IR 05000293/1993019
| ML20058D900 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 11/23/1993 |
| From: | Eugene Kelly NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20058D898 | List: |
| References | |
| 50-293-93-19, IEIN-93-079, IEIN-93-79, NUDOCS 9312060087 | |
| Download: ML20058D900 (16) | |
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U. S. NUCLEAR REGULATORY COMMISSION f
REGION I
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Docket No.:
50-293
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Report No.:
93-19
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Licensee:
Boston Edison Company 800 Boylston Street
Boston, Massachusetts 02199
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Facility:
Pilgrim Nuclear Power Station location:
Plymouth, Massachusetts l
Dates:
September 28 - November 1,1993 Inspectors:
J. Macdonald, Senior Resident Inspector
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A. Cerne, Resident Inspector
D. Kern, Resident inspector Approved by:
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E. Kelly [ Chi.
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Reactor Proje ts Section 3A Scope:
Resident safety inspections in the areas of plant operations, maintenance and surveillance, engineering, and plant support. Initiatives selected for inspection
included motor operated valve design program review and NRC Information Notice 93-79, * Core Shroud Cracking at Beltline Region Welds in Boiling Water Reactors."
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Inspections were per formed on backshifts during September 29, October 5, 8,15, j
18-19, 25-26, and November 1. Deep backshift inspection was performed on October 5 (10:00pm - 12:00 midnight).
I Findines:
Performance during this five week period is summarized in the Executive Summary.
l 9312060087 931124 PDR ADOCK 05000293 Q
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EXECUTIVE SUMMARY Pilgrim Inspection Report 93-19
i Plant Operations: Operators and technical personnel were alert in identifying emerging
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equipment problems and resolving operational anomalies. Corrective actions were accomplished I
in a timely manner to restore systems to normal operating configurations.
f Maintenance and Surveillance: The configuration, condition and operational controls for the
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emergency diesel generator (EDG) air starting and turbo-boost assist system properly support the design function of the EDGs. A design change was successfully implemented to replace the existing belt driven fuel booster pump with a more reliable gear driven design on the "A" EDG.
Maintenance and surveillance testing was consistent with vendor recommendations and satisfied all regulatory commitments and Technical Specification requirements.
t Licensee event reports accurately documented corrective actions to address material and procedural problems.
Redundancy noted within surveillance and preventive maintenance
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procedures may result in unnecessary operation of some safety-related components and l
consequentially reduce system reliability. The licensee was reviewing this concern at the end l
of the report period.
Engineering: Engineers demonstrated an excellent questioning attitude and determined that the industry practice of using run efficiency in place of pullout efficiency to calculate the output torque capability of DC powered motor operated valves (MOVs) was incorrect. This new information resulted in the high pressure coolant injection system outboard steam supply valve being declared inoperable.
Follow-up actions were thorough and promptly completed.
Additionally, appropriate corrective actions were initiated to address errors identified during a review of engineering MOV calculations.
The industry issue of reactor vessel core shroud cracking in boiling water reactors was comprehensively assessed, although Pilgrim remains susceptible and BECo has not yet performed the GE-recommended shroud inspections. Quality assurance personnel have been closely involved during this review. Management has recognized the importance of coordinated work
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scheduling to ensure that an appropriate shroud inspection is performed during the next refueling outage.
Plant Support: Security force members responded effectively to the discovery of an unloaded hand gun, with ammunition, in a carrying bag during routine personnel and property checks at an access control point prior to entry into the protected area. Immediate actions to secure the gun, interview the owner, and complete required NRC notifications were appropriate. Security management verified the gun was properly registered and the owner had a valid license to carry the firearm. Ultimately, it was determined the gun and ammunition had been inadvertently left in the bag.
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SUMMARY OF FACILITY ACTIVITIES At the start of the report period Pilgrim Nuclear Power Station was operating at approximately 100% of rated power.
On September 28, the tailpipe temperature for safety relief valve 203-3A rose above 212 degrees. The te2nperature returned below and again rose above 212 degrees several times during the report period, but remained below the limit established by licensee engineering evaluation for safe continued operation.
On September 30, a blown fuse in the high pressure coolant injection (HPCI) system flow controller was idendfied during preparations to perform a routine surveillance. The licensee initially notified the NRC in accordance with 10 CFR.50.72 that the HPCI system was inoperable. Engineers subsequently determined that the blown fuse affected the availability of flow indication only and did not make the HPCI system inoperable. Laar the same day, engineers determined that the HPCI outboard steam supply valve (MO-2301-5) had insufficient thrust to ensure clcisure in the event of a HPCI steam line break (See Section 4.1). The HPCI system was declared inoperable and the second isolation valve in that steam line was immediately closed. Repairs were made and MO-2301-5 was successfully retested and returned to service on October 4.
