reportability assessment and report
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withdrawal was appropriate. The cause of the diaphragm failure and associated corrective actions are discussed further in Section 4.2.
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2.3 High Pressure Coolant Injection System Inoperability i
Technical Specification 4.5.C.1 requires that surveillance testing demonstrate that the high pressure coolant injection system (HPCI) be capable of delivering at least 4250 gallons per
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minute (gpm) for a system head corresponding to a reactor pressure of 1000 to 150 pounds per square inch gauge (psig). This capability is tested monthly by operating HPCI in a recirculating mode, taking suction from the condensate storage tank (CST) and retuming flow to the CST via the full flow test line. Restricting orifice, RO-2301-59, positioned in the full flow test line establishes the system head pressure that correlates to reactor pressure.
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On June 30, HPCI was declared inoperable following surveillance testing because the system indicated a flowrate of 4,000 gpm which was less than the required 4,250 gpm. Problem
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Report 93.9308 was generated to document the event. Initial trouble shooting determined the speed control system was functioning properly and associated instrumentation was within proper ranges of calibration. The restricting orifice in the full flow test line was then disassembled and inspected. The restricting orifice is conical in shape with approximately i
seventy flow holes. The inspection revealed that portions of several plastic tie-wraps, pieces of an abrasive material similar to that of a grinding wheel, and one piece of a ferrous metal
were blocking orifice flow. The foreign material appeared to have entered HPCI via the condensate storage tank (CST). It is believed that the material was introduced into the CST during the recent refueling outage when significant volumes of water were routinely
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transferred throughout various portions of the station.
The orifice was cleaned, reinstalled, and the surveillance test was subsequently completed satisfactorily on July 1,1993, and the system was returned to service. The licensee is currently assessing additional preventive actions that include the addition of periodic orifice inspection to the preventive maintenance program and a remote camera or diver inspection of
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the CST to determine if any additional foreign material is present.
The inspector concluded licensee actions to restore HPCI operability were appropriate. At the conclusion of the report period, the proposed preventive actions were not finalized.
Status of these actions will be addressed during inspector review of the licensee event report submittal required by 10 CFR 50.73.
3.0 RADIOLOGICAL CONTROLS (71707)
3.1 Contracted Radiation Worker Exposure Limit Control and Termination Exposure Reporting The inspector reviewed the radiation exposure records of twelve workers selected at random
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from the refueling outage (RFO) 9 contractor workforce. By procedure the licensee established local whole body (WB) exposure limits which were more conservative than the regulatory limits of 10 CFR 20.101. Three of the workers exceeded the initial authorized
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local exposure limit of 750 millirem. In each case the licensee had properly used procedure i
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6.1-212, " Requesting and Authorizing Dose Control Levels", to evaluate and raise the
authorized WB exposure limit prior to the worker exceeding the initial authorized exposure
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limit. Each worker's total radiation exposure remained below the established regulatory i
limit. Three other workers received minor intakes of radioactive materials while performing maintenance on control rod drives. The magnitude of each internal exposure was properly-
evaluated and determined to be below regulatory limits. The licensee properly reported total
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individual radiation ex,osure incurred during the period of employment to both the NRC and I
to the individual as required by 10 CFR 20.408-409 for each of the twelve workers reviewed. The inspector concluded that radiation worker exposure limits were well
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mtrolled and personnel exposure results properly reported for RFO 9.
4.0 MAINTENANCE AND SURVEILLANCE (37828,61726,62703,93702)
4.1 Switchyard Betterment Program (Update)
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In 1987 the 345 KV switchyard insulators were coated with room temperature vulcanized silicone rubber (RTV) which improved insulator electrical resistance characteristics.
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However, during the past two years the switchyard has experienced several electrical faults i
due to breaker flashover which resulted from saltwater spray buildup or insulator icing
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during severe storms. The licensee established a Switchyard Task Force (STF) to develop a
plan to improve switchyard performance which was initially documented in NRC Inspection l
Report 50-293/93-03. The STF concluded that performance of the RTV coating had degraded due to loss of hydrophobicity caused by continuous exposure to electrical surface
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stress. This was consistent with the findings of Electric Power Research Institute (EPRI)
l sponsored studies on the same subject. When applied in 1987, the licensee believed the RTV
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coating would effectively minimize electrical flashover in the switchyard for a period of i
approximately 15 years. Actual experience at Pilgrim indicated that the coating was effective for a shorter period.
