ML20044H293
| ML20044H293 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 05/24/1993 |
| From: | Lazarus W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20044H284 | List: |
| References | |
| 50-334-93-09, 50-334-93-9, 50-412-93-09, 50-412-93-9, NUDOCS 9306080149 | |
| Download: ML20044H293 (31) | |
See also: IR 05000334/1993009
Text
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos.
93-09
Docket Nos.
50-334
50-412
License Nos.
NPF-73
Licensee:
Duquesne Light Company
One Oxford Center
301 Grant Street
Pittsburgh, PA 15279
Facility:
Beaver Valley Power Station, Units 1 and 2
Location:
Shippingport, Pennsylvania
Inspection Period:
April 6 - May 10,1993
Inspectors:
Lawrence W. Rossbach, Senior Resident Inspector
Peter P. Sena, Resident Inspector
Scot A. Greenlee, Resident Inspector
Approved by:
he#
M
W. Ufazarus Milef, Reactor Projects Section 3B
Date
Inspection Summary
This inspection report do;uments the safety inspections conducted during day and backshift
hours of station activities in 'he areas of: plant operations; radiological controls; surveillance
and maintenance; emergency pwparedness; security; engineering and technical support; and
safety assessment / quality verification.
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9306080149 930525
gDR
ADOCK 05000334
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EXECUTIVE SUMMARY
Beaver Valley Power Station
Report Nos. 50-334/93-09 & 50-412/93-09
Plant Operations
A walkdown of the Unit I residual heat removal system found the system to be properly
aligned and performing its safety function. The Unit 2 high head safety injection (HHSI)
system was found to be properly aligned and fully operable following a detailed walkdown;
however, some missing supports were identified on two of the HHSI pump oil systems. This
is discussed further in Engineering and Technical Support. Good supervision of refueling
operations was evident as well as thorough implementation of lessons learned from industry
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experience on handling of the upper internals assembly.
Radiological Controls
improper implementation of health physics requirements by plant operators on two separate
occasions resulted in a violation of technical specifications (50-334/93-09-01). Although
these events were identined by the licensee, the inspectors noted that a previous similar
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violation of Technical Speci6 cation 6.12 occurred on June 13,1992 (LER 92-06). These
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events, therefore, were not considered to meet the criteria of 10 CFR 2, Appendix C for a
non-cited violation because they were r.u solated. These events and the broad scope of
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issues raised by operators during the subsequent brienngs indicate a greater need for operator
awareness of the requirements governing control of high radiation areas. A worker was
witnessed reaching into a posted high radiation area (HPA) without HRA controls. The
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posting was precautionary since the maximum actual radiation level in the area was only 8
mR/hr. The practice of placing extremities across an HRA boundary was not prohibited by
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station policy, but was considered a poor practice. Following discussions with the NRC,
Duquesne Light Cumpany changed their policy to prohibit any crossing of a HRA boundary
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without full HRA controls.
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Maintenance and Surveillance
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High quality maintenance, consistent with vendor recommendations, was evident on the
Unit I diesel generator . overhaul inspection. Troubleshooting to determine the cause of load
Ductuations on the No. 2-2 diesel generator was well controlled. The fluctuations (maximum
of 300 kW) were observed at approximately 1,000 kW while unloading the unit. The Unit I
safety injection accumulator discharge check valve full stroke testing was successful using
non-intrusive acoustic analysis. An alternate test method was performed in parallel with the
non-intrusive testing; however, this alternate method should be reviewed to ensure sufficient
accuracy prior to use as the sole method for meeting ASME Code requirements. The
licensee demonstrated the ability to ensure all core alteration prerequisites were satisfied and
that proper controls existed to maintain containment closure throughout. Steam generator
tube and plug examinations were comprehensive. A revised accident analysis and 50.59
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(EXECUTIVE SUMMARY CONTINUED)-
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evaluation for increased steam generator tube plugging will be completed prior to plant .
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restan. Steam generator tube repair technology development during this refueling outage-
was a noteworthy initiative.
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Engineering and Technical Sunoort
A higher than expected number of fuel failures were identified during ultrasonic
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examinations. Thirty-five failed rods were found on the twice burned Westinghouse.
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Vantage 5 Hybrid (V5H) fuel assemblies. The licensee's root-cause analysis remains under
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investigation. The licensee conservatively elected'not to reload the core with any of these -
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two cycle V5H assemblies, including those without indication of fuel failure.
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An AMSAC design change, which improves logic voltage levels, is a result of the licensee
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applying lessons learned from other nuclear facilities to Beaver Valley.
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A temporary spent fuel pool cooling system was designed to provide decay heat removal for -
the offloaded core while the component cooling water system was removed from service.
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Satisfactory capacity, redundancy, and backup systems were designed into the cooling .
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this temporary cooling system.
No significant problems were acted with a design change package for a station blackout
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electrical cross-tie between Unit 1 and Unit 2. The final functional test of the cmss-tie was
well controlled and thoroughly briefed. The overall adequacy of the tests performed is under
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review by NRC.
Six support brackets were found missing on the Unit 2 high head safety injection (HHSI)
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pump lube oil systems. A detailed engineering analysis showed that the missing brackets did
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not effect HHSI system operability. The reason for the missing brackets has yet to be_ .
determined and is considered an unresolved item (50-412/93-09-02). - One of the brackets:
had been identified as missing in October 1992, but no action 'was taken to analyze or correct
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the condition until the NRC identified a similar condition in April 1993. The failure by
Duquesne Light Company to take prompt corrective action for a condition adverse to quality
is a violation of 10 CFR 50, Appendix B, Criterion XVI (50-412/93-09-03).
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Documentation was not available to support the adequacy of post-m' dification piping' stresses
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in the Unit 2 HHSI pump lube oil systems. The modification was initiated to enhance -
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performance monitoring on the lube oil heat exchangers. Duquesne Light company was 1
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going to generate adequate documentation to support the current configuration of the HHSI
pump lube oil systems.
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(EXECUTIVE SUMMARY CONTINUED)
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Corrective actions for a previous violation involving the use of temporary containment
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penetration seals during refueling were very thorough.
Safety Assessment /Ouality Verification
During an information notice review, the licensee identified that the ability of the manual
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reactor trip switch to initiate a reactor trip via the shunt trip had not been adequately tested
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on Unit 2. Adequate justification for enforcement discretion was provided. Required testing
will be completed during the next refueling outage.
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TABLE OF CONTENTS
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EXECUTIVE SUMMARY
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TABLE OF CONTENTS
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1.0
MAJOR FACILITY ACTIVITIES
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2.0
PLANT OPERATIONS (71707, 71710, 93702) . . . . . . . . . . . . . . . . . . . . . 1
2.1
Operational Safety Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . I
2.2
Safety System Walkdowns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
2.3
Unit 1 Refueling Operations . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . 3
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RADIOLOGICAL CONTROLS (71707) . . . . . . . . . . . . . . . . . . . . . . . . . . 4
3.1
Improper Health Physics Practices . . . . . . . . . . . . . . . . . . . . . . . . . 5
3.2
Work Encroaching on Posted High Radiation Area . . . . . . . . . . . . . . . 7
4.0
MAINTENANCE AND SURVEILLANCE (62703,61726,71707) . . . . . . . . .
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4.1
Maintenance Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
4.2
Surveillance Observations
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4.3
Configuration Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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4.4
Unit 1 Steam Generator Tube Eddy Current Examinations
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5.0
S EC URITY (71707) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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6.0
ENGINEERING AND TECHNICAL SUPPORT (37700,37828, 71707) . . . . .
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6.1
Unit 1 Fuel Inspection
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6.2
Unit 1 AMSAC Design Change . . . . . . . . . . . . . . . . . . . . . . . . . .
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6.3
Unit 1 Temporary Spent Fuel Pool Cooling . . . . . . . . . . . . . . . . . .
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6.4
Modification for Station Blackout (SBO) Cross Tie Between Unit I and
U n it 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
6.5
Unit 2 HHSI Pump Lube Oil System Support Bracket Deficiencies . . . .
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6.6
Unit 2 Modifications for Heat Exchanger Performance Monitoring . . . .
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6.7
(Closed) Violation (412/92-07-02) Temporary Containment Penetration
Seals..........................................