On October 23, the reactor core isolation cooling (RCIC) system was declared inoperable in order to effect valve position problems identified following successful completion of the routine quarterly surveillance. The RCIC system was returned to service on October 24. The reactor was operating at full power at the close of the inspection period.
2.0 PLANT OPERATIONS (71707, 40500, 90701)
2.1 Plant Operations Review The inspector
.1 the safe conduct of plant operations (during regular and backshift hours)
in the followN uns:
Contu. Loom Fence Line Reactor Building (Protected Area)
Diesel Generator Building Turbine Buildmg Switchgear Rooms Screen House Security Facilities Control room instruments we.e independently observed by NRC inspectors and found to be in correlation amongst channels, properly functioning and in ec7formance with Technical 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 ia accordance with Technical Specification requirements. Posting and control of radiation contamination, and high radiation areas were appropr%te. Workers complied with radiation work permits and appropriately used required personnel monitoring devices.
Plant housekeeping, including the control of flammable and other hazardous materials, was 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 communication of equipment status. These records included various operating logs, turnover sheets, tagout, and lifted lead and jumper logs.
2.2 Control Room Activities and Plant Obmations During this inspection period, the inspector witnessed operator shift training, routine controls manipulation to support plant evolutions, and follow-up actions to troubleshoot and correct equipment problems. Additionally, plant status ar.d component configuration questions raised as a result of plant tours were discussed with opemtions section and other cognizant personnel.
The following represent specific observations and areas of follow-up review by the inspector:
On September 30,1993, the NRC issued Information Notice (IN) 93-M Core Shroud
Cracking at Beltline Region Welds in Boiling Water Reactors (BWRs). The inspector observed training of the on shift licensed operators relative to the core shroud cracking issue discussed in NRC IN 93-79. The training, conducted by an instructor from the Operations Training Section, outlined current industry experience, applicability to the PNPS core shroud, and potential consequences of shroud failure. Inspector review concluded the draft student guide (0-RQ-04-01-26) used for instruction effectively provided operators with a good preliminary level of detail on this issue. Additional technical discussion of NRC IN: 93-79 is documented in section 4.2 of this inspecti^n report.
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+d the removal of Temporary Modifications hack panel instrumentation related to the (TM) 93-52 and 93-53 from the contro'
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recirculation motor generator (MG) se. p a control circuits. As documented in j
inspection report 50-293/93-15, the installatis. of these TMs allowed for the continuous recording of speed control signals on both the "A" and "B" recirculation pump MG sets.
Corrective measures to address several pump speed control runbacks which had occurred since RFO 9 included replacement of both speed limiter modules on each recirculation pump spcxx! control circuit. These actions appear to have effectively corrected the pump runbacks. Therefore, the TMs were removed and the control panels restored to their normal configuration.
With the reactor water cleanup (RWCU) system removed from service from October 18 -
21, 1993 for valve maintenance, the inspector verified the nuclear watch engineer's attention to the reactor water chemistry limits specified not only by the PNPS Technical Specifications, but also by the more conservative criteria controlled by the Electric Power b
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Research Institute (EPRI) action levels or General Electric guidelines. These limits and criteria are delineated in PNPS Procedure 7.8.1, " Water Quality Limits," which discus.,es the frequency of measurement along with the various actions available to minimize the advent of water chemistry problems. Spccifically, for reactor water conductivity, the inspector noted operator cognizance of entry into EPRI Action Level 1.
With the restoration of the RWCU system on October 21, the ionic impurities measured by the conductivity parameter were reduced below the level requiring any further technical evaluation or action.
- On October 20, 1993 reactor power was reduced to approximately 50% and the "B" l
seawater pump was secured to investigate an upper motor bearing lubrication oil leak.
