ML20044G279
| ML20044G279 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 05/21/1993 |
| From: | Eugene Kelly NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20044G274 | List: |
| References | |
| 50-293-93-06, 50-293-93-6, NUDOCS 9306020264 | |
| Download: ML20044G279 (14) | |
See also: IR 05000293/1993006
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket No.:
50-293
Report No.:
93-06
Licensee:
Boston Edison Company
800 Boylston Street
Boston, Massachusetts 02199
Facility:
Pilgrim Nuclear Power Station
Location:
Plymouth, Massachusetts
Dates:
March 14 - April 26,1993
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inspectors:
J. Macdonald, Senior Resident Inspector
A. Cerne, Resident Inspector
D.Ke
_ Resident Inspector
Approved by:
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E.Mells Cwief
bate'
Reactor Projects Section 3A
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Scope: Resident safety inspections in the areas of plant operations, radiological controls,
maintenance and surveillance, security, safety assessment and quality verification, and
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engineering and technical support. Initiatives included extended observation of refuel floor
activities, including selected portions of reactor vessel disassembly and the initial phase of core
manipulations. Additionally, a review of fire watch processes was conducted. Reactive
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inspection of undervessel work activities was performed.
Inspections were performed on backshifts during March 15-19, 23, 24, 26, 30 and April 1, 2,
5, 7, 8, 12, 13, 15, 20-24, 1993. Deep backshift inspections were performed on March 14,
1993 from 12:00 am - 12:15 pm, April 18,1993 from 11:30 am - 4:40 pm and April 19, 1993
from 7:30 am - 4:15 pm.
Findines: Performance during this inspection period is summarized in the Executive Summary.
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The pressure-temperature limits for the reactor vessel bottom head were exceeded during the
March 13,1993 event. Failure of the licensee to identify and analyze this condition in a timely
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manner is a violation (VIO 50-293/93-06-01). The failure of tha. licensee to establish adequate
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design controls during the 1992 installation of voltage regulating ransformers that subsequently
caused the unanticipated deenergization of the Y3 and Y4120 volt busses during the March 13,
1993 event is a violation (50-293/93-06-02). A previous unresolved item regarding the adequacy
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of area cooling to the high pressure coolant injection and reactor core isolation cooling systems
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was closed (UNR 50-293/91-04-01).
Two previous violations regarding inservice test
instrumentation (50-293/91-22-01) and post maintenance testing (50-293/91-22-02) were also
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closed.
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9306020264 930521
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EXECUTIVE SUMMARY
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Pilgrim Inspection Report 93-06
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Plant Operations: As was noted in NRC Inspection Report 50-293/93-05, immediate operator
actions in response to the March 13, 1993, turbine generator load reject and partial loss of
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offsite power event were excellut. However, subsequent to an NRC initiated review, it was
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determined that the Technical Specification (TS) pressure-temperature limits for the reactor
vessel bottom head had been exceeded during the reactor depressurization and cooldown.
Additionally, because this condition had not been recognized prior to plant startup a TS required
engineering evaluation was not performed in a timely manner. Ultimately, engineering analysis
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indicated substantial safety margins existed.
Operations has maintained excellent oversight of outage activities. Upgrades to the refueling
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bridge hardware and software systems as well as establishment of dedicated fuel handling crews
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resulted in improved refuel floor performance.
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Radiological Controis: Radiological controls established to support outage activities were
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appropriate. Radiation work permits and surveys were accurate and current. Control points
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were properly staffed, techricians were alen and knowledgeable of assigned responsibilities, and
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preentry briefings were thorough.
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Maintenance and Surveillance: Incorrect technician action while performing local power range
monitor replacement activities resulted in temporary entry into a TS limiting condition for
operation. Immediate supervisor, project manager, and nuclear watch engineer responses were
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appropriate. The event critique addressed all potential relevant contributing factors.
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Security: Security watchmen temporarily employed for outage support were observed to be
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attentive and knowledgeable of designated duties. Outage-related compensatory measures were
properly implemented.