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The licensee cleaned and reapplied protective RTV coating to the top 25 percent of all
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switchyard breaker insulators located inboard of the offsite power line disconnects during the
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May - June 1993 period. This was an interim action pending test results from EPRI, which has been contracted to evaluate the performance of various coated insulators exposed to a j
harsh environment which will be simulated in a fog chamber test facility. The RTV coated l
insulators became pitted and covered by a dark pollutant film which formed due to continued service in the salt spray environment since 1987. Based on industry experience the licensee chose a dry cleaning process in lieu of steam cleaning to remove the degraded RTV coating.
A walnut shell and corn cob powder mixture applied with low pressure air was effective in removing the pollution film and restoring the smooth insulator surface. Licensee testing confirmed that the bottom portion of the insulators had satisfactorily retained their hydrophobic properties and were not in current need of recoating. The inspector observed the cleaning and reapplication of RTV coating te top 25 percent of the cleaned insulators.
The work was well controlled and completed with a minimum impact on offsite power supply availability to the sit '
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The STF intends to collect sufficient.information from EPRI testing to support resolution of several issues including (1) preventive maintenance or other methods to extend useful life of RTV coated switchyard insulators and (2) alternate designs of switchyard insulators.
Insulators of two design types which were used in the switchyard since RTV application in 1987 were sent to the EPRI test facility. Specific elements of the tests to be performed at the EPRI high voltage facility are under development, with testing to commence in July. An alternate option involving replacement of the existing 345 KV switchyard with a modern compactly designed switchyard which would be more resistant to the coastal environment has been presented for management review. The inspector concluded that STF efforts were progressing and receiving an appropriate level of management involvement.
4.2 Preventive Maintenance Deferral The inspector reviewed the preventive maintenance (PM) deferral process as described in procedure 3.M.1-1 " Preventive Maintenance", to determine whether overdue PMs (i.e., PMs not completed by their scheduled due date plus grace period) received appropriate review and deferral evaluation prior to becoming overdue. Procedure 3.M.1-1 allows deferral of PMs for up to one additional frequency interval beyond the original due date. The deferral process is initiated with a written deferral request by the responsible division or outage section manager. Procedure 3.M.1-1 contains a PM Deferral Request Form which requires review and approval by the responsible division manager, system engineer, and section manager prior to the PM becoming overdue. The system engineer review is included to ensure a technical assessment of deferral impact on component or system operability is performed. The inspector concluded that the procedure provides sufficient instruction for PM deferral.
The inspector reviewed the deferral file which contained completed forms for the deferral of approximately 200 PMs. The inspector noted the appropriate approval signatures including system engineer technical review and consistently established due dates extensions within 1 frequency interval. However, several deferral requests were not initiated until after the PMs were overdue. Comments concerning procedure intent were discussed with the PM program manager who initiated a procedure revision to clarify selected aspects of the deferral process.
Inspector review of the PM backlog indicated that responsible section and division managers did not consistently use the established deferral process when rescheduling PMs beyond the due dates. An example was the rescheduling of a large number of PMs from refueling outage (RFO) 9 to midcycle outage (MCO) 10. Outage management personnel conducted a resource review prior to RFO 9 and determined that available resources were insufficient to complete all of the outage PMs which would become overdue prior % '.!CO 10. The reliability centered maintenance (RCM) program manager was di.ceted to prioritize the pending outage PMs based upon existing commitments and impact on component performance. A group of PMs (approximately 200) from the bottom of the prioritized list was deleted from the outage schedule. However, the licensee did not use the established
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deferral process and, as a consequence, the licensee could not clearly identify to the inspector which PMs had been deleted from the outage schedule. The failure to use the deferral process resulted in a large number of PMs being postponed beyond their due dates without receiving system engineer technical assessment for impact on component or system
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operability. The licensee initiated problem report (PR) 93.0515 to document this concern.