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The "B" seawater pump is one of two 50% capacity non-safety related pumps that
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supplies cooling or circulating water for the main condenser. Troubleshooting revealed a pinhole leak in the cooling water coil to the lube oil reservoir. The inspector discussed the planned licensee repairs with the nuclear water engineer and reviewed the vendor
l drawing illustrating the component disassembly required to effect npairs. On October i
21, after the completion of repairs to both the cooling coil and an upper thrust bearing l
temperature element identified as broken, the inspector witnessed the startup of "B" seawater pump from the corrol room and preparation for return to full power.
i On October 16, the discharge pipe temperature for the safety-relief valve (SRV-203-3A)
on the "A" main steam line increased to approximately 235 degrees Fahrenheit (F). The steam leak associated with the tail pipe temperature rise stopped when reactor pressure l
was lowered on October 20 to repair the "B" seawater pump (see above). On October 27, the tail pipe temperature rose again to approximately 230 F; then decreased the next day when reactor pressure was lowered slightly. These incidents of SRV leakage, likely associated with simmering of the pilot valve on the two-stage Target Rock relief valve, followed a brief period of less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> starting on September 28, when the discharge pipe temperature of SRV-203-3A rose slightly above the 212 F criteria delineated in PNPS Technical Specification 3.6.D.3. The inspector verified that the licensee performed an engir,eering evaluation in accordance with the Technical Specification requirements, which concluded that continued operation up to a tail pipe temperature of 255 F is permissible.
The inspector reviewed the BECo Engineering Evaluation, noting that the 255 F Hmit corresponds to an equivalent calculated steam leak, below which, the tolerance of the lift setpoint of the SRV should not be adversely affected. The basis for this temperature limit is provided in an General Electric Report, NEDE-30476, which used tests and i
analyses to correlate SRV leakage with setpoint drift.
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The inspector also noted a night order in the control room, indicating that the chief l
operating engimr should be contacted if the tail pipe temperature reached 245 F, thus allowing time for any decision to shutdown upon continued leak degradation. During
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visits to the control room, the inspector checked the SRV tail pipe temperature recorder l
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and confirmed that the alarm for high discharge temperature on SRV-203-3A was appropriately disabled to allow the other SRVs to round a high temperature alarm, if required. Interviews with cognizant licensx staff indicated the licensee's intent to replace both the main and pilot stages of SRV-203-3A during the next outage in excess of the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> specified in the PNPS Technical Specifications (Note: After the l
conclusion of this inspection period, a forced outage of such a duration did occur and j
SRV-203-3A was in fact replaced, as planned.).
L The inspector reviewed three Problem Reports (PR 93.9437,9438 and 9439) related to
the reactor core isolation cooling (RCIC) system inoperability from October 23-24 and discussed the identified component malfunctions and functional significance with
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operations personnel. The inspector confirmed licensee reportability, in accordance with l
10 CFR 50.72, of a primary containment isolation system (Group V) actuation upon high I
steam supply flow upon RCIC testing to return the system to operable status. The isolation was apparently caused by air in the hydraulic oil for RCIC turbine control valve, which resulted in a slow valve response upon steam admission. The air entered l
the valve hydraulic system during an oil change and was not fully vented prior to RCIC system testing. The inspector reviewed the applicable PNPS procedure 8.5.5.1, "RCIC Pump Operability Flow Rate and Valve Test at Approximately 1000 PSIG," noting that this quarterly surveillance checks operability for the RCIC turbine control valve (HYD-1301-159). The limiting condition for operation of RCIC was cleared upon successful conduct of procedure 8.5.5.1 on October 24.
The inspector also reviewed the events surrounding separate half scram events (i.e.,
channel "B" on October 28 and channel "A" on October 31) related to the reactor water level signals into the reactor protection system (RPS) circuitry. The inspector discussed the licensee anzlysis of these events with operations and technical personnel and concluded the events were not only unrelated to each other, but also not connected to actual reactor water level discrepancies or level transmitter problems. In the first case a problem with an electrical trip unit module in the RPS "B" relay cabinet appeared to cause the unanticipated half scram. This was corrected by replacement of the module.
In the latter case, improper valve manipulation during the conduct of PNPS procedure 8.M.1-33, " Instrument Welkdown," to verify valve lineups was identified as the cause of the half scram.
The completion of 8.M.1-33 was suspended until additional instruction of the personnel involved in the valve checks could be conducted.
During a plant inspection-tour, the inspector noted loose bolts on the "A" train 4.16 KV
switchgear cabinet doors and questioned the acceptability of the condition. The licensee responded that the closure bolts were backup to the door handles and didn't affect component operability, but agreed that the bolts should be tightened to provide a better closure configuration for the switchgea.
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The inspector also identified missing Jowel pins on the shim supports for the "B" train RPS motor-generator (MG) set. This condition does not adversely affect the function of this fail-safe component, but the licensee initiated a work request to correct the discrepant equipment condition.
Overall, the above inspection activities confirmed acceptable licensee response to emerging equipment problems, safety system actuations and identified operational anomalies.