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Engineering and Technical Support: The Y3 and Y4120 volt busses deenergized during the
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March 13,1993 event because the input breaker trip setpoints to the associated voltage
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regulating transformers were improperly set below the vendor established setpoints. The
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transformers had been installed during the 1992 midcycle outage. Adequate design controls
associated with the installation of the transformers were not developed to ensure the breaker trip
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setpoints established at the manufacturer facility were maintained. Engineering evaluation of the
performance of a high pressure coolant injection system steam supply valve addressed
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appropriate NRC Generic Ixtter 89-10 assumptions.
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Safety Assessment and Quality Verification: Actions to address outstanding NRC issues
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indicated continued attention to issue resolution. An engineering evaluation of the emergency
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area cooling system safety bases'was well supponed by station design documentation.
Corrective actions to previous inservice test program weaknesses were appropriate.
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TABLE OF CONTENTS
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EXECUTIVE SUMMARY ......................................ii
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TABLE OF CONTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iii
1.0
SUMMARY OF FACILITY ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . 1
2.0
PLANT OPERATIONS G1707,40500,90712)
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2.1
Plant Operations Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
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2.2
Turbine Generator Imad Reject Followup . . . . . . . . . . . . . . . . . . . . . 2
2.3
Operational Oversight of Outage Activities . . . . . . . . . . . . . . . . . . . . 4
3.0
RADIOLOGICAL CONTROLS G1707) . . . . . . . . . . . . . . . . . . . . . . . . . . 5
3.1
Outage Contmls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
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4.0
MAINTENANCE AND SURVEILLANCE (37828,61726,62703,93702)
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4.1
Local Power Range Monitor Replacement Activities . . . . . . . . . . . . . . 5
5.0
S ECURITY G 1707) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
5.1
Land Vehicle Threat Readiness . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
5.2
Security Outage Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
5.3
Periodic Review of Firewatch Activities
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6.0
SAFETY ASSESSMENT AND QUALITY VERIFICATION (92701) . . . . . . . .
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6.1
Followup of Previously Identified Items . . . . . . . . . . . . . . . . . . . . . . 8
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6.1.1 (Closed) Unresolved Item 50-293/91-04-01.1, HPCI and RCIC
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Area Coolers
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6.1.2 (Closed) Violation 50-293/91-22-01, Failure to Use Properly
Ranged Pressure Gauge During Inservice Testing . . . . . . . . . . . 8
6.1.3 (Closed) Violation 50-293/91-22-02, Failure to Perform Valve
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Stroke Time Testing Following Packing Adjustment . . . . . . . . . . 9
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7.0
ENGINEERING AND TECHNICAL SUPPORT G1707) . . . . . . . . . . . . . . . 9
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7.1
Inadequate Design Change Contiol . . . . . . . . . . . . . . . . . . . . . . . . . 9
7.2
Engineering Evaluation, HPCI Containment Isolation Valve
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8.0
NRC MANAGEMENT MEETINGS AND OTHER ACTIVITIES (30702) . . . .
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8.1
Routine Meetings
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8.2
Other NRC Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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DETAILS
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1.0
SUMMARY OF FACILITY ACTIVITIES
At the beginning of the report period, the reactor was suberitical, in the process of being
maneuvered to cold shutdown following the March 13,1993 automatic reactor trip. The trip
resulted from a weather-related turbine generator load reject. Shortly after the reactor trip, the
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station experienced a partial loss of offsite power that included the unavailability of both 345
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kilovolt offsite transmission lines. All safety-related systems responded to this event as designed
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with the exception of the unanticipated deenergization of the Y3 and Y4120 volt electrical
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busses. Additionally, subsequent to plant restart, it was determined that the pressure-temperature
limits for the reactor vessel bottom head as defined by Technical Specifications had been
exceeded during the reactor depressurization and cooldown.
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Reactor restart was initiated on March 16,1993 and the turbine generator was synchronized 'o
the offsite distribution system on March 17,1993 and 100% of rated power was achieved. On
March 20,1993, end of operating cycle reactor coastdown began.
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On April 3,1993, the ninth refueling outage started. Reactor vessel disassembly and refueling
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cavity floodup were completed on April 12,1993. Phase 1 of core shuffle was conducted April
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13-16, 1993. In vessel and undervessel activities were started on April 16, 1993 and were
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continuing at the end of the report period. On April 22,1993, during local power range inonitor
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(LPRM) string replacements undervessel, technicians improperly determinated two LPRM strings
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that were not part of the work scope. Loss of these two LPRM strings caused the minimum
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Technical Specification requirements for average power range monitor channel availability to be
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exceeded.