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The inspector reviewed NRC Information Notice (IN)86-109, " Diaphragm Failure in Scram-l Outlet Valve Causing Rod Insertion", which informed licensees of an unplanned control rod insertion which occurred following an age related failure of a scram outlet valve diaphragm.
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In response to IN 86-109, the licensee developed procedure 3.M.4-76 " Scram Valve
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Maintenance and HCU Frame Inspection and Service", which establishes a nine year total diaphragm lifetime and a six year periodicity for scram inlet valve and outlet valve
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I diaphragm replacement. The six year interval was to be implemented by replacement of approximately one third of all scram valve diaphragms each refueling cycle. This PM was
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due to be performed on 49 individual control rods during RFO 9. Seventeen of these control
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rods had original installation scram valve diaphragms dating back to initial commercial operation in 1972. One of the PMs which was postponed from RFO 9, without use of the l
PM deferral process, was the replacement of the scram inlet valve and outlet valve
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diaphragms for control rod 42-39. The outlet scram valve diaphragm failed shortly after startup from RFO 9 as discussed in Section 2.2 of this inspection report. The licensee sent
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the failed diaphragm to a materials laboratory to determine the failure mechanism. Results of the laboratory analysi. were not complete at the end of this report period. Problem report
93.9303 was initiated to determine the root cause of the diaphragm failure and establish
corrective actions to preclude recurrence.
i The inspector noted that General Electric Service Information Letter (SIL) 457, " Scram
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Valve Diaphragms" recommends that the maximum " total lifetime" (i.e., shelf life plus service life) of scram valve diaphragms for BWR/4 applications be maintained at 15 years.
Procedure 3.M.4-76 infers a minimum six year diaphragm service life following installation.
i The nylon-reinforced Buna N diaphragm is procured with a manufacturer specified shelf life of 7 years. Station procedures permit the shelflife to be extended to 14 years based upon a i
procurement engineering evaluation. The inspector determined that current procedures permit a scram valve diaphragm to reach a totallife of 20 years prior to replacement. This differs from the information provided by NRC IN 86-109 and GE SIL 457. Following
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evaluation of these concerns, the licensee initiated revisions to procedure 3.M.4-76 and the shelflife determination process for the scram valve diaphragms. System engineers review vendor information letters for their systems and convey pertinent information to procurement personnel. However, this practice was not in place at the time SIL 457 was issued.
Completion of corrective actions will be tracked by PR 93.9303.
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l Licensee resolution of (1) Proper implementation of the PM deferral process including i
system engineer technical assessments, (2) Root cause determination for failed scram outlet
valve diaphragm, and (3) evaluation of shelf life controls for the scram outlet valve diaphragm and similar materials is identified as an unresolved item (50-293/93-13-01).
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5.0 SECURITY (71707)
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Selected aspects of plant physical security were reviewed during regular and backshift hours j
to verify that controls were in accordance with the security plan and approved procedures, i
This review concluded that performance was acceptable and included the following security l
measures. Security force staffing, vital and protected areas barrier integrity, maintenance of l
isolation zones, behavioral observation, and implementation of access control including
access authorization and badge issue, searches of personnel, packages and vehicles and i
escorting of visitors. Security force personnel continued to perform assigned duties j
consistent with security plan requirements.
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6.0 ENGINEERING AND TECHNICAL SUPPORT (71707)
6.1 Evaluation of High Pressure Coolant Injection and Reactor Core Isolation Cooling System Exhaust Line Rupture Disks
Recently a high pressure coolant injection system (HPCI) steam turbine exhaust line rupture disk failed during surveillance testing at another commercial nuclear power facility, resulting in personnel injury. Both the HPCI and reactor core isolation cooling (RCIC) system steam
turbine exhaust lines at PNPS utilize rupture disks to preclude overpressurization. The inspector discussed this industry experience with cognizant licensee personnel to determine site specific applicability.