The inspector determined through the interviews of several operations personnel and the cognizant technical support personnel that BECo has adequately addressed the noted operational issues as they have arisen and has taken the appropriate corrective action in a timely manner. Further followup of certain of the above areas of inspection may be conducted relative to LER closure and/or future system inspections.
3.0 MAINTENANCE AND SURVEILLANCE (61726,62703,71710,90712)
3.1 Licensee Event Report Review
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The inspectors reviewed Licensee Event Reports (LERs) submitted to the NRC to verify accuracy, description of cause, previous similar occurrences, and ifectiveness of corrective actions.
The inspectors considered the need for further information, possible generic implications, and whether the events warranted further onsite follov up. The LERs were also reviewed with respect to the requirements of 10 CFR 50.73 and the guidance provided in NUREG 1022.
- LER 93-17 LER 93-17, "High Pressure Coolant Injection (HPCI) System Inoperable due to Unplanned Isolation During Surveillance Testing", dated August 13, 1993 describes the July 21, 1993, unplanned isolation of the HPCI steam supply during performance of procedure 8.M.2-1.5.10,
"HPCI Vacuum Breaker Isolation Valve Testing." The root cause of the event was !ailure to properly revise procedure 8.M.2-1.5.10 following implementation of a plant design change (PDC 91-75). Prior to PDC 91-75, the HPCI steam supply valves were not affected during the portion of the surveillance in question. However, implementation of PDC 91-75 resulted in automatic l
closure of the two HPCI steam supply valves. This affect on the HPCI system was not identified during the plant impact review process associated with implementation of the PDC.
The surveillance was promptly stopped and the HPCI system was returned to its normal lineup within 10 minutes. The event was of minimal safety significance. The LER properly addressed all reporting criteria and thoroughly described the event.
Corrective action in response to this event included correction to procedure 8.M.2-1.5.10, counselling of the Instrumentation and Controls supervisor who had performed the procedure i
impact review and expanded impact reviews of HPCI logic test procedures. The licensee
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critique further identified a potential for impact reviews to be misassigned or to bypass affected maintenance disciplines. The inspector reviewed the revision to procedure 8.M.2-1.5.10 and i
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determined that corrective action had been properly implemented to preclude recurrence of this event. However, the inspector noted that performance several Technical Specification required procedures (including 8.M.2-1.5.10) resulted in repeated cycling of safety-related motor operated
valves (MOVs) on a frequent basis. The inspector questioned whether redundancy within current surveillance and preventive maintenance procedures resulted in unnecessary repeated operation of safety-related MOV; and potential adverse impatt on reliability. This concern was under licensee review at the end of this report period.
- LER 93-18
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LER 93-18, " Completion of a Shutdown Due to Reactor Coolant Pressure Boundary Leakage,"
dated August 18,1993 describes the July 22,1993, plant shutdown which commenced as a result of an increased unidentified reactor coolant system leakage, and was completed as a shutdown required by the Technical Specifications because the leak was located at an unisolable pressure boundary weld on the reactor vessel drain line. As documented in NRC inspection report 50-293/93-14, the weld was repaired and hydrostatically tested and a reactor restart commenced on July 25,1993. Since that time, reactor coolant unidentified leakage has remained less than 0.25 gpm, which is considerably below the 5 gpm limit allowed by the PNPS Technical Specification.
NRC inspection of the plant shutdown and licensee activities related thereto identified an unresolved item (50-293/93-14-01) associated with the event details and corrective actions documented in LER 93-18. Subsequently, on October 7,1993, BECo submitted a supplemental Licensee Event Report (LER 93-18-01)in accordance with 10 CFR 50.73 to clarify the facts surrounding this event and the one-hour event notification required by 10 CFR 50.72.
The inspector noted that LER 93-18-01 describes in greater detail the plant conditions at the time that the reactor coolant pressure boundary weld leak was identified by the licensee. The report also discusses the licensee position relative to the NRC immediate notification requirements that were applicable to this event. The adequacy of BECO's position in this regard is the subject of the unresolved item, which will be reviewed during a future inspection. With respect to LER 93-18, the licensee submitted supplemental information, in accordance with 10 CFR 50.73(c),
upon the determination that the original LER was not sufficiently detailed to facilitate the understanding of this event. The inspector has no addi'.ional questions regarding LER 93-18 and notes that the substance of supplemental LER 93-18-01 will be reviewed during NRC followup of unresolved item 93-14-01.