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7.0
SAFETY ASSESSMENT AND QUALITY VERIFICATION (40500,71707,
90712, 91700) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
7.1
Unit 2 Reactor Trip System Surveillance Enforcement Discretion . . . . .
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8.0
ADMI NISTRATIVE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
8.1
Management Meeting and Media Briefing
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8.2
Preliminary Inspection Findings Exit
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8.3
Attendance at Exit Meetings Conducted by Region-Based Inspectors . . .
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8.4
NRC Staff Activities
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MAJOR FACILITY ACTIVITIES
Unit 1 remained in a refueling outage throughout this inspection period. There were no
significant operational events. Ultrasonic testing of fuel assemblies identified a higher than
expected number of leaking fuel pins. This is discussed in Section 6.1. Steam generator
eddy current testing and tube plugging were completed. The results of this testing are
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discussed in Section 4.4. Numerous other operation, maintenance, modification, and
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surveillance activities were completed during this portion of the refueling outage.- Those
inspected are described in Sections 2,4, and 6.
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Unit 2 operated at full power throughout this inspection period except for a power reduction
to 45 percent from April 8 to 12 to maintain the scheduled length of the fuel cycle and to
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perform maintenance. There were no significant operational events.
2.0
PLANT OPERATIONS (71707, 71710,93702)
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2.1
Operational Safety Verification
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Using applicable drawings and check-off lists, the inspectors independently. verified safety
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system operability by performing control panel and field walkdowns of the following
systems: low head safety injection, component cooling water, and temporary spent fuel pool
cooling. These systems were properly aligned. The inspectors observed plant operation and
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verified that the plant was operated safely and in accordance with licensee procedures' and
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regulatory requirements. Regular tours were conducted of the following plant areas.
Control Room
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Safeguard Areas
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Auxiliary Buildings
Service Buildings
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Switchgear Areas
Turbine Buildings
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Access Control Points
Intake Structu' e
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Protected Areas
Yard Areas
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Containment Penetration Areas
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Spent Fuel Buildings
Diesel Generator Buildings
Unit 1 Containment
During the course of the inspection, discussions were conducted with operators concerning
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knowledge of recent changes to procedures, facility configuration, and plant conditions. The
inspectors verified adherence to approved procedures for ongoing activities observed. Shift
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turnovers were witnessed and staffing requirements confirmed. The inspectors found that
control room access was properly' controlled and a professional atmosphere was maintained.
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- Inspectors' comments or questions resulting from these reviews were resolved by licensee-
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personnel.
Control room instruments and plant computer indications were observed for correlation
between channels and for conformance with technical specification (TS) requirements.
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Operability of engineered safety features, other safety related systems, and onsite and offsite
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power sources were verified. The inspectors observed various alarm conditions and
confirmed that operator response was in accordance with plant operating procedures.
Compliance with TS and implementation of appropriate action statements for equipment out
of service was inspected. Logs and records were reviewed to determine if entries were
accurate and identified equipment status or deficiencies. These records included operating
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logs, turnover sheets, system safety tags, and the jumper and lifted lead book. The
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inspectors also examined the condition of various fire protection, meteorological, and seismic
monitoring systems.
Plant housekeeping controls were monitored, including control and storage of flammable
material and other potential safety hazards. The inspectors conducted detailed walkdowns of
accessible areas of both Unit 1 and Unit 2. Housekeeping at both units was acceptable.
2.2
Safety System Walkdowns
The operability of the Unit I residual heat removal (RHR) system and the Unit 2 high head
safety injection (HHSI) system was verified by performing detailed walkdowns of the
accessible portions of the systems. The inspectors confirmed that system components were
in the required alignment, instrumentation was valved in with appropriate calibration dates,
as built prints reflected the as-installed system, essential support systems were operational,
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and the overall material condition was satisfactory. Specific observations are discussed
below.
Unit 1 RHR System
The inspectors performed a walkdown of the RHR. system while it was providing
decay heat removal and after the completion of all maintenance activities prior to core
reload. The RHR system was inspected due to its normal inaccessibility at power and
the shutdown risk associated with decay heat removal. The system was found to be
properly aligned and performing its safety function.
Heavy boric acid buildup was evident due to system leaks. RHR pump 1B was
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heavily encrusted with boric acid due to a seal leak. Following the motor
replacement, this area was satisfactorily decontaminated with the exception of the pipe
cage beneath the pump. The Unit I radiological operations director informed the
inspectors that this area would also be decontaminated. Numerous valves, also
identified by the licensee, exhibited packing leaks and boric acid buildup. These
valves were subsequently cleaned of boric acid residue, valve packing was adjusted,
and carbon steel was inspected for degradation. RHR pump 1B discharge isolation
valve, RH-6, continued to exhibit a wet packing leak. A packing adjustment was
subsequently completed.
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Permanent lighting on the RHR platform was initially poor as a majority of the
overhead lights were burned out. The lighting condition was improved prior to the
start of maintenance.
The radiological survey map of the RHR platform could have been updated with more
up-to-date dose rate information. The posted survey map was 2 weeks old and did
not take into account that the incore flux detectors were withdrawn from the core.
These detectors, have in the past, resulted in significantly increased dose rates at the
keyway entrance on the RHR platform. Health physics technicians surveyed this area
after the detectors were withdrawn and updated their turnover log book with the new
information. Although dose rates increased less than expected (from 20 mR/hr to
40mR/hr), the posted survey map was not updated. The inspectors discussed this
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with the Unit I radiological operations director who agreed that posted survey maps
should be updated following a significant change in plant configuration which could
affect dose rates. The RHR platform survey map was subsequently updated.
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The Unit 2 HHSI system was found to be properly aligned and capable of performing its
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intended safety function. The material condition of the system was generally good; however,
the inspectors found one pipe support bracket for the 21C HHSI pump lube oil system
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missing, and another bracket was found loose and missing a fastener. Duquesne Light
Company was informed of these deficiencies. They subsequently performed a detailed
walkdown of all lube oil piping for the HHSI pumps, and found a total of four missing
supports for the 21C HHSI pump oil system and two missing supports for the 21B HHSI
pump oil system. One of the missing supports for the 21B HHSI pump oil system had been
previously identified by Duquesne Light Company. The HHSI system was determined to be
operable even with the six missing brackets. This deficiency is discussed in more detail in
Section 6.5 of this report. No other significant deficiencies were observed during the
walkdown.
2.3
Unit 1 Refueling Operations
The inspectors observed refueling operations involving the reactor head removal, upper
internals assembly removal, and core reload. The licensee had recently developed site
specific refueling procedures in order to provide a greater sense of ownership vice relying on
generic vendor supplied procedures. Master Lee refueling services provided assistance to the
licensee's refueling organization.
Prior to lifting the reactor head, the licensee established containment closure (see
Section 4.3). A tool control area was established around the refueling cavity for foreign
material exclusion. Personnel safety precautions were properly adhered to by refueling
personnel via the use of safety harnesses. While placing the polar crane cable under strain
during the initial attempt to lift the head, the load cell readings were noted to be erratic. The
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licensee's refueling supervisor appropriately stopped this initial attempt and reduced the
strain on the crane cable. The load cell had been properly calibrated, but the load cell cable
was faulty and had to be replaced. During the head lift, radiation levels were continuously
monitored and all elevations outside the crane wall adjacent to the travel path of the head
were appropriately roped off. However, subsequent monitoring of personnel exiting
containment identified 13 individuals with slight facial contamination, including positive nasal
smears. The circumstances of this airborne event were inspected and documented in NRC
inspection report 50-334/93-10.
During the upper internals assembly removal, the inspectors noted that lessons learned from
past industry events were implemented by the licensee. Specifically, suggestions contained in
NRC Information Notice 90-77, " Inadvertent Removal of Fuel Assemblies from the Reactor
Core," were incorporated into refueling procedure IRP-9R-3.15. The licensee did not limit
its overall supervisory control of the upper internals removal even though the contractor has
extensive experience with refueling at similar plants. The command and control of the
internals lift evolution was clearly dictated by the licensee's refueling supervisor, not the
contractor. Also, adequate underwater lighting and good water clarity allowed a thorough
inspection of the upper internals with an underwater camera. The upper internals storage
area was also inspected to ensure that no visible debris or foreign objects were present which
could damage the fuel assembly guide pins. Finally, elevation readings of the upper internals
assembly were obtained by the licensee's refueling supervisor with a level and transit rod.