The responsible system engineer evaluated the HPCI and RCIC turbine exhaust rupture disks and concluded that system design and maintenance differences between Pilgrim and the other facility made occurrence of a similar event at Pilgrim highly improbable. Both the HPCI and
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RCIC turbine steam exhaust lines have two rupture disks installed in series to protect the lines from overpressurization. The rupture disks are designed to relieve at 175 and 150 psig i
respectively. A pressure switch installed between the two disks is set to activate an alarm in the control room at 10 psig to warn operators of steam leakage past the inboard disk.
i Separate pressure switches in the turbine exhaust lines are set (at 150 and 46 psig
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respectively) to trip the HPCI or RCIC turbines prior to exhaust line disk rupture. In the event that both the inboard and outboard rupture disks actuate to relieve pressure, steam is exhausted to a high elevation within the torus room. This exhaust location would not normally be anticipated to be occupied during HPCI or RCIC operation. Inspector review of
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controlled system drawings, procedures, and procurement data sheets to assess rupture disk operation concluded that under normally anticipated modes of opemtion, HPCI or RCIC rupture disk actuation would not pose a personnel safety hazard.
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Title 10 CFR 50.55(a) requires that licensee Inservice Pump and Valve Testing (IST)
programs, updated at 10 year intervals comply with the requirements of the latest edition of the ASME Boiler and Pressure Vessel Code and Addenda existing 12 months prior to the
start of the 10 year program interval. The May 1992 update to the licensee IST program incorporated ASME/ ANSI OM-1-1987 which requires replacement of safety-related rupture disks every 5 years, unless historical data indicates a need for more frequent replacement.
The inspector verified that the HPCI and RCIC rupture disks were identified for replacement in procedure 8.I.l.1 " Inservice Pump and Valve Testing Program and the IST program coordinator confirmed the intention to replace the rupture disks according to the 5 year interval. The current HPCI rupture disks were installed in 1985 (inboard) and 1978 (outboard). No indication of disk leakage was evident during HPCI operation this report period. The inboard RCIC rupture disk indicated slight leakage, was replaced, and was satisfactorily retested in June 1993. The licensee properly incorporated the HPCI and RCIC rupture disks into their latest IST program update. Periodic replacement of the rupture disks via the IST program further reduces the likelihood of personnel injury due to rupture disk actuation.
6.2 Salt Service Water Pipe Replacement Completion In May 1992, the licensee initiated construction activities related to the replacement of a major portion of the buried carbon steel, salt service water (SSW) piping with new titanium pipe. This major modification was conducted in several stages, controlled by plant design changes PDC 91-10A through E, and completed during the recent refueling outage (RFO 9)
with the final tie-in of the new sections of piping into the existing train "A" and "B" SSW lines at both the plant intake structure and auxiliary bays. In accordance with the PNPS Technical Specifications, a SSW operability test (i.e., procedure no. 8.5.3.14) was successfully conducted and system operability verified on May 11, 1993.
Previous NRC inspections, as documented in reports 50-293/92-08,92-10,92-14 and 92-23, evaluated the design change, work control and construction practices implemented for the sequential stages of modification work, commenci.1g with the excavation for the new SSW piping vault and including installation of the first spool pieces of new titanium piping.
During the current inspection period, the inspector reviewed the completed records for the buried SSW pipe replacement and final loop connection activities, along with post-work and operability testing documents, verifying the acceptable return to service of both SSW loops during RFO 9. The inspector examined the complete document packages for maintenance requests (MR) 19104117 and 19201550 and selected a sample of testing, QC verification and nonconformance report corrective measure activities for further followup.
Specifically, the inspector confirmed adequate QC inspection of hold point activities in the maintenance work plans for pipe and pipe support installations. Documented evidence of the acceptable performance of hydrostatic testing of the piping in accordance with ASME B31.1 for the titanium spool pieces and ASME Section XI for the as-installed piping configuration
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9 was found to be in conformance with applicable code requirements. The inspector discussed leak test criteria with the cognizant BECo QA test personnel and determined that a drop test was conducted on the buried piping and visual verification of leak tightness for the accessible flanges was performed during routine system operation. With respect to the system pressure test requirements delineated in article IWA 5000 of ASME Section XI, the inspector questioned the visual examination criteria and controls employed during the conduct of the system leakage test of the thanium piping flanged connections. It was noted that the PDC specified mechanical joints as part of the installation details to eliminate the need for any field welding of titanium material.