- LER 93-19
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I LER 93-19, " Automatic Closing of Primary Containment System Group 3 Isolation Valves
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While Shutting Down," dated August 23, 1993, documents the July 22, 1993 actuation of a residual heat removal (RHR) system isolation in the shutdown cooling mode of operation. This isolation, as controlled by the primary containment isolation system (PCIS), was determined to have been caused by a momentary pressure transient in the RHR suction piping and resulted in l
the appropriate Group 3 isolation to protect the shutdown cooling piping against
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overpressurization.
NRC followup of this event and analysis of the safety impact are documented in the NRC inspection report (IR) 50-293/93-14, Section 1.2. The inspector concluded that the PCIS actuation, while reponable in accordance with 10 CFR 50.73, did not represent a protective action that was actually needed by the plant conditions at that time.
During this inspection, the inspector reviewed LER 93-19 and confirmed that no new information relative to the details of this event or its safety consequences had arisen. Existing i
licensee controls to establish shutdown cooling were deemed adequate and the applicable pressure switches were verified to be functioning properly. Hence, licensee corrective action appears to be directed toward review of the need for a slower response time in the affected pressure switch circuity.
The inspector noted that while three similar events occurred during the establishment of shutdown cooling in the 1989/90 time frame, improved venting techniques and procedures appeared to preclude problem recurrence until the current event. The inspector therefore believes that the licensee corrective measures appear appropriate and commensurate with the
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safety significance of such an event as this shutdown cooling isolation upon RHR establishment.
LER 93-19 describes this event, its cause, and the BECo analysis of the need for corrective action in a manner consistent with the NRC understanding of the facts, as documented in IR 93-14. This LER adequately addresses the reportability criteria of 10 CFR 50.73 and the inspector has no further questions regarding this event or the licensn response.
3.2 Engineered Safety Feature System Walkdown (71710)
The inspector conducted a walkdown inspection of the air starting and turbo-boost assist air systems for both emergency diesel generators (EDG). For the "A" EDG, the inspector also examined the completed installation of a new gear driven fuel booster pump, checking compliance with the criteria and configuration controls delineated in plant design change, PDC 88-19. In addition to the review of component conditions, valve lineup; and instrument setpoints, the inspector observed the automatic actuation of "B" starting air compressor to charge both starting air receivers to the preselected air pressure of 250 psig. Also, the inspector witnessed a delivery of the EDG fuel oil to the site; confirming chemistry sampling prior to j
unloading in the "A" ad "B" underground storage tanks and discussing fill operations with both the licensed operators on shift and the fuel oil vendor representative.
With regard to the PDC 88-19, the inspector reviewed all the field revision notices (FRN) for design change details, verifying the modified fuel oil system booster pump and piping system l
layout in accordance with design requirements. The inspector noted that FRN 88-19-05 specified l
that a two-inch long fillet weld on a pipe suppon could be replaced by whatever length of weld j
l was available from the field positioning of attached members. The resulting weld was a little over one-inch long, which the inspector confirmed as acceptable per welding code and design
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strength requirements. However, the inspector discussed this FRN with nuclear engineering i
department (NED) and compliance personnel, pointing out that the substitution of as-built details I
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for specific design criteria warrants engineering followup and documentation of the acceptability
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of the resulting field configuration. In this particular case, the up front design conservatism l
provided sufficient margin to prevent the installation of an undersized weld.
The inspector also reviewed the GE/ALCO vendor manual (V-454) for the EDGs, specifically checking the engine controls and starting sequence provisions to be consistent with the mode
selector switches and component lineup observed in the field. The inspector spot-checked the alarm response procedures (ARP) krated at each EDG local control station, verifying that ARP-C103B-C5 had been correctly revised to account for the fuel oil booster pump changes implemented by PDC 88-19. The inspcor also confirmed that the receiver tanks in the air start system for both EDGs are bled of moisture daily, in accordance with the guidance of GE services information letter (SIL No. 4).
Various procedural requirements for EDG operation, surveillance, and individual starting air motor performance tests were reviewed for consistenev with field observations. The inspector noted instructions in PNPS procedure 2.2.8 for st g the "B" EDG with a failed fuel booster pump drive belt. The specified operator actions are not applicable to the "A" EDG because of
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the modifications associated with PDC 88-19. With regard to the EDG surveillance procedure
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8.9.1, the inspector identified local diesel start testing for each EDG monthly, alternating
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l aetween the two redundant air starting systems so that each air start train is tested every other month. The inspector questioned this surveillance process in light of engineering determinations made relative to temporary procedure, TP92-038, and problem repon, PR 93.9446, that l
provided the basis for continuing EDG operability with air staning and turbo-boost assist l
components out of service. The basic question involved the reliability of one train of starting l
air if the components of that specific train had not been surveilled within the last month.