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This ensured that adequate clearance existed between the upper internals and the storage
stand to prevent damage to the upper internals fuel assembly guide pins. The inspectors
reviewed engineering memorandum 100559, which evaluated the elevation requirements for
the upper internals lift. The upper internals was raised a total of 26 to 26.5 feet, as specified
per procedure, to provide a clearance of between 15 and 21 inches between the upper
internals storage stand guide stud and the upper internals fuel assembly guide pins. Overall,
good supervision of the evolution was evident as well as thorough implementation oflessons
learned from industry experience.
3.0
RADIOLOGICAL CONTROLS (71707)
Posting and control of radiation and high radiation areas were inspected. Radiation work
permit compliance and use of personnel monitoring devices were checked. Conditions of
step-off pads, disposal of protective clothing, radiation control job coverage, area monitor
operability and calibration (portable and permanent), and personnel frisking were observed
on a sampling basis. Licensee personnel were observed to be properly implementing their
radiological protection program except as described below.
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3.1
Improper IIcalth Physics Practices
On April 15, 1993, two separate incidents occurred at Unit I which involved improper
implementation of health physics requirements by four plant operators. These events
indicated a greater need for operator awareness of the requirements governing control of high
radiation areas.
The first event occurred when two operators entered the safeguards building 'A' penetration
area in order to post a clearance tag on a sample system valve. The entry way to this area
was barricaded, locked, and posted as Zone 5A (> 100 mR/hr, anti-Cs not required). An
inner area, which was entered by one of the operators, was roped off and posted as a
Zone SC (> 100 mR/hr, anti-Cs required). A high radiation barrier key was signed out by
one of the operators in order to gain access to the penetration area. The operators, however,
failed to obtain a radiation meter prior to entering the posted high radiation area even though
they had multiple opportunities to recognize the need for the meters (via multiple postings
and radiation barrier key control). Both operators were radiation meter qualified and thus
trained in the technical specification requirements for entering a high radiation area.
Technical Specification 6.12 states, in part, that any individual permitted to enter high
radiation areas shall be provided with a " radiation monitoring device which continuously
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indicates the radiation dose in the area." After the operators exited the 'A' penetration area,
a radiation control quality assessor noted that these individuals did not possess a meter. The
operators acknowledged that they had not signed out a meter for use in the high radiation
area and that it was an oversight on their part. The operators had been posting multiple
clearance tags on equipment throughout the safeguards building, but no other additional areas
were entered which required a radiation meter. The total doses received by each operator
during their entire shift was 10 mR. The survey map of the penetration area indicated that
the immediate area around which the operators were working had dose rates of less than 20
mR/hr.
The second event involved two additional operators who entered the 'C' reactor coolant
pump cubicle on the 718 foot elevation of containment. This area was posted as a high
radiation area (> 100 mR/hr) and the barricade door was locked shut. The operators who
entered the cubicle decided to leave the door open for personal safety so as to provide a
rapid exit if necessary. The barricade door is selflocking when fully shut but can be readily
unlocked and opened from inside the cubicle. The operators acted with the understanding
that they could act as a guard or personal barricade to the cubicle and thus maintain positive
control over access. However, neither operator was stationed at the cubicle door. Both
operators were instead involved in posting a clearance tag on the 'C' reactor coolant loop
flow transmitter isolation valves located on the intermediate leg. The operators believed that
positive control of access could still be maintained as they were in visual sight of the cubicle
entry way. Inspection of the 'C' cubicle area from the location of the flow transmitters
indicated to the inspectors that positive control of access could not be guaranteed from this
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vantage point. The inspectors concluded that the operators could not effectively act as a
personal barricade from their work location. Additionally, with the cubicle door full open,
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the high radiation area posting was concealed, since the posting was on the front of the door.
Therefore, the high radiation area was no longer conspicuously posted. These conditions are
contrary to Technical Specification 6.12.1 requirements which specify that each high
radiation area in which the intensity of radiation is > 100 mR/hr but less than 1,000 mR/hr,
be barricaded and conspicuously posted as a high radiation area.
The failure to maintain the 'C' reactor coolant pump cubicle doorway barricaded and posted
was identified by the licensee's health physics technicians. The door was left open for about
1 minute and no other individuals had entered the cubicle. Subsequent detailed surveys of
the cubicle indicated that remote but accessible areas of the cubicle, due to recently installed
scaffolding, have dose rates of greater than 1,000 mR/hr. The area in which the operators
was working had dose rates of about 50 - 75 mR/hr. Technical Specification 6.12.2 specifies
that in addition to high radiation areas being barricaded and conspicuously posted per TS 6.12.1, that locked doors to provided to prevent unauthorized entry into radiation areas
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.> 1,000 mR/hr. The cubicle door is self locking shut; however, the operators were not
aware that dose rates over 1,000 mR/hr existed within the cubicle. The posting on the door
was a Zone 5 area (> 100 mR/hr). The licensee plans on implementing a Zone 6 posting
(> 1,000 mR/hr) which will provide clarification to individuals regarding locked high
radiation areas.
The licensee has taken immediate corrective action to ensure that operators fully understand
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the requirements of Technical Specification 6.12. The meter qualification of all Unit 1
operators was suspended pending a briefing by the Operations Manager to discuss high
radiation area requirements. All operators were required to attend this briefing before being
reinstated as meter qualified. Additionally, specific questions and concerns of operators
regarding high radiation requirements and practices were formally answered and distributed
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to all operators. The four specific operators involved in these incidents have been
individually counseled.
The inspectors are concerned that if similar incidents continue to occur, then the potential
exists for possible excessive exposures or inadvertent exposures to workers. These two
incidents, and the broad scope of issues raised by operators during the subsequent briefings,
indicate a greater need for operator awareness of high radiation area technical specification
requirements and the licensee's policies for implementing them. The failure to enter a high
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radiation area without a meter and the failure to maintain a high radiation area either locked,
barricaded, or conspicuously posted is a violation (50-334/93-09-01) of Technical Specification 6.12. Although these events were identified by the licensee, the inspectors
noted that a previous similar violation of Technical Specification 6.12 occurred on June 13,
1992 (LER 92-06). These events, therefore, were not considered to meet the criteria of 10 CFR 2, Appendix C for a non-cited violation because they were not isolated.
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3.2
Work Encroaching on Posted High Radiation Area
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During a routine tour of the Unit I auxiliary building, one of the resident inspectors stopped
to observe some motor operated valve (MOV) testing in the 'A' charging pump pit. Only
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one worker was in the charging pump pit, and he was kneeling on the floor working on an
MOV. Approximately 1 foot from the worker was a posted high radiation area (HRA)
boundary consisting of a rope and a sign. The inspector noticed that just on the other side of
the HRA boundary (i.e., in the HRA) there were some MOV parts and a box of tools sitting
on the floor. The inspector asked the worker if the tools and parts were his. The worker
said that they were, but that the general area radiation level just over the HRA boundary was
only 6 mR/hr, and then stated that he would move his equipment anyway. Subsequently, the
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worker reached over the boundary and removed the parts and tools from the posted HRA.
The worker did not have a radiation monitoring device which would continuously indicate or
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integrate the dose rate in the area.
The inspectors presented this observation to Duquesne Light Company's health physics
personnel who subsequently surveyed the area and found that the maximum HRA boundary
radiation level was 6 mR/hr. The HP supervisor also explained to the inspector that the
boundary was only precautionary (in case a hot spot developed in the charging system piping)
and that the maximum radiation level in the posted HRA was 8 mR/hr. The HRA boundary
was moved to allow the worker to maintain more distance from the boundary.
Duquesne Light Company informed the resident inspectors that they consider it a poor work
practice for a worker to reach into a HRA, but as long as only his extremities pass into the
area, they do not consider the action as an actual entry into a HRA. Thus, the technical
specification requirements do not apply. However, because it is a poor practice, Duquesne
Light Company implemented a new station policy that requires implementation of HRA
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controls for passage of any part of a person's body across a HRA boundary.