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While the inspector identified no technical deficiencies in either the installation practices (e.g., torque control) of the new piping or the acceptance testing and results, the licensee did indicate an intent to evaluate the need for the qualification of additional inspectors to the VT-2 (i.e., visual examination) criteria of the ASME code, as a result of recent ASME Section
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XI edition interpretations. The inspector further checked postwork testing documentation and evaluated the consistency of the results with operational testing, the PNPS construction verification process, and ASME Section XI reporting requirements for " replacement" components. In assessing the adequacy of the programmatic controls, the following BECo procedures and specifications were reviewed:
PNPS Procedures
1.5.3, " Maintenance Requests"
1.13.1, "Pos: Work Test Matrices and Guidelines" e
3.M.1-30, " Post Work Testing Guidance"
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Nuclear Operations Procedures
NOP83El, " Control of Modifications to Pilgrim Station"
NOP83M1, "ASME Code Repairs and Replacements" Snecifications
M100E, " Shop Fabricated Titanium Pipe and Fittings" M301, " Field Fabrication and Installation of Piping and Installation"
The inspector also reviewed three nonconformance reports (NCRs 93-84,93-85 and 93-92)
regarding SSW pipe replacement activities to check status and evaluate the disposition and corrective actions. One each " accept-as-is, " repair," and " rework" disposition were selected for followup. As necessary, the inspector reviewed additional quality records to verify the completion of acceptable corrective measures and/or engineering analysis. In each case, the licensee disposition to the nonconforming condition reflected an appropriate action with respect to design and functional considerations. The inspector confirmed compliance with the applicable specification and code criteria for those activities involving pipe repairs.
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In reviewing the selected sample of quality records related to MRs 19104117 and 19201550 and assessing the completed records for the SSW piping replacement modification, the inspector identified a well documented history of quality construction and a well planned, conservative approach to implementation controls. The review of the MR log sheets provided a direct correlation to the safety-related activities supported by quality records.
Quality control inspections were in evidence and provided the requisite assurance of code, specification and procedure compliance. The inspector checked specific attributes for special
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process controls (e.g., torque application, welding, NDE, and testing) and identified no technical issues or quality concerns requiring further followup. The major modification governed by the staged implementation of PDC 91-10 has been installed over the past year with good management oversight and with the appropriate, objective measures of quality design and construction. The inspector has no further questions on this modification and considers its completion to represent a good example of PNPS betterment with an overall significant benefit to the future safe and reliable operation of the SSW system.
7.0 SAFETY ASSESSMENT AND QUALITY VERIFICATION (92701)
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7.1 Licensee Event Report (LER) Review LER 93-06 LER 93-06, " Reactor Building-to-Torus Train "B" Vacuum Relief System Actuation While
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Shut Down," describes the discovery by the licensee on March 15,1993 of the subject
engineered safety feature (ESF) actuation. Subsequent licensee review of plant computer information indicated that the air operated vacuum relief valve had cycled several times beginning late on March 14,1993 and had resulted in the in-service check valve hanging partially open. The NRC operations center was notified in accordance with 10 CFR 50.72 i
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on March 15, 1993.
At the time of the actuation of this vacuum breaker system, the plant was in cold shutdown, following a reactor scram on March 13,1993 due to a load rejection during a severe northeast storm. NRC inspection followup of the reactor scram is documented in inspection reports 50-293/93-05 and 93-06. Although primary containment integrity was not required to i
be maintained during cold shutdown condition in accordance with the PNPS Technical Specifications, the licensee continued to perform the surveillances for vacuum breaker accumulator leakage monitoring (procedure no. 8.C.36) and vacuum breaker valve position
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indication (procedure no. 2.1.15, daily log test no.16) once per shift. During the review of data from procedure 8.C.36, in conjunction with the operator monitoring of control room panel C-7 for vacuum breaker valve position, it was discovered that the reported event had occurred.