The inspector reviewed the Bechtel specification 6498-M-6 for the EDGs and the acceptance criteria for the preoperational testing of the EDGs conducted in 1972. It was noted that four
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successful EDG starts were obtained from each air start train without using the starting air compressor to re-charge the receiver tanks. This testing not only demonstrated compliance with l
starting air design criteria, but also provided evidence of a conservatism relative to the FSAR l
commitment of " sufficient air for two normal starts" per each air receiver train. The licensee also provided the inspector with an evaluation of the EDG air start failure rates that analyzed the probability of a failure based upon the length of time since its last successful air start test l
(i.e., in this case two months versus the standard one month testing frequency). The increased
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failure probability was determined to be insignificant from a safety perspective, in terms of both demand response statistics and the fact that there is no evidence of a direct correlation of air start system degradation as the time between surveillances is increased.
The inspector considered this licensee evaluation to represent art acceptable analysis of the current EDG surveillance strategy, particularly given the alarms, r atomatic design actuations and operator routine and response activities which are in evidence for starting air system abnormalities. The licensee did indicate that consideration will be given to the surveillance t
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scheme of the starting air system, should removal of a redundant train be required for future planned maintenance or modification activities. The inspector views this approach to be prudent and had no additional questions in this area.
With regard to the overall configuration, condition and operational controls observed relative to the air starting and turbo-boost assist systems on each of the EDGs, the inspector identified no unresolved issues or areas of safety concern. The system design and licensee program for maintenance and testing appears adequate to meet or exceed all regulatory commitments and technical specification requirements.
4.0 ENGINEERLNG (37828, 71707, 92700, 92701)
4.1 Motor Operated Valve Design Review The licensee established a motor operated valve (MOV) team to perform design reviews of
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various MOVs, recommend modifications to improve MOV design margin, and incorporate l
current industry information in response to NRC Generic letter 89-10, " Safety-Related Motor Operated Valve Testing and Surveillance" into existing MOV programs. Published industry guidance, Electric Power Research Institute (EPRI) technical report (TR) 100449 "MOV Margin Improvement Guide" dated February 1992, stated that running efficiency can be used to evaluate MOV thrust capability in the closing direction since the motor is at its full running speed by the l
time significant loading occurs. This guidance did not differentiate between altemating current (AC) and direct current (DC) powered MOVs. Similar guidance was contained within NRC
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inspection program documents. Based on this guidance, engineers substituted the running efficiency for the previously used and more conservative " pullout" efficiency value and recalculated available thrust for two MOVs whose design margins were small.
l During the MOV design review process, licensee engineers questioned the use of running efficiency in place of the more conservative pullout efficiency when calculating DC powered MOV torque output capability in the close direction. Pilgrim engineers noted that the speed of l
an AC powered motor remains relatively constant in the range of MOV operation. A DC i
powered MOV however, is expected to slow down when mechanical load increases as the valve l
approaches the closed seat position. The licensee contacted the MOV vendor who orally j
clarified use of run efficiency versus pullout efficiency. The vendor stated that due to the
differences in operating characteristics between AC and DC motors, run efficiency can be i
applied to only AC MOVs in the close direction of motion. Direct current powered MOVs must use pullout efficiencies when calculating available thrust in the close direction. Engineering department personnel promptly reviewed existing MOV thrust calculations to determine what I
impact if any this new information had on operability. Analysis determined that the HPCI outboard steam supply valve (MO-2301-5) may not have sufficient thrust to close during a HPCI
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steam line break. The valve was immediately declared inoperable, the HPCI inboard steam supply valve was shut and deenergized, and problem report (PR) 93.9422 was issued to restore MO-2301-5 to an operable condition. The reactor core isolation cooling system and the balance
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of the emergency core cooling systems remained available to provide core cooling if called upon.
Design review personnel demonstrated sound initiative in questioning existing industry guidance and promptly initiated corrective action.
Plant design change (PDC) 93-03-86 was implemented to modify the overall gear ratio of the motor operator from 27.2 (0.4 pullout efficiency) to 25.65 (0.6 pullout efficiency). Design calculation M-565 revision 1, determined the post modification available MOV thrust to be approximately 12 percent greater than that necessary for MO-2301-5 to close as designed during a HPCI steam line rupture. Post modification testing was successfully completed and MO-2301-5 was returned to service on October 4.