Electrical and mechanical maintenance and modification of B loop systems were conducted April
11-19, 1993. The B loop was restored and returned to service on April 19,1993 at which time
the A loop was removed from service. At the conclusion of the inspection report period, the
station remained in an outage status, with the reactor mode select switch in the refuel position
and shutdown cooling on the B loop of the residual heat removal system.
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2.0
PLANT OPERATIONS (71707,40500,90712)
2.1
Plant Operations Review
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The inspector observed the safe conduct of plant operations (during regular and backshift hours)
in the following areas:
Control Room
Fence Line
Reactor Building
(Protected Area)
Diesel Generator Building
Turbine Building
Switchgear Rooms
Screen House
Security Facilities
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Control room instruments were independently observed by NRC inspectors and found to be in
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correlation amongst channels, properly fanctioning and in conformance with Technical
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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. Posting and
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control of radiation, contamination, and high radiation areas were appropriate. Workers
complied with radiation wrak permits and appropriately used required personnel monitoring
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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
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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
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lifted lead and jumper logs.
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2.2
Turbine Generator Load Reject Followup
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At the conclusion of the previous inspection report period (IR NRC 50-293/93-05), the licensee
was in the process of depressurizing and cooling down the reactor while concurrently recovering
offsite power capabilities following the March 13,1993, weather-related turbine generator load
reject, automatic reactor trip, and partial loss of offsite power.
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The partial loss of offsite power caused the A.C. powered active components of the condensate
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and feedwater system, sea water circulating system, radwaste system, reactor protection system,
and the reactor recirculation pumps to be deenergized and unavailable. Additionally, the main
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steam isolation valves (MSIVs) were closed as required by procedure when no condensate pumps
were available, therefore the main condenser was also unavailable. The reactor depressurization
was controlled by operation of the high pressure coolant injection (HPCI) system in the full flow
test mode and reactor vessel level control was maintained by the operation of reactor core
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isolation cooling (RCIC) system in the injection mode.
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Following the automatic reactor trip which occurred at 4:28 p.m., depressurization progressed
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at a normal cooldown rate of approximately 50-60 degrees F/hr. By 8:44 p.m., the startup
transformer had been reenergized and was supplying power to the A-3 and A-4 4160V nonsafety
busses and the reactor protection system trip was reset. Torus water temperature and level
increased during the shutdown due to the addition of HPCI and RCIC turbine steam exhaust and
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the limited power availability to support letdown to the radwaste systems. At approximately
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10:30 p.m., RCIC was secured. At 11:00 p.m. HPCI was secured because the torus water level
had increased to +3.5 inches and the HPCI pump suction path automatically transferred from
the condensate storage tank to the torus and the full flow test values automatically isolated.
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With the reactor essentially isolated, reactor pressure began to increase at a rate of
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approximately 10 psi per minute. At 11:36 p.m., reactor pressure increased to approximately
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600 psig. This reactor pressure, in conjunction with the MSIV being closed, resulted in an
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automatic reactor trip signal being generated. On March 14,1993 at 12:50 a.m., reactor
pressure increased to 820 psig. By this time, additional offsite power cap 6ilities had been
restored, the torus water level had been returned to normal levels, and the condensate and
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feedwater system was being prepared to return for service.
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At 1:00 a.m., control room operators sequentially cycled the four main steam safety relief valves
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in accordance with emergency operating procedures to reduce reactor vessel pressure and level.
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At 1:21 a.m., HPCI was r; turned to service for reactor vessel pressure control and RCIC was
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retumed to service for reactor vessel water level control. By 2:45 a.m., reactor vessel pressure
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had decreased to 320 psig. At 4:04 a.m., the reactor protection system trip was reset. The
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depressurization and cooldown continued routinely and at 8:22 p.m., the reactor entered cold
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shutdown with the reactor coolant system temperature less than 212 degrees F.