The cause of this ESF actuation event was attributable to the lowering of torus pressure due to response to the shutdown, coincident with the storm-induced winds increasing reactor building pressure slightly. The negative-pressure condition was corrected when nitrogen was
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added to the torus atmosphere and subsequently the partially open check valve was closed i
l through operator manipulation of the air operated valve to allow the positive torus pressure to reseat the valve. A critique board was convened on March 16,1993 to review the event and the critique memorandum, dated March 24,1993, was reviewed by the inspector.
The inspector reviewed LER 93-06, submitted in accordance with 10 CFR 50.73 (a)(2)(iv),
i for consistency with the conditions and actions described in the event critique memorandum.
j Additionally, PNPS procedures 8.C.36 and 2.1.15 were reviewed, along with Nuclear Organization Procedure NOP 92A1 on problem reporting. Problem Report 93.9092 was
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examined, as were the records documenting the conduct of the surveillances associated with
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the vacuum breaker accumulator leakage monitoring on March 15 and 16,1993. The inspector confirmed the implementation of one programmatic corrective action; i.e., the revision of PNPS procedure no. 8.M.3-4, governing the reactor building to torus vacuum breaker sensor calibration, to decrease the setpoint of the alarmed pressure instrument switch
(DPIS-5040A) below that of DPIS-5040B, which has no high differential pressure alarm.
Since during this event the unalarmed vacuum breaker valve (AO-5040B) had opened, no alarm was received by the operations staff since the pressure differential was relieved without
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opening the alarmed valve.
In effect, the above corrective action should provide "real-time" notification to the operators of vacuum breaker actuation without reliance upon the subsequent review of surveillance results. The inspector considers this procedural enhancement, along with the operator checks
of valve position each shift (reference: procedure no. 2.1.15), to be adequate to address any concerns regarding a potential unidentified breach of primary containment integrity.
The inspector discussed LER 93-06 with licenrm operations, compliance and support personnel and concluded that the report details were accurate and corrective measures were appropriate to the event. One minor documentation error relative to surveillance records for
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procedure no. 8.C.36 was brought to the licensee's attention. This error had no bearing on
either the cause or followup of the event and is currently being corrected by operation support personnel (reference: Problem Report 93-9330). The inspector has no further questions regarding LER 93-06 and determined that the report properly addressed the reporting criteria and correctly assessed the safety consequences of this event.
LER 93-07
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LER 93-07, " Automatic Closing of the Reactor Core Isolation Cooling (RCIC) System Turbine Steam Supply Isolation Valves due to High Steam Flow Signal", dated April 16, 1993, describes the March 17 unplanned automatic primary containment isolation system (PCIS) Group 5 actuation which occurred while attempting to place the RCIC system in standby service. The RCIC steam supply valve (MO-1301-16) did not open on the first several attempts to jog open the valve. The operator then held the control switch in the open position for a longer period of time and the valve opened. However, the valve opened further than intended, since the control switch was held open longer, which resulted in the
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high steam flow signal and Group 5 actuation. Both RCIC steam supply isolation valves (MO-1301-16 and MO-1301-17) closed as designed in response to the isolation signal
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i properly performing th.ir PCIS function. Reactor temperature was approximately 360 degrees and pressure was 130 psig when the system isolated. The inspector confirmed that the RCIC system is not required to be operable under those plant conditions.
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Corrective actions inleded repeated operation of MO-1301-16 using procedure 8.5.5.4,
"RCIC Motor Operated Valve Operability Test Monthly / Quarterly." The valve functioned properly in each instance. The licensee increased the frequency of the monthly MO-1301-16 operability test to weekly, as a conservative measure to provide added assurance of reliability. A failure analysis team concluded that the most credible cause of MO-1301-16 failure to open was intermittent operation of the torque switch bypass circuitry which is part of the valve's opening circuit. Further root cause inspection was scheduled for RFO 9, when plant conditions support disassembly of the valve actuator. The LER accurately described the event and addressed reporting criteria. The licensee will submit a supplemental LER
following completion of the root cause analysis.