The licensee notified the industry of the apparent misapplication of efficiency factor guidance provided in TR-10N49 via the Nuclear Network.
At least one other utility has subsequently contacted the licensee stating that use of the run efficiency factor for a DC powered MOV had resulted in declaration of an inoperable safety-related MOV. The inspector reviewed various engineering calculations and confirmed that the licensee had used running efficiency in the close direction for only one other MOV. The available design margin for the second valve, (reactor water cleanup system isolation valve MO-1201-5), was reduced, but the MOV remained operable. The inspector noted minor errors in MOV size designations documented in engineering calculation M-569 (revision 1) and questioned the MO-2301-5 overall gear ratio used in previous calculations. These errors did not impact MOV operability, but had the potential to adversely affect available thrust calculations.
Engineering department representatives initiated appropriate corrective action to address this concern. In addition, a revision to Nuclear Engineering Department Work Instruction 430 was initiated to correct the procedural use of run versus pullout effi:iency factors for MOV thrust calculations. Operability of MO-2301-5 was restored in a reasonable time and action taken to notify the industry and assess operability impact on the remaining safety-related DC powered MOVs was excellent.
i 4.2 NRC Inforrnation Notice 93-79 The core shroud is a stainless steel cylinder which directs the flow of water within the reactor vessel (RV), and is completely contained inside the RV. Previously, in October 1990 General Electric Company (GE) issued Rapid Information Communication Services Information Letter (RICSIL) 54 following the discovery of core shroud cracking at an overseas BWR. This RICSIL i
recom:nended that visual core shroud inspections be performed during the next lefuehng outage j
at al! BWR facilities which had high carbon type 3M stainless steel shrouds.
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Recently, NRC Information Notice NRC IN 93-79, " Core Shroud Cracking at Beltline Region Welds in Boiling Water Reactors (BWRs)" dated September 30,1993, was issued to inform all BWR licensees that core shroud cracking was recently identified within two reactor vessels at a BWR facility located within the United States. The affected licensee performed a safety evaluation which determined that one of the reactors could safely continue operating for the duration of the current operating cycle. Core shroud repairs were initiated at the second reactor which was already shutdown. Subsequently, GE issued RICSIL 54 (revision 1), SIL 572, and SIL 572 (revision 1) to inform BWR license holders of the latest inspection results, enhanced l
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internal vessel visual inspection I) techniques, and recommended that the core shroud inspection be performed at all BWm during the next refueling outage. The NRC is currently reviewing the potential generic implications of shroud cracking for reactor core configuration and emergency core cooling system performance under accident conditions.
The licensee has not yet performed the core shroud IVVI. The recent domestic BWR experience became known only after RF 09 at Pilgrim in Spring 1993. This resulted in postponement of the IVVI until RFO 10 because of scheduling coordination problems. Pilgrim station has maintained close communications with GE and several BWR facilities (including the facility who identified the core shroud cracks discussed in NRC IN 93-79) who have performed the core shroud IVVI. The primary shroud cracking mechanism is believed to be intergranular stress corrosion cracking (IGSCC) with irradiation assisted stress corrosion cracking (IASCC)
identified as a secondary contributor. Pilgrim has identihed shroud material composition (carbon content), fabrication vendor and techniques, material sensitization, plant water chemistry (conductivity) history, reactor power history, and reactor vessel internal configuration as variables pertinent to shroud cracking.
Engineering and construction personnel conducted a detailed comparison of relevant plant specific variables between Pilgrim and two BWR facilities which recently identified core shroud cracking. Quality Assurance representatives closely monitored all phases of this plant specific comparison. The Pilgrim shroud is made of high carbon ASTM-240 Type 304 SS (carbon content <.08%) and was manufactured at the same facility as the shrouds discussed in NRC IN 93-79. The shroud sections were shop welded with only the final shroud to reactor vessel weld performed in the field. The licensee reviewed fabrication documentation and determined that the total heat input was controlled adequately such that the base metal of the shroud was not sensitized during fabrication. Heat affected zenes adjacent to shroud beltline welds were subjected to some degree of sensitization. The Pilgrim lifetime water chemistry history (approximately 0.39 1/cm) was relatively poor due to resin intrusion. Hydrogen water chemistry was estathshed ~1 a continuous basis in the Spring of 1991 which notably reduced conductivity (0.09 uS/cm for 1992). The other BWR facility which has detected core shroud cracking had a more severe history (approximately 0.48 uS/cm) due in part to chloride intrusion, and has commenced hydrogen water chemistry on an intermittent basis only. Pilgrim also has a lower power output (potential for lower irradiation of the core shroud) and thicker core shroud than the facility discussed in NRC IN 93-79.