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Recently, several boiling water reactors have exceeded the pressure and temperature limits for
the reactor vessel bottom head during reactor shutdowns. These shutdowns typically involved
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loss of forced recirculation pump flow through the reactor, reactor coolant temperature
stratification, unavailability of the main condenser, MSIV closure, and an operational occurrence
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that caused a temporary increase in reactor pressure. Because of these similarities with the
Pilgrim shutdown of March 13-14,1993, the NRC questioned whether the Pilgrim reactor vessel
bottom head pressure-temperature limits for subcritical cooldown as defined by Technical Specification 3.6.A.2 and Figure 3.6.2 had been similarly exceeded. The post trip report had
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not addressed this concern.
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Subsequently, on March 19,1993, after reactor restart, licensee review of operational data from
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the shutdown identified that the bottom head pressure-temperature limits had been exceeded for
approximately three hours and twenty minutes beginning at 11:20 p.m. on March 13, 1993.
Additionally, because the licensee did not recognize that the pressure-temperature limits had been
exceeded an engineering evaluation to determine the appropriate course of action was not
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performed in a timely manner. Failure of the control room operators and post trip review
processes to identify that the reactor vessel bottom head pressure-temperature limits for
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suberitical cooldown as defined by TS Figure 3.6.2 had been exceeded during the March 13-14,
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1993 reactor shutdown which therefore precluded the timely performance of an engineering
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evaluation of this condition as required by TS 3.6.A.2 is identified as a violation (VIO 50-
293/93-06-01). Subsequent engineering evaluation performed by an approved licensee vendor
determined that ASME Section XI brittle fracture and crack extension factors of safety were
maintained throughout the pressure-temperature conditions experienced during the March 13-14,
1993 reactor shutdown. Additionally, the evaluation concluded stresses resultant from this event
were well within ASME Section III for fatigue usage. The evaluation used actual plant data that
indicated the pressure-temperature limits were exceeded at 112 degrees F and 520 psig, peaked
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at a pressure of 810 psig and 105 degrees F, and returned to within specified limits at 400 psig
and 94 degrees F.
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Continued independent NRC review of this event identified several weaknesses that were
contributing factors. Although shift supervision and operations section management present ia
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the control room during the event promptly identified that reactor coolant temperature
stratification was occurring and actions were taken to minimize its extent by reducing control
rod drive pump flow of cool water into the bottom of the vessel, the awareness was focused
toward recirculation pump restart rather than bottom head limitations. Additionally, procedure
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2.1.7, Attachment 1-OPER 7, Reactor Pressure Vessel Temperature and Pressure Checklist, that
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directed control room operators to monitor and record relevant reactor vessel temperature and
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pressures during startups and shutdowns was weak. The procedure requires all the appropriate
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data to be recorded at appropiiate intervals, however the procedure did not provide direct
correlation or trending of this data with TS figures. Also, after discussions with several
operatnrs and licensed operator training personnel, the inspector concluded current training did
not e. sure consistent knowledge of the TS requirements defined by the pressure-temperature
figures. Further, the post trip report processes did not address the TS pressure-temperature
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limits. Finally, the inspector noted that while all relevant reacto: vessel temperature points and
reactor pressure are available on the emergency plant information computer, the system is not
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used to aid the operator by graphically trending pressure-temperature progression during
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shutdowns. These issues were discussed v.ith the licensee. Initial improvements to the OPER
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7 checklist, and post trip report procedure have been proposed. These actions as well as longer
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term corrective actions will be reviewed following the licensee response to the Notice of
Violation.
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2.3
Operational Oversight of Outage Activities
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On April 2,1993 at 8:00 p.m., control room operators initiated a reactor shutdown to begin the
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ninth Pilgrim refueling outage.
The shutdown was well controlled, with no anomalous
conditions encountered.
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The operations section assumed active roles throughout the outage organization. Improvements
since the last refueling outage were most notable on the refuel floor. The refuel manager was
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a currently licensed senior reactor operator (SRO). A dedicated fuel handling crew of four
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SROs and eight operators performed all core alterations. The refuel bridge was modified to
eliminate interferences at the core periphery. The bridge position indexer was upgraded to
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reduce slippage and provide more precise position coordinates.