4.0
MAINTENANCE AND SURVEILLANCE (62703,61726,71707)
4.1
Maintenance Observations
The inspectors reviewed selected maintenance activities to assure that: the activity did not
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violate Technical Specification Limiting Conditions for Operation and that redundant
components were operable; required approvals and releases had been obtained prior to
commencing work; procedures used for the task were adequate and work was within the
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skills of the trade; activities were accomplished by qualified personnel; radiological and fire
prevention controls were adequate and implemented; QC hold points were established where
required and observed; and equipment was properly tested and returned to service.
!
Maintenance work requests (MWRs), maintenance planning and scheduling (MPS), and
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preventive maintenance (PV) activities reviewed included:
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MWR 17565 Replace Diesel Fuel Injector Fuel Line
MWR 11493 River Water Valve MOV-RW-102B2 Replacement (see Section 6.3)
MWR 12545 Fuel Assembly Ultrasonic Examination (see Section 6.1)
MWR 06022 Emergency Diesel Generator 1-1 Insoection
The Unit 1 emergency diesel generator (EDG) maintenance was performed per maintenance
surveillance procedures 36.25-M, " Number 1 EDG Internal Inspection," and 36.22-M,
" Number 1 EDG Filter, Strainer, Heat Exchanger, and Woodwaru Governor Maintenance."
This maintenance is performed on an 18-month frequency per technical specification
requirements. Specific activities observed by the inspectors included:
air box inspection;
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head to piston clearance check;
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piston ring inspection;
engine nut and bolt torque check;
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cylinder liner inspection;
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rocker arm bushings and cam followers check;
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exhaust valve and injector timing adjustment;
injector rack inspection and setting;
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torsional damper inspection;
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fuel oil, lube oil, jacket water, air tubing inspection; and
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overspeed trip check.
The licensee's maintenance plan and inspection acceptance criteria (i.e., tolerance
specifications) were found to be consistent with the vendor's recommendations for
maintenance of standby stationary diesel generators (General Motors, EMD 645E). The
inspection procedure, as detailed in MSP 36.25, was developed per the guidance of the
vendor technical manual. This procedure was processed through the licensee's procedure
upgrade program and was of excellent quality. No engine deficiencies were identified during
the licensee's inspection. Based on the inspectors' review of measured. specifications and
observations, the engine was noted to be in excellent material condition Good vendor
interface with the licensee's mechanics was observed as well as proper oversight by
mechanical maintenance supervision. The vendor technical representative recommended that
one additional inspection be accomplished. Specifically, the ring to land clearance of the
upper piston compression ring should be measured for indication of ring wear. The
maintenance supervisor informed the inspectors that this would be evaluated for future diesel
inspections since this activity was not specified in the vendor technical manual.
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MWR 18208 Chargine Valve CH-18 Inspection
The licensee previously reported that the omission of charging system check valve CH-18 -
from the Unit 1 inservice test program creates a previously unanalyzed release path with the
potential to exceed 10 CFR Part 100 limits (see NRC inspection report 50-334/93-01). The
licensee's analysis assumed that CH-18 would not provide isolation between the seal water
heat exchanger and the recirculation flow path. Part of the licensee's corrective action was
to add this valve to its preventive maintenance program. The check valve has been
subsequently disassembled and satisfactorily " blue checked" to verify 360oF disc / seat
contact.
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MWR 17065 Chxk Emergency Diesel Generator 2EGS - EG2-2 Governor Oneration
On April 15,1993, the No. 2 emergency diesel generator (EDG) for Unit 2 was taken out of
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service to oneck the resistance of two motor operated potentiometers (MOPS). One MOP
was associated with the EDG speed control unit, and the other was part of the voltage control
unit. The inspectors found that the MWR for this maintenance had been open since February
18, 1993. The chronology of events associated with the MWR was as follows:
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On February 18,1993, the No. 2 EDG experienced slight load fluctuations while
being unloaded following its monthly surveillance test. The fluctuations were
documented as occurring below approximately 1000 kW; however, the magnitude and
duration of the fluctuations were not documented. The documentation did state that
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the governor performed satisfactorily at rated load. An MWR was generated to check
the EDG's governor performance during the next monthly surveillance test.
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On March 18,1993, the No. 2 EDG was monitored, as required by the MWR, duri_ng
its monthly surveillance test. Specifically, load was observed for fluctuation, and the
output of the unit's electronic governor assembly v as monitored for voltage
fluctuations. No voltage fluctuations were noted at the electronic governor assembly
1
output; however, a momentary load fluctuation of approximately 300 kW was noted
J
as load was decreased to around 1000 kW following the test. This anomaly was not
part of the MWR documentation. The inspe fors obtained the anomaly information
,
from personnel who were involved with the test.
The resistance checks on the MOPS were the next step in Duquesne Light Company's efforts
to resolve the load fluctuation problem. The inspectors observed the checks and reviewed
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the associated procedure. The resistance checks showed that the MOPS were functioning
correctly. The inspectors also observed the post maintenance test of the No. 2 EDG (the
monthly surveillance test). The EDG was observed to load and run satisfactorily, but during _
the unloading sequence, the unit did experience a load spike (a decrease followed by a return
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to the original value) of approximately 300 kW when load was between 1000 kW and
1500 kW. The spike lasted only a matter of seconds. During the spike, control room
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operators also observed that the power factor meter indication cycled between .99 and .1
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Duquesne Light Company has concluded that the No. 2 EDG is still fully operable since this
'
minor fluctuation only occurs during diesel shutdown and does not effect the ability of the
diesel to load and run. DLC plans to continue troubleshooting, probably during subsequent
monthly surveillance tests.
!
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The inspectors assessed that Duquesne Light Company's actions to resolve this problem were
,
adequate and that the troubleshooting was well controlled; however, documentation of the
,
problem characteristics, both in the operations logs and the MWR, was lacking in detail.
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The inspectors had no further questions at this time.
4.2
Surveillance Observations
The inspectors witnessed / reviewed selected surveillance tests to determine whether properly
approved procedures were in use, details were adequate, test instnimentation was properly
calibrated and used, technical specifications were satisfied, testing was performed by
,
qualified personnel, and test results satisfied acceptance criteria or were properly
dispositioned. The operational surveillance tests (OSTs), Beaver Valley Tests (BVTs), and
,
maintenance surveillance procedures (MSPs) listed below were reviewed. The observed
,
surveillance activities were properly conducted without any notable deficiencies unless
otherwise indicated.
OST 2.1.12 Safeguards Protection System Train 'B' Go Test
OST 2.36.17 Reactor Coolant Pump Bus Undervoltage Functional Test
OST 2.36.1
Emergency Diesel Generator Operability Test (Pre-op Checks)
BVT 1.11.3 SI Accumulator Discharge Check Valves Full Stroke Test
The Unit I safety injection (SI) accumulator discharge check valves (SI-48,49,50,51,52,
and 53) were tested during the ninth refueling outage to verify their full stroke capability in
l
accordance with Section XI of the ASME Code. The test methodology had been granted
interim approval by the NRC in a letter to Duquesne Light Company dated February 8,
1993. Final staff approval is pending a more detailed evaluation of the methodology by the
Oak Ridge National l2boratory.
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The test method was developed by the Fort Calhoun Station and is described in
NUREG/CP-0123, Proceedines of the Second NRC/ASME Symoosium on Pumo and Valve
Testing. It basically involves blowing down each of the accumulators at reduced pressure to
the reactor coolant system while measuring parameters which allow calculation of flow
through the check valves and pressure drop from the accumulators to the reactor vessel. The
flow and pressure drop are then used to calculate a flow coefficient. This value is then
compared with a theoretical flow coefficient which is derived from the system configuration.
l
If the measured coefficient is greater than the theoretical coefficient, then the check valves
are considered satisfactory.
In addition to using the Fort Calhoun test method, Duquesne Light Company also used non-
intrusive acoustic data to verify the opening and closing of the valves. This was done to
validate the Fort Calhoun test method for future use.
,
The inspectors observed part of the testing, reviewed the test results, and verified that the
test was performed in accordance with current commitments. The following observations
were made:
The temporary instrumentation used to measure the " Fort Calhoun" test parameters
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were specified to have an accuracy of at least 1 percent. Based on this level of
accuracy, the test engineers decided that it was not necessary to perform an accuracy
analysis on the test data. The inspectors noted, however, that the minor divisions on
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the strip chart recorder, which was used to record these parameters, were such that
readability could introduce considerably more than 1 percent error.