The licensee reviewed previous Pilgrim reactor vessel internal inspection documents and ascertained that no cracking in the area of the core shroud had been evident. Core Spray sparger visual inspections (made of the same material type as the core shroud) performed each RFO have showed no cracking. Both of the BWR facilities which recently identified core shroud cracking also observed cracking of their core spray spargers. Video of portions of Pilgrim's core shroud taken during ajet pump inspection was enhanced and no shroud cracks were observed. Pilgrim representatives contacted the GE Level 3 inspector who performed an in-core instrumentation inspection during RFO No. 8. He confirmed that his inspection included some internal portions
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of the core shroud and that he did not observe any cracks. The vendor noted that previous inspection techniques may not readily detect some core shroud cracking. Service Information Letter 572 (revisim 1) recommends that licensees use an enhanced video inspection technique or ultrasonic testing that can resolve a one mil wire on the inspection surface during future core shroud inspections. Its recognized that the past visual examinations of sparger piping, portions of the shroud and jet pump locations were not performed to the more recent criteria in SIL 572.
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l The licensee has performed a review of the safety consequences of core shroud cracking ana
currently available industry information. The inspector observed associated training of control room operators. Related safety consequences were discussed in detail. The shroud IVVI is
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scheduled to be performed during the next RFO (April 1995). Previou; schedule coordination difficulties resulted in postponement of this inspection from RFO 9. but BECo management has placed emphasis on integrated coordination of the shroud IVVI for RFO 10. The licensee considers this a developing issue which will be reassessed as new information becomes available.
4.3 (Closed) UNR 92-04-02 Evaluation of Reactm Vessel Water Level Instrumentation
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Spiking l
Since March 1990, the licensee experienced reactor vessel (RV) water level instrumentation
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spiking during reactor depressurization following plant shutdown. On several instances the
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l magnitude of the indicated level spikes was sufficient to cause automatic actuation of the Group I primary containment isolation system. This unresolved item was established regarding RV
level instrumentation performance with respect to potential noncondensible gas buildup. NRC Inspection Report 50-293/93-14 documented successful licensee implementation of actions
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requested in NRC Bulletin 93-03, " Resolution of Issues Related to Reactor Vessel Water Level
instrumentation in BWRs" for the modified level systems. Actions included operator training,
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l procedure revisions, engineering design and installation of a RV level reference leg back-fill system for the safety related instrument channels. Reactor vessel water level instrumentation
has responded as designed during subsequent reactor depressurizations. This item is closed.
5.0 PLANT SUPPORT (71707)
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5.1 Safeguards Event Notification
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On October 27,1993 a heensee secunty officer discovered a hand gun during the routine X-ray
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check of packages being carried by personnel before entry into the protected area. The weapon was unloaded but ammunition was found in the canvas carrying bag, along with various other personal and work items. The individual, who owned the weapon had a valid license to carry the firearm, was denied unescorted access to the protected area. No other contraband material was found during a hand search.
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NRC discussion witn licensee security personnel revealed that they had questioned the individual
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and further investigated whether there existed a history of any job related problems; none were
identified. The subject BECo employee apparently forgot that the hand gun was in the canvas l
bag, and, in his interview wi:h BECo security, related that he was called into work on an earlier
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l shift than originally scheduled and neglected to check the bag in the rush to get to work. BECo l
has taken disciplinary action in the form of a work suspension.
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The inspector confirmed licensee notification to the NRC Operations Center of this reportable l
safeguards report within one hour of discovery, in accordance with 10 CFR 73.71 and Appendix
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G to Part 73. The inspector also reviewed a draft version of the written licensee report t
documenting this event and verified licensee awareness of the requirement to submit this report to the NRC within 30 days of the inidal discovery. The inspector has no further questions on this event or licensee actions relative thereto.
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6.0 NRC MANAGEMENT MEETINGS AND OTHER ACTIVITIES (30702)
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6.1 Routine Meetings
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At periodic intervals during this inspection, meetings were held with senior BECo plant management to discuss licensee activities and areas of concern to the inspectors. At the
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conclusion of the reporting period, the resident inspector staff conducted an exit meeting on November 15, summarizing the preliminary findings of this inspection.
No proprietary information was identified as being included in the report.
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