Manipulations of components within the core were controlled by two basic procedures. Fuel
bundle manipulations were governed by procedure number 4.3, " Fuel Handling." Refuel bridge
auxiliary equipment usage for non fuel bundle manipulations were governed by procedure
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number 2.2.75, " Fuel Handling and Service Equipment." Both procedures were very detailed,
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clearly written, and referenced industry experience involving refueling events. An upgraded fuel
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handling computer software program was also imp 3emented that minimized total incore
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manipulations and also directed proper grapple orientation before engaging fuel bundle bail
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The inspector observed significant portions of the reactor vessel disassembly and was present
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on the refuel bridge for much of the first phase of core manipulations. Excellent supervision
and conduct of all incore operations were noted. Communications on the bridge and with the
control room were formal with repeat back verifications.
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Approximately three weeks before the start of the outage, the normal six shift operational
schedule was reduced to a four shift rotation. Operators from the offshifts were interspersed
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throughout the outage organization. One Nuclear Watch Engineer (NWE) was assigned as the
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balance of plant work coordinator and a second NWE was assigned as the electrical work
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coordinator. Additionally, SROs were assigned as tagging coordinators in the work tagging
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control center established in the control room annex.
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Inspector review of portions of these work activities found excellent controls, with proper
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tagging boundaries established, and an absence of schedule or activity conflicts. The system and
license knowledge provided by direct SRO involvement in the outage process was a positive
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factor.
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3.0
RADIOLOGICAL CONTROLS (71707)
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The inspector reviewed radiological controls in place as well as the radiological conditions of
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selected areas of the plant. Management tours of the radiological controlled area continued to
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be thorough and directed towards minimizing total personnel radiation exposure. Survey
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postings, radiological conditions and controls were appropriate with no discrepancies noted.
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3.1
Outage Controls
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The inspector toured selected radiological protection outage control points. The drywell and
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refuel floor control points were properly established. Surveys and radiation work permits were
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current and easily readable. Technician entry briefings were detailed, hot spots and high dose
rate areas were identified and low dose rate resting areas were emphasized. Good technician
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presence was routinely noted within work areas and technicians were observed to be very
responsive to personnel monitoring alarms.
4.0
MAINTENANCE AND SURVEILLANCE (37828,61726,62703,93702)
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4.1
Local Power Range Monitor Replacement Activities
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On April 22,1993, undervessel technicians were conducting initial local power range monitor
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(LPRM) string replacement activities.
Seven LPRM strings had been identified for
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determination and removal. The specific strings were selected to ensure minimum average
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power range monitor (APRM) Technical Specification requirements for channel operability were
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maintained. Specifically, TS 3.1.1 requires that an APRM channel have at least two LPRM
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inputs per level and at least 50% of the normal LPRM inputs to the APRM to maintain
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operability.
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The seven LPRM strings to be replaced were tagged and independently verified to be correct.
An eighth LPRM string intended to be replaced after installation of the other seven LPRM
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strings was discretely tagged also. The undervessel technicians were then briefed on the LPRM
determination or cutting evolutions.
Each of the seven LPRM strings intended to be
determinated were properly cut. The next procedural step involved bagging and installing a
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drying desiccant to the cut coaxial connectors. At approximately 2:00 p.m., the technician
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assigned this responsibility completed the task but then without authorization or direction cut two
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additional LPRM strings (12-37 and 12-45) under the mistaken belief that these strings had been
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overlooked during the initial determination pass. The technician notified supervision of the
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action taken.
The supervisor, with knowledge that the technician action was incorrect
immediately notified the project manager who in turn notified the nuclear watch engineer
(NWE).
Additionally, problem report 93.9181 was generated to document and initiate
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evaluation of the event.
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The NWE reviewed the remaining LPRM availability and determined that cutting of the two
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additional LPRM strings caused less than eleven (or 50%) totu LPRM inputs and less than two
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LPRM inputs per level for APRM Channels B, D, and F. Additionally, APRM Channel E was
left with less than eleven (or 50%) total LPRM inputs. Therefore, APRM Channels B, D, E,
and F did not meet minimum TS requirements, and were declared inoperable. He A and C
APRM Channels remained operable. The NWE entered an active limiting condition of operation
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(A93-98) in accordance with TS 3.1.1 and placed the B reactor protection system in trip and
inserted a control rod block. Actions by the NWE were appropriate and promptly implemented.