>
The calculations to derive the theoretical flow coefficient encompassed the' area
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between the accumulators and the reactor coolant system piping. The pressure drop
measurement was taken from the accumulators to the reactor vessel on loops A and B.
The theoretical flow coefficient calculation should normally encompass the same area
as the measured pressure drop; however, omitting the additional piping from the
calculation is conservative, making the theoretical coefficient higher, and, therefore,
'
more restrictive.
The inspectors assessed that the use of the non-intrusive testing was a good initiative and
should be sufficient by itself to meet the ASME Code,Section XI requirements, as well as
Position 1 of Generic Letter 89-04, " Potential Generic Deficiencies Related to IST Programs
and Procedures." However, the modified Fort Calhoun test methodology should be subjected
to an accuracy analysis prior to use as the sole method of meeting the ASME Code and
Generic Letter 8944 requirements. Duquesne Light Company is evaluating alternate data
recording methods to increase the accuracy of the Fort Calhoun methodology.
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4.3
Configuration Control
The inspectors reviewed the licensee's configuration controls in preparation for the Unit I
core alterations. Technical specifications define core alteration as the movement or
manipulation of any component within the reactor pressure vessel with the vessel head
removed and fuel in the vessel. The licensee does not consider the lifting of the reactor
vessel head a core alteration. However, the licensee does establish containment closure as a
>
precautionary measure when the head is initially raised.
Operational surveillance test OST-1.49.3, " Refueling Operations Prerequisites," is the
licensee's governing document which assures all refueling operations technical specification -
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surveillance requirements are completed prior to core alterations. These requirements
include conditions such as minimum reactor coolant system boron concentration, duration of
reactor subcriticality, and communications between control room and refueling personnel.
The inspectors observed and/or verified that the following additional technical specification
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(TS) surveillance requirements were satisfied within specified time limits:
OST 1.2.3, " Source Range Neutron Flux Monitor Channel Functional Test," (TS
4.9.2.b);
RP-9R-3.3, " Manipulator Crane Load Test," (TS 4.9.6.1), and " Auxiliary Hoist Imad
>
Test," (TS 4.9.6.2);
MSP 60.03, " Spent Fuel Bridge Crane Interlock and Travel Test," (TS 4.9.7);
OST 1.44.C.1, " Containment Purge and Exhaust System Isolation," (TS 4.9.9); and
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OST 1.16.4, " Fuel Building Ventilation System Operation," (TS 4.9.12).
Additionally, the inspectors performed an independent walkdown of containment closure
prior to and during core alterations. OST 1.47.3, " Containment Integrity Checklist for
Refueling," is used to verify containment closure of the equipment access hatch, personnel
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airlock, and each containment penetration which could provide direct access from the
containment atmosphere to the outside atmosphere. The closure of temporary penetrations is
,
discussed in Section 6.7. The inspectors verified the containment closure of penetrations
associated with the secondary side of steam generators (IRC-E-1A, IB, and IC) and river
water piping serving the recirculation spray heat exchangers (IRS-E-1 A, IB, IC, and ID), -
and penetrations associated with various other miscellaneous systems. Valves associated with
these containment penetrations were verified closed with a clearance tag posted (clearance
permit numbers 650732,33,34,35, and 36). System and piping integrity between the
containment penetration and system isolation valve were also verified. No discrepancies
~
were noted by the inspectors. The inspectors also observed the Independent Safety
Evaluation Group Chairman performing an independent walkdown of containment closure to
identify possible breaches as experienced by other nuclear facilities. Overall, the licensee
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demonstrated the ability to ensure all core alteration prerequisites were satisfied and that
proper controls existed to maintain containment closure throughout the core alteration
evolution.
4.4
Unit 1 Steam Generator Tube Eddy Current Examinations
The licensee conducted an extensive steam generator tube examination program to assess the
integrity of tubing in the Unit I steam generators. . An NRC inspection of the licensee's
inservice inspection program included portions of the steam generator tube eddy current
examinations and is reported in NRC inspection report 93-08/08. The licensee's eddy
current examinations and corrective actions are summarized below.
The Unit I steam generator examinations consisted of bobbin coil examination of 100 percent
ofinservice tubes. Inconclusive bobbin coil examination results, such as distorted support
plate indications, and areas of interest, such as the inner U-bends and tubes at certain areas
of the tube sheet, were further eddy current examined with'a rotating pancake coil. Any
tubes with indications greater than allowable and other suspect tubes were plugged. The
plugs used were Babcock and Wilcox (B & W) plugs made of Iconel 690.
The primary cause of tube degradation for the tubes plugged during this refueling outage was
stress corrosion cracking at the lower tube support plates. The degradation of 77 percent of
the tubes plugged was attributed to this cause. Stress corrosion cracking at the sludge pile
accounted for 15 percent of the tubes plugged. Cold leg thinning (vibration induced wear on
the cold leg side of periphery tubes at the lower support plates) and primary water stress
corrosion cracking (PWSCC) at the inner U-bends, each accounted for approximately
]
4 percent of the tubes plugged. The U-bend PWSCC occurred only in the 'B' and 'C' steam
generators. The 'A' steam generator inner U-bends were heat treated several outages ago to
prevent PWSCC and no PWSCC has occurred since in that generator. The licensee is now
]
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considering heat treating the inner U-bends of the 'B' and 'C' generators. No tubes were
plugged due to loose parts wear and no tubes were plugged due to denting.
Previously installed plugs were also examined. One cold leg and one hot leg plug were
found cracked. The cold leg plug was a B & W plug made of regular Inconel 600. The
licensee replaced that plug and all other plugs from the same heat with B & W Inconel 690
plugs. The hot leg plug was a B & W plug made of enhanced Inconel 600, and it was also
replaced with a B & W Inconel 690 plug.
The licensee is participating with Westinghouse in the development of a tube repair
technology that uses a laser to remove cracks by heating the cracked metal. During this
outage, one steam generator tube was repaired in two locations using this technique. ' The
tube was subsequently removed and has been sent to a laboratory for detailed analysis. The
tube location was then plugged. Eddy current examination of tubes adjacent to the repair site
showed that they were not affected by the repair.
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There are 3,388 tubes in each Unit 1 steam generator (SG). The tube plugging status at the
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completion of tube work activities during the current refueling outage (9R) is as described
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below:
A SG
B SG
CEi
Total
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Tubes plugged in 9R
221
197
150
568
Tubes plugged pre-9R
507
302
244
1,053
Total tubes plugged
728
499
394
1,621
y
Percent plugged
21.5 %
14.7 %
11.6 %
15.9 %
The limiting break loss of coolant accident reanalysis for increased SG tube plugging is
presented in Section 14.3.2.2 of the Unit 1 FSAR. This previous reanalysis assumes a
maximum of 20 percent of the tubes in any one SG or 20 percent of the total tubes in all
I
three SGs are plugged. The licensee is preparing another reanalysis and a 10 CFR 50.59
review to approve operating with m' ore than 20 percent of the tubes plugged. This revised
reanalysis and 10 CFR 50.59 evaluation would be completed prior to plant restart from the
]
current refueling outage.
The inspectors considered that the licensee's SG tube and plug examination were
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comprehensive. The tube repair technology development was a noteworthy initiative. The
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inspector had no further questions at this time.
5.0
SECURITY (71707)-
Implementation of the physical security plan was observed in various plant areas with regard
!
to the following: protected area and vital area barriers were well maintained and not
compromised; isolation zones were clear; personnel and vehicles entering and packages being
delivered to the protected area were properly searched and access control was in accordance
with approved licensee procedures; persons granted access to the site were badged to indicate
whether they have unescorted access or escorted authorization; security access controls to
vital areas were maintained and persons in vital areas were authorized; security posts were
adequately staffed and equipped, security personnel were alert and knowledgeable regarding
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position requirements, and that written procedures were available; and adequate illumination
was maintained. Licensee personnel were observed to be properly implementing and-
following the Physical Security Plan.