Subsequent to this LER, the licensee determined that an electrical jumper across the limit switch which bymsses the torque switch in the open direction had not been reinstalled following actuato overhaul during midcycle autage No. 9. Problem reports 93.9213 and 93.9320 were initiated to address the missing jumper and a subsequent wiring discrepancy.
The inspector reviewed the problem reports and the draft supplemental LER 93-07-01, and concluded that the licensee initiated corrective actions were appropriate to preclude recurrence. The in:;pector had no further questions.
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1.ER 93-08
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LER 93-08, " Failure to Perform Functional Test of Control Room High Efficiency Air Filtration System Humidistats in 1990," describes the determination on April 9,1993 that a once-per-cyc. operability verification of the subject humidistats had been incorrectly omitted
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from the functional test performed on March 10, 1990. This omission resulted in a period (o er 42 months) between successful testing which violated the Technical Specification
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surveillance requirement for the control room high efficiency air filtration (CRHEAF) system
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humidistats.
The inspector confirmed that the subject humidistats were tested on January 23,1992 with satisfactory as-found results, indicating no evidence of component or system inoperability i
during the 42-month window of concern. Prior to the conduct of the successful functioral test in January 1992, the procedure controlling the surveillance activity had been revised to j
better ensure performance of all required steps when a preceding section of the procedure is not performed. The inspector reviewed tne current revision of procedure 8.E.47.1 and
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determined that the current details provide adequate instructions to the Instrumentation and
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Control (I&C) technicians and supervisors responsible for surveillance conduct and procedural completion.
The inspector also noted that the I&C division personnel received additional instruction on
the performance of procedure 8.E.47.1 and that I&C supervisor had received training
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regarding the responsibility of an I&C review (reference: BECo reply to NRC Notice of
Violation 50-293/92-28-01). These corrective actions appeared to be adequate in addressing
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the identified procedural and personnel deficiencies relative to the missed surveillance. The inspector concurred with the licensee position that this event posed no safety threat, since no component failure was identified and the CRHEAF system was capable of performing its safety function during the period of time in question.
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The inspector evaluated LER 93-08 relative to the reporting requirement in 10 CFR 50.73 (a)(2)(i)(B), the CRHEAF system surveillance requirement in section 4.7.B.2.d of the PNPS Technical Specifications, and the geral reporting criteria for licensee event reports. The inspector determined that the LER accurately described the event and completed corrective actions and that no safuy issues or questions remain unresolved relative to the identified technical specification violation.
In accordance with section VII.B.(2) of 10 CFR 2, Appendix C, the Technical Specification violation identified in LER 93-08 was properly reported to the NRC and otherwise satisfies criteria, including the conduct of the corrective action noted above, for the mitigation of -
enforcement sanctions. Therefore, this violation is considered to be a noncited violation.
8.0 NRC MANAGEMENT MEETINGS AND OTIIER ACTIVITIES (30702)
8.1 Routine Meetings At periodic intervals during this in ips 7ectings were held with senior plant
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management to discuss licensee acti-
. s.: > 1. es of concern to the inspectors. At the
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conclusion of the reporting period, the +'
nector staff conducted an exit meeting on
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July 20,1993, with licensee management summaria.ig the preliminary findings. No
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proprietary information was identified as being included in the report.
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8.2 Management Meetings
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On June 10, NRC regional management conducted a Systematic Assessment of Licensee Performance (SALP) management meeting at the Chiltonville, MA training center. Results of the NRC SALP for the period September 29,1991 to March 13,1993 were presented and
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discussed with licensee management. The meeting was open to the public.
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8.3 Other NRC Activities i
On June 9-11, an NRC Region I electrical specialist conducted an inspectic.n to follow-up issues identified during a previous NRC Electrical Distribution System Functional Inspection (50-293/91-80). Inspection results will be documented in NRC Inspection Report 50-293/93-11.
On June 14-18, an NRC Region I safeguards specialist conducted a security program inspection. Inspection results will be documented in NRC Inspection Report 50-293/93-10.
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