Cutting of the two additional LPRM strings was of minimal operational or reactor safety
significance because no core allevations were in progress and source range monitors were
available; however, the action caused the station to enter a TS limiting condition for operation.
The operations section manager directed all undervessel work to be stopped until the causes of
this event were understood. A formal event critique was convened at approximately 3:30 p.m.
on April 22,1993. The critique was chaired by outage management, and information relevant
to the event was developed. The preliminary critique conclusion determined the event was
caused by discrete personnel error by the technician who cut the nonspecified LPRM strings.
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No contributing programmatic factors were identified.
The inspe; tor independently toured the undervessel area and concluded the LPRM tagging
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adequately identified the strings to be cut. The inspector also attended the event critique that
was reconvened an April 23,1993, at 7:00 p.m.
The critique focused on basic technician
qualification standards, technician-supervisor interaction, pre-brief evolutions, and work package
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content. These topics were thoroughly discussed and evaluated without any concerns being
identified. Subsequent to completion of the critique, undervessel LPRM replacement activities
were authorized to restart.
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Notwithstanding, the personnel error relative to this event, the licensee staff exhibited excellent
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response. The NWE properly evaluated the loss of the additional APRM Channels and
implemented appropriate required responses. The event critiques were comprehensive and well
run. Finally, the LPRM strings were expeditiously replaced and the LCO was promptly exited.
5.0
SECURITY (71707)
5.1
Land Vehicle Threat Readiness
On March 30,1993, the licensee conducted a time sensitivity diill to validate procedures and
personnel response in the event of a land vehicle bomb threat condition. The inspector attended
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the drill critique and discussed implementation of the bomb threat procedure with Security
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management. Personnel from various BECo service centers responded to Pilgrim Station well
within the time period called for by the security plan.
Service center managers were
knowledgeable of their responsibilities. Inspector review of applicable procedures and NRC
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generic guidance determined the licensee effectively demonstrated the ability to respond to
potential threats posed by land vehicles.
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5.2
Security Outage Controls
The inspector reviewed supplemental security staffing and in plant compensatory postings related
to the current refueling outage. Temporary watchmen were noted to be alert and knowledgeable
in assigned responsibilities. Personnel accountability was properly established at the drywell.
Areas requiring compensatory measures were properly posted and outage related vehicles within
the protected area were observed to be properly controlled.
5.3
Periodic Review of Firewatch Activities
During the inspection period the inspector reviewed the effectiveness of the implementation of
compensatory hourly and continuously posted firewatches. The review included completed logs
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selected randomly back through December 1992. The logs were found to be properly completed
in accordance with established procedures. The inspector also randomly selected security
computer data to conduct a second verification that firewatch standers entered plant locations-
required to complete firewatch rounds. No discrepancies were identified. Finally, during plant
tours, the inspector questioned firewatch standers regarding the reason a compensatory watch
existed, requirements of the watch, and actions to take should an actual fire be encountered.
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The inspector concluded that the firewatch aspects of the fire protection program were being
effectively implemented and that the watch standers were knowledgeable in their designated
responsibilities.
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6.0
SAFETY ASSESSMENT AND QUALITY VERIFICATION (92701)
6.1
Followup of Previously Identified Items
6.1.1 (Closed) Unrsolved Item 50-293/91-04-01.1, HPCI and RCIC Area Coolens
As was identified initially in NRC Inspection Report 50-293/912-04, the March 25,1991 loss
of A-6 bus event caused power to both HPCI area coolers to be lost, therefore requiring HPCI
to be declared inoperable. The inspector questioned if the loss of both HPCI area coolers in
response to a single active failure of the A-6 bus was consistent with the emergency area cooling
system design bases as described in FSAR Section 10.18. The same scenario would be
applicable to the RCIC system in the event of a loss of power to the A-5 bus. The specific
inspector concern was that it appears that the operability of either the HPCI or RCIC systems
should be independent of a design bases single active AC power failure.
The status of this item was updated in NRC Inspection Report 50-293/93-03. On February 24,
1993, the onsite review committee approved the engineering evaluation that concluded the
current EACS design is appropriate, and conforms with the station operating license and FSAR
design bases. The evaluation is supported by reference documentation that preceded system
construction. The evaluation included assessment of basic design intent, NRC NUREG 0737
Action Plan Items, equipment qualification, and station blackout.