6.0
ENGINEERING AND TECHNICAL SUPPORT (37700,37828,71707)
6.1
Unit 1 Fuel Inspection
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The inspectors observed the performance of ultrasonic (UT) examination of the 9R fuel
'
assemblies following complete core offload by the licensee. The fuel inspection was
performed in order to confirm suspected fuel failures based on previous Westinghouse and
.
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Duquesne Light Company analyses of reactor coolant activity. The licensee planned on
performing fuel reconstitution of the fuel assemblies with identified failures thus preventing
core reload with failed fuel pins (rods).
The technique for the UT examination of pressurized water reactor fuel assemblies uses the
" Failed Fuel Rod Detection System." The services for this inspection were provided by ABB
Combustion Engineering. Each fuel rod was individually examined by ultrasonic means,
normally at 2 to 3 inches above the first grid strap. As a conservative measure, the licensee
took another set of UT measurements at a second elevation of 2 to 3 inches below the second
grid strap. The licensee has found that a UT examination at only the lower elevation may
fail to detect a leaky fuel rod in certain instances. A failed fuel rod is identified by the
presence of water (reactor coolant) between the fuel pellet and cladding. Water in a leaking
fuel rod reduces the UT signals transmitted through the cladding. Defect free rods are
internally pressurized with helium which serves to minimize compressive clad stresses and
,
creep due to coolant operating pressures. The UT examinations discovered a total of 11
failed fuel assemblies, consisting of 35 individual failed rods. All of the failed rods were
found in the 'K' fuel assemblies which have experienced two reactor cycles. All of the 'K'
,
fuel assembles were of the Westinghouse 17 by 17 Vantage 5 Hybrid (V5H) design. This
design is characterized by the use of zircaloy grid straps vice Inconel-718 and debris filtering
,
bottom nozzles. Of the 35 failed rods,30 were located within fuel assemblies adjacent to the
core baffle assembly. One fuel assembly in particular, "K-16," was found to contain 18
failed fuel rods. Subsequent remote detailed visual inspection of the 11 fuel assemblies did
not indicate the presence of any debris induced fretting. However, the licensee's root-cause
analysis of the failure mechanism was still in progress with assistance from Westinghouse.
Baffle jetting is not suspected due to a previous flow conversion modification which changed
the flowpath between the core barrel and baffle plate from a downflow configuration to an
,
upflow configuration. The inspectors discussed the unexpected performance of the twice
burned V5H fuel with specialists from NRC headquarters. Headquarters subsequently
scheduled a meeting with Westinghouse to discuss V5H fuel performance.
As an immediate corrective action, the licensee conservatively elected not to reload the core
with any of the 'K' fuel assemblies. This included all of the twice burned (two reactor
cycle) V5H 'K' fuel, even those assemblies which did not show any indication of failed rods.
The licensee has replaced the 'K' assemblies with twice burned 'J' assemblies which were
being stored in the spent fuel pool. The 'J' fuel assemblies are standard 17 by 17 with
Inconel grid straps. Twenty 'J' fuel assemblies have been reloaded into the core adjacent to
the baffle plate. Additionally, for those 'L' fuel assemblies (V5H design) which will
undergo their second cycle adjacent to the baffle plate, wet annular burnable absorbers
(WABAs) have been inserted into the rod cluster control assembly guide tubes. The WABAs
will thus function to provide a dampening effect and reduce the potential for flow induced
vibration. The burnable poisons in the WABAs have previously experienced a fuel cycle and
will have minimal impact on the core reload analysis. This action is intended to prevent the
i
VHS 'L' fuel assemblies adjacent to the baffle plate from experiencing the same failure as
the 'K' assemblies during their second fuel cycle.
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Prior to the refueling outage shutdown, the licensee's analysis of reactor coolant activity
indicated there were at least eight failed rods. At least two of these failures were large, open
defects with intimate contact between the fuel pellets and bulk coolant water. This analysis
was performed independently by the licensee's reactor engineering staff and chemistry staff.
The Westinghouse Nuclear Fuels Group estimated four failed rods based on the same data.
This analysis was based on the activity concentrations of iodine (I)-131, I-134, Xenon
(Xe)-133, and the I-131/133 ratio. An increase in I-131 activity (corrected for TRAMP) was
apparent following the reactor trip on October 9,1992.1-131 activity (micro-curies per
gram) increased from 5.096 X E-4 prior to the reactor trip to 1.937 X E-3 prior to reactor
shutdown for refueling. The analysis for estimating the number of failed rods based on
iodine activity did not, however, model the low power fuel assemblies very well. This was
due to the fact more iodine was released from fresh fuel than the second or third cycle low
power fuel assemblies. Therefore, with 30 failed rods located in low power fuel assemblies,
the licensee's estimate for the number of failed fuel rods was off by a factor of four.
The Xe-133 analysis for estimating the number of failed rods was consistent with the I-131
analysis through January 1993. However, the licensee was unable to obtain a pressurized
reactor coolant sample (for Xe-133) between January 12 and March 23,1993, due to the
failure of hot leg sample valve TV-SS-105A1. This inside containment isolation valve
showed dual indication in the control room; therefore, in order to satisfy TS 3.6.3.1 for
containment isolation valves, it was necessary to maintain the outside isolation valve,
TV-SS-105A2, deenergized shut. The licensee decided not to repair TV-SS-105A1 due to
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the multiple containment entries required, past experience on repair attempts of similar
sample valves, high dose rates, and the belief that iodine activity alone was sufficient to
estimate the number of failed fuel rods. No technical specification reactor coolant samples
were required through TV-SS-105A1. The licensee did, however, have the installed
capability to obtain pressurized reactor coolant samples (for Xe-133) from the reactor coolant
cold legs. Although the licensee had an established procedure for obtaining a pressurized
cold leg sample, it had not been needed for implementation in over 10 years. Thus,
concerns existed over the possibility of corrosion products in the sample lines. In fact, the
licensee experienced difficulty in obtaining sufficient purge flow and in operating the sample
line trip valves. A pressurized cold leg sample was finally obtained on March 23,1993,2
days after a power reduction to 48 percent. Analysis of the Xe-133 activity, power
corrected, indicated between 21 and 28 fuel failures. This result was not considered credible
since it was only one data point taken under transient conditions in which fission product
levels were elevated due to , spiking. Additional samples were not obtained due to the start of
'
degassing in preparation for the reactor shutdown on March 26. Although hindsight can be
applied, it is apparent that the licensee's inability / difficulties in obtaining a pressurized
reactor coolant sample for Xe-133 hindered their ability to accurately predict the number of
failed fuel rods.
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6.2
Unit 1 AMSAC Design Change
The inspectors reviewed the implementation of design change 1555 to the Unit 1 ATWS
mitigation actuation circuitry (AMSAC). The AMSAC system was designed to limit reactor
coolant system pressure, diverse from the reactor protection system, by automatically
initiating the auxiliary feedwater system and a turbine trip under conditions indicative of
automatic AMSAC bypass when less than 40 percent power (C-20 permissive) and to
improve the logic levels.
On December 11, 1990, the Ginna Power Station (Rochester Gas & Electric) experienced a
turbine trip and reactor trip as a result of an AMSAC circuit card design deficiency (see
NRC inspection report 50-244/90-28). Troubleshooting of the AMSAC logic circuitry by
Ginna personnel identified that lower than expected logic output voltage (6.5 Vde) caused the
AMSAC trip to occur. Foxboro, the manufacturer of AMSAC at both Ginna and Beaver
Valley, recommended that to correct this design deficiency, a jumper connecting the negative
input terminal to common was necessary. After completion of this design change by Beaver
Valley, AMSAC functional test (Procedure IT-45B-1555-1) verified that logic voltage levels
increased from 7.2 Vdc and 8.1 Vdc to 9.6 Vdc and 9.7 Vdc. Completion of this design
change was indicative of the licensee's continuing efforts to apply lessons learned from other
nuclear facilities to Beaver Valley, and in this case, thus reduce the possibility of inadvertent
AMSAC actuations.
.
The second part of this design change involved adding a control room annunciator to
continuously indicate that AMSAC was automatically bypassed when secondary power was
less than 40 percent power. The licensee previously identified that their commitment to
providing control room indication for an operating bypass was not satisfied. Duquesne Light
Company letter NDINSM: 2560, dated February 27,1987, to the NRC stated, in part,
. . . a control room annunciator provides indication when AMSAC is bypassed by the C-20
"
permissive." This information was also specified in the NRC safety evaluation of AMSAC.