Initial inspector review of the evaluation determined licensee action in response to the unresolved
item to be complete and therefore the item is closed. Should additional NRC concerns be
identified following continuing staff review, they will be addressed separately as future
inspection reports as new inspection items. This item is closed.
6.1.2 (Closed) Violation 50-293/91-22-01, Failure to Use Properly Ranged Pressure Gauge
During Inservice Testing
Previously the inspector identified that on September 10,1991, a 0-30 psig gauge was used to
measure suction pressure, that had a reference value of 4.0 psig (pump not running), during
performance of a low pressure coolant injection pump quarterly inservice test (IST). The 0-30
psig test gauge exceeded the A'NE Section XI test instrument range criteria of three times the
reference value or less.
Licensee corrective actions to this violation, as documented in BECo Letter 91-140, dated
November 15,1991 included repeat of the surveillance with the properly ranged pressure gauge.
Additionally, measure and test equipment was inventoried to identify the appropriate instrument
for the specified IST surveillance. Shift performance was monitored with satisfactory results.
Finally, IST surveillance procedures are being revised to require double verification of M&TE
installation, and to ensure personnel review and understand procedural requirements. Inspector
review concluded the corrective actions were effectively implemented and had no further
questions. This item is closed.
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6.1.3 (Closed) Violation 50-293/91-22-02, Failure to Perform Valve Stroke 'Ilme Testing
Following Packing Adjustment
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Previously the inspector identified that on July 9,1991, licensee did not perform required valve
stroke time testing following adjustment to the packing of the LPCI shutdown cooling system
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suction isolation valve, MO-1001-50.
Licensee corrective actions, as documented in BECo Letter 91-140, dated November 15,1991,
included satisfactory stroke time testing of the effected valve. Additionally, maintenance
planners received training specifically directed toward IST procedure requirements. This
violation was also included in the work control program review for applicable consideration.
Inspector review of corrective actions including direct observation of several subsequent post
maintenance valve stroke time testing evolutions determined the violation was properly
addressed. This item is closed.
7.0
ENGINEERING AND TECHNICAL SUPPORT (71707)
7.1
Inadequate Design Change Control
As was documented in NRC Inspection Report 50-293/93-05, the Y3 and Y4120 VAC safety
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related busses unexpectedly deenergized following the March 13,1993 turbine generator load
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reject and automatic reactor trip. Deenergization of these busses disenabled the logic that would
automatically start additional salt service water system and reactor building closed cooling water
system pumps shouM low system pressures be encountered. The busses were recovered in
accordance with proce jures within approximately twenty minutes. Manual start capability was
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available for the effected system pumps. Unresolved Item 50-293/93-05-01 was issued to
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develop additional inspector information regarding this event.
The licensee initiated problem report (PR) 93.9084 to identify the event and to determine
reportability, root cause analysis, and corrective actions. The licensee utilized Kepner Tregoe
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analysis methodologies during its investigation. The cause of the deenergization of the busses
was determined to be the tripping of the input circuit breakers to the voltage regulating
transformers that supply the busses. The breakers tripped because the instantaneous trip
setpoints had been improperly set at a lesser value than required by station design.
During the October through November 1992 mid cycle outage the supply transformers to the Y3 -
and Y4 busses were changed from existing fixed tap transformers, that did not have local circuit
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breaker protection to voltage regulating transformers, that included local circuit protection. The
transformer replacement was implemented via plant design change PDC 91-59A.
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transformers were preset and performance tested by the manufacturer prior to shipment to
Pilgrim. Vendor documentation indicated that the input circuit breakers for each transformer
had been set at a value of 5 (which corresponds to 1200 Amperes) on an adjustable range of LO-
2-3-4-5-6-7-HI. However, subsequent investigation following the March 13,1993 event revealed
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that the Y3 bus X55 regulating transformer input breaker trip setpoint was set at 2 which
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corresponds to 900 Amperes and the Y4 bus X56 regulating transformer input breaker trip
setpoint was set at 3 which corresponds to 1000 Amperes.