The inspectors reviewed engineering memorandums 30812 and 76212 and memorandums
between the nuclear safety department and nuclear engineering department (dated
September 5,1990, and December 5,1990). This documentation clearly indicated that the
required bypass annunciator was finally implemented as a result of persistent and diligent
efforts by the licensee's nuclear safety department to ensure NRC commitments were fully
satisfied. The inspectors considered these efforts to be appropriate.
The inspectors also reviewed the licensee's completion of AMSAC testing to ensure the
testing commitments were fully sanfied. Duquesne Light Company letter (ND3NSM: 3016)
to the NRC, dated December 12, 1987, specified that periodic testing of AMSAC will
include a functional test of the logic, time delays, setpoints, and an end-to-end test from the
instrument channel inputs to AMSAC through the final actuation devices. Operability of the
Unit 1 and Unit 2 AMSAC systems have been verified by the completion of OST 1.45.B.1
(June 22,1991) and OST 2.1.20 (April 15,1992) respectively. These tests are performed on
,
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an 18-month frequency and satisfy the end-to-end testing requirements. Loop calibration
procedure ILCP-24-AMSAC satisfies the periodic testing requirements of AMSAC logic,
time delays, and setpoints for Unit 1. The inspector had no further questions at this time.
6.3
Unit 1 Temporary Spent Fuel Pool Cooling
During the refueling outage, the licensee planned to remove the reactor plant component
cooling water (CCR) system from service due to numerous maintenance activities. This
included replacement of the river water return header from the CCR heat exchangers which
had recently developed a through-wall pinhole leak (see NRC inspection report
50-334/93-03). The CCR system normally supplies the spent fuel pool (SFP) heat
exchangers and residual heat removal (RHR) heat exchangers for decay heat removal. It was
therefore necessary for the licensee to design a temporary modification to provide cooling to
the SFP heat exchangers while the core was completely offloaded.
The licensee used two redundant temporary cooling loops consisting of two heat exchangers
(15.6 X E6 BTU /hr capacity), each with a 1,500 gpm pump and connecting piping / hoses.
The temporary loop circulated demineralized water on the shell side of the SFP heat
exchangers with normal fuel pool cooling circulating on the tube side to cool the fuel
assemblies. The temporary modification heat exchangers were cooled by river water from
the main river water header. The FSAR allows for the use of river water to supply the SFP
heat exchangers, via blind flanges and hoses, in the event of a complete loss of component
cooling water. The temporary modification is thus being used under this similar condition
described in the FSAR, except that a demineralized water loop will interface between the
river water and SFP heat exchangers. This is intended to minimize the fouling of the SFP
heat exchangers due to river water. The design heat load of the temporary modification heat
exchangers is based on maintaining SFP temperature less than the operational limit of 143oF.
The maximum allowable fuel pool temperature was established as 185oF based on thermal
stresses induced on the concrete structure of the pool. The licensee analyzed multiple system
lineups, assuming 21 days (500 hours0.00579 days <br />0.139 hours <br />8.267196e-4 weeks <br />1.9025e-4 months <br />) after reactor shutdown, with varying conditions of
river water temperature and flow. The temporary cooling loops were provided with cross
ties so that either loop could provide cooling for either or both SFP heat exchangers.
Inspectors review of these calculations indicates that sufficient margin exists to maintain SFP
temperature less than 185cF.
The temporary cooling system was implemented with backup systems such as multiple pump
power supplies. The primary electrical power supply was either Class 1E motor control
centers E-7 or E-8, depending on train priority. These busses could be powered from either
offsite (via main transformer backfeed, station transformers, or unit transformers) power or
the priority train diesel generator. A commercial grade power supply from the Unit 2
construction transformer was also readily available. River water, auxiliary river water, and
fire water were available to either supply the temporary heat exchangers or supply the shell
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side of the SFP heat exchangers directly. Response procedures were developed to address
emergency actions for loss of offsite or emergency power, loss of river water to temporary
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SFP cooling, and loss of the temporary SFP cooling system. Two operators were stationed -
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to monitor the performance of the cooling system 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day. The inspectors questioned
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operators on their emergency response actions and found them to be knowledgeable of their
responsibilities. Construction craft personnel were also stationed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day in order to
rapidly respond to any leaks in the temporary cooling piping or hoses.
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The licensee had previously evaluated this modification as a "high risk evolution" during the -
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pre-outage shutdown safety review (see NRC inspection report (50-334/93-03). The licensee
appropriately designated this evolution as an " Infrequently Performed Test and Evolution "
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(IPTE). Specific guidance is pmvided for the conduct of these evolutions, including the_
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degree of management involvement and management's expectations of station personnel.
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The Unit 1 Operations Manager was designated as the IPTE manager. The Operations'
Manager's involvement was evident as he had the primary power supply of the temporary
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pumps changed to Class IE. The original design designated the Unit 2 construction ' '
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transformer as the primary supply. Pre-evaluation briefings were conducted on all aspects of
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the temporary cooling system, including system setup, test, operation, and removal. Items
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stressed by the IPTE manager included the need for exercising caution and conservation,
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emphasis on maintaining the highest margins of safety, and the need for open~
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communications and a questioning attitude.
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The initial confidence test of the temporary cooling system was performed with the entire
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core offloaded. The CCR system was maintained available to support the SFP heat
exchangers (single valve isolation) if the confidence run did not produce desired results. ,The
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test run was performed for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, vice the originally planned 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, so that each ~
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individual train of temporary cooling and both temporary heat exchangers in parallel
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demonstrated the ability to maintain adequate core cooling. Initial pool temperature, based
on local indication, was 99oF and peaked at 108oF with two temporary heat exchangers in.
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service. For the 14 days while the temporary modification was in service, fuel pool
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temperature was maintained at less than 110oF.
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Prior to establishing temporary SFP cooling, replacement of river water pump discharge.
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valves, MOV-RW-102A2, B2, and C2 was necessary due to valve leak by. This .
maintenance was within the scope of the IPTE. In order to permit adequate two-valve
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isolation for this maintenance, the auxiliary river water (ARW) system was used to supply
normal river water loads while in Modes 5 and 6. The 'C' river water pump was maintained
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in " pull to lock" so as to be available if needed. Use of the river water pump would only.
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provide single valve isolation to the maintenance activities, thus inadvertent pump start would -
be precluded while in " pull to lock." The river water system is not required to be operable
in Modes 5 and 6. The ARW system is designed to supply normal river water system loads,
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such as the emergency diesel generators, in the event of a postulated loss of the Category I
intake structure due to a gasoline barge impact. Portions'of the ARW piping between the
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alternate intake structure and the river water system are not, however, seismically designed.
Also, the ARW pumps, although powered from a Class lE power supply, are not designed to
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automatically sequence onto the emergency diesels in the event of a loss of offsite power.
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Inherent in the definition of operability is that a system can perform its specified safety
functions only when all its necessary support systems are capable of performing their related
support functions. Under certain postulated conditions in which the ARW system is
degraded (i.e., loss of offsite power, seismic event), diesel generator operability can only be
ensured by manual operation such as starting the river water pump from " pull to lock."
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Generic Letter 91-18 specifically addresses the use of manual action in place of automatic
action. The use of manual action must focus on the physical differences between automatic
and manual actions and the ability of the manual action to accomplish the specified function.
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The physical differences to be considered include the ability to recognize input signals for
action, ready access to or recognition of setpoints, design nuances that may complicate
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subsequent manual action, time required for automatic action, minimum manning
requirements, and emergency operating procedures written for the automatic mode of
operation. The licensee determined that operation of the ARW system to support Mode 5
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and 6 equipment loads, while maintaining one river water system "available," was
acceptable. This determination was based on an memorandum from the Nuclear Safety
Department which stated,
" Based on the Mode 5 or 6 potential events, required manual operator actions to
restore river water flows can be performed without reliance on automatic protection
systems to mitigate the consequences of shutdown events associated with Modes 5 or
6, when in conjunction with approved operator response guides."