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Independent NRC review determined adequate design controls were not established for PDC 91-
59A to ensure that the proper input breaker trip setpoints established at the manufacturer facility
were maintained after the licensee accepted receipt of the equipment. Specifically, the PDC did
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not identify the breaker setpoints as a critical receipt inspection criterion. Similarly, neither
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installation instructions nor post modification testing required the verification of the input
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breaker trip setpoints.
Failure of the licensee to ensure adequate design controls were
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established to maintain proper input breaker trip setpoints as required by 10 CFR 50 Appendix
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B, Criterion III, " Design Control" is identified as a violation (VIO 50-293/93-06-02).
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Immediate licensee corrective actions to this event have been appropriate. The input breakers
were reset via field revision to the design change to the HI setting which corresponds to 1500
Amperes. The event investigation was comprehensive and addressed all potential contributing
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factors. Ultimately, the licensee investigation concluded the most likely root cause of the
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improperly set input breaker trip setpoints was an unauthorized and undocumented change the
PDC installation. Due to the lack of design controls for the input breaker trip setpoint once the
transformers were in the licensee's possession, it was not possible to establish a definitive root
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cause. Unresolved item 50-293/93-05-01 is closed, and any further action relative to this issue
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will be tracked via the violation.
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7.2
Engineering Evaluation, HPCI Containment Isolation Valve
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On March 3,1993, the licensee issued problem report 93.9064 which identified that the inlet
port diameter of the HPCI steam supply containment isolation valve,2301-5, was 7.87 inches,
not 6.5 inches as was previously assumed when used in previous NRC Generic Letter 89-10
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motor operated valve capabilities calculations. Problem report 93.9064 was generated to initiate
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corrective actions. The valve has three basic functions 1.) to close if a HPCI steamline break
is sensed, 2.) To open, if closed for test purposes, upon receipt of a HPCI initiation signal, and
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3.) to close and isolate HPCI on low reactor steam supply pressure. The larger inlet port
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diameter would require the actuator to develop more thrust to cause the valve to stroke.
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The Engineering Department performed an evaluation of the effect of increased inlet port
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diameter on the operability on the valve. Calculations, which included GL 89-10 assumptions,
supported the evaluation. The calculations which assumed higher motor temperatures and lower
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available DC voltages, indicated that for a HPCI steam supply line double ended pipe break, the
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valve would stroke more slowly, requiring approximately 39 seconds to close rather than the 25
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seconds as described in the FSAR. The increased strol e time was reviewed against equipment
qualification in a harsh environment and it was determ'ned the increased closure time was
acceptable. FSAR bases time limits for valve ciesnrt on low reactor steam pressure or valve
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opening during HPCI initiation were not impacted. The calculation also indicated the actuator
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would develop adequate thrust to ensure the valve would close approximately 96-98 percent of
full closure while the closing limit switch bypasses the torque switch.
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The licensee's analysis assumed that the high thrust required to close the valve would have
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tripped the torque switch. Therefore, the valve may not fully seat and could possibly have some
through-valve leakage with the worst car assumptions for motor voltage, ambient temperature
and break. size. However, the licensee's analysis considered this acceptable because the energy
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releases would be within the assumptions for the environmental qualification evaluations. The
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radiological effects were bounded by the analysis of a steam line break outside of containment.
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Likewise, the licensees analysis of the effects of the slow closing time on the mass and energy
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released to the reactor building was acceptable for the environmental analysis of the direct
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current operated valve motor operator.
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8.0
NRC MANAGEMENT MEETINGS AND OTIIER ACTIVITIES (30702)
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8.1
Routine Meetings
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At periodic intervals during this inspection, meetings were held with senior plant management
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to discuss licensee activities and issues identifed by the inspectors. At the conclusion of the
reporting period, the resident inspector staff conducted an exit meeting on April 20,1993, with
licensee management summarizing the preliminary findings. No proprietary information was
identified as being included in the report.
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8.2
Other NRC Activities
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On April 20,1993, Mr. James T. Wiggins, Acting Director of the Division of Reactor Projects
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and Mr. Eugene M. Kelly, Chief, Reactor Projects Section 3A, visited Pilgrim. Messrs Wiggins
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and Kelly met with the Senior Resident inspector, attended the routine periodic exit meeting for
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this report, toured the station, and met with senior station management.
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