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The inspectors, however, concluded that a " basis for continued operability," (BCO) would
have been more appropriate to address and document the specific points of Generic letter
91-18 noted above, as well as compensatory measures taken, applicable conservatism, and
probability of needing the safety function. The inspectors discussed this issue with the
Nuclear Safety Director who agreed that the BCO could have been used in this case and that
this would be applied as a lessons learned. The inspectors did agree that the diesel was
operable, based on manual action if needed under certain postulated events. The Operations
Safety Committee (OSC) ensured that written procedures were established to direct operators
to manually restore river water under various scenarios. The OSC review of diesel cooling
requirements indicated that river water must be restored within 10 minutes of diesel start.
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This was appropriately addressed in the emergency response procedures. Operators were
found to be knowledgeable of the actions needed to restore river water in the event of a loss
of auxiliary river water.
Despite the need for open communications during an IPTE, two instances occurred in which
communications were poor. The first involved the replacement of MOV-RW-102B2.
During IPTE briefing, the IPTE manager explicitly instructed that the valve not be removed
until the replacement valve was staged and ready to be installed. This was intended to
minimize the time the river water system was open since if river water pump 'C' needed to
be started, then only single valve isolation was available to the workers. As discussed
above, the ARW system was supplying normal river water loads so that two valve isolation
was provided. However, the inspectors discovered craft personnel removing every other bolt
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from MOV-RW-102B2 while the replacement valve was not yet ready for installation. The
work was being performed per an authorized work permit, with the river water system
already removed from service and within the clearance boundaries. The inspectors informed
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the shift supervisor who was unaware that this work had begun. The shift supervisor did not
believe this work was authorized, per the IP'TE briefing, and immediately and appropriately
secured the work. Review of this incident found that a different shift supervisor, who was
not on shift at the time of the IPTE briefing, had signed the work permit and authorized
work to begin. Although the shift supervisor had the authority to sign the work permit, this
was contrary to the directions provided by the IPTE manager via his pre-job briefing and
night orders. The second incident involved maintenance on MOV-RW-113B, emergency
diesel generator 1-1 cooling water supply. Temporary SFP cooling was operating at the time
and the importance of this system for decay heat removal was stressed at the shift outage
meetings. Maintenance was authorized to setup MOVATS test equipment on RW-113B;
however, operations personnel were. not aware that this required RW-113B to be opened.
This in turn diverted about 200 gpm of river water flow from the temporary heat exchangers
to the diesel coolers. Although the temporary SFP cooling system was designed for river
water to adequately supply both the diesel and temporary heat exchangers and no heatup was
experienced, the diversion of river water flow was unexpected. The project shift
coordinators, operators, and control room staff were unaware of the cause of the river water
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flow degradation. The electricians performing the MOVATS setup were not aware that their
work affected the temporary SFP cooling system. The cause of the flow diversion was
discovered within a few hours and the system was restored. These incidents stress the need
for communications between the control room staff, project coordinators, outage
coordinators, craft personnel, and management to meet the highest standards during an IPTE
so that complete control of evolution is guaranteed. The inspector had no other questions at
this time.
6.4
Modification for Station Blackout (SBO) Cross Tie Between Unit I and Unit 2
Design Change Package (DCP) -1698, " Cross Tie BV-1 and BV-2 Diesel Generators," was
initiated by Duquesne Light Company in order to comply with the requirements of
10 CFR 50.63, " Loss of all Alternating Current Power." The modification permits the
station to cross-tie the 2A or 2D non-emergency 4.160 kV bus at Unit 2 to the 1 A or ID
4.160 kV non-emergency bus at Unit 1. The non-emergency busses at each unit can be tied
to the emergency busses using existing equipment. Therefore, a unit which experiences an
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SBO can receive power from one of the other unit's emergency diesel generators (or offsite
power lines, if available).
Duquesne Light Company's SBO concept was evaluated by the NRC and was found
acceptable, with recommendations. The recommendations are documented in a safety
evaluation report dated November 23,1990. Duquesne Light Company committed to the
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NRC's recommendations by letter dated December 20,1990.
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The inspectors reviewed selected portions of the DCP, performed walkdowns of the four
cross-tie breakers, and observed part of the actual installation at Unit 1. The Unit 2 part of
the design change was installed during their last refueling outage. Additionally, the cross-tie
functional test was observed and the associated paperwork was reviewed.
The cross-tie functional test involved energizing a Unit I chiller on the ID non-emergency
bus through the cross-tic from the 2A non-emergency bus. The 2A bus was powered directly
from offsite through its station service transformer. This test passed approximately 35 amps
of current through the entire length of the new cross-tie cable (approximately 20 percent of
the maximum load which could be expected under SBO conditions). The test was considered
satisfactory because the voltage drop across the cable was less than 1 percent.
Duquesne Light Company experienced one significant problem during the functional test.
The chiller on the ID bus tripped on under voltage (UV) even through the bus was energized
through the cross-tie. This happened because the test writers did not realize that the UV
trips were also enabled when the normal power supplies for the bus were not present (the
station and unit transformers).
The inspectors did not note any significant problems with the physical installation of the
modification or the DCP paperwork. The functional test, Beaver Valley Test 2.36.3, was
well controlled, thoroughly briefed, and the change to prevent the chiller from tripping on
UV was properly implemented. Overall, Duquesne Light Company demonstrated a very
good safety perspective during the test.
As the report period ended, the inspectors were reviewing the overall adequacy of the SBO
modification tests and Duquesne Light Company's actions to comply with their commitments
outlined in the December 20,1990, response to the SBO Safety Evaluation Report.
6.5
Unit 2 HHSI Pump Lube Oil System Support Bracket Deficiencies
As discussed in Section 2.2 of this report, six pipe support brackets were found missing from
the lube oil systems for the 21B and 21C high head safety injection (HHST) pumps (two from
21B and four from 21C). Duquesne Light Company promptly restored all six brackets by
transferring parts from the 21A HHSI pump lube oil system. This action alleviated any
question of operability on the 21B and 21C HHSI pumps. Replacement brackets for the 21 A
HHSI pump oil system were installed within a week following removal of the original
brackets.
Unit 2 at Beaver Valley has three HHSI/ charging pumps (21 A,21B, and 21C). Technical
specifications require only two of the three pumps to be operable. Duquesne Light Company
prefers to keep the 21A pump out of service to minimize the amount of gas accumulation
(and subsequent venting) in the non-running pumps. Typically, one pump runs continuously
for normal charging.
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Duquesne Light Company did not consider any of the HHSI pumps inoperable because of the
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missing brackets, and they performed a detailed engineering stress analysis to support this
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conclusion. The analysis showed that they still had a significant amount of margin between
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the allowable stress and the calculated actual stress for their design basis seismic event.
Duquesne Light Company was still trying to determine the reason for the missing pipe
support brackets when the report period ended. Determination of the reason for the missing
brackets is identified as an unresolved item (50-412/93-09-02). They had determined,
however, that one of the missing brackets on the 21B HHSI pump lube oil system had been
identified in a maintenance work request during October of 1992. Additionally, an
engineering memorandum (No. 104224) was written in November of 1992 to initiate an
evaluation of the correct replacement for the missing bracket. Neither document resulted in
the unanalyzed condition of the HHSI system being addressed. Thus, the deficiency still
existed in April of 1993, until a similar condition was identified by NRC inspectors on the
21C HHSI pumps. The failure of Duquesne Light Company to promptly correct this
condition is seen as a violation of 10 CFR 50, Appendix B, Criterion XVI, which requires
that measures shall be established to assure that conditions adverse to quality are promptly
identified and corrected (50-412/93-09-03).
The inspectors assessed that Duquesne Light Company's actions following the April 1993
identification of the missing brackets were prompt, thorough, and appropriate.
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6.6
Unit 2 Modifications for Heat Exchanger Performance Monitoring
in response to Generic Letter 89-13 " Service Water Systems Problems Affecting Safety-
Related Equipment," Duquesne Light Company initiated a design change package
(DCP-1502) to enhance performance monitoring of various Unit 2 safety related heat
exchangers. The inspectors reviewed portions of the design change associated with the heat
exchangers for the high head safety injection (HHSI) pump lube oil systems. The change
involved the addition of a thermowell and a resistance temperature element to the inlet oil
pipe and the modification of the thermowell and resistance temperature element on the oil
outlet pipe of each heat exchanger.
The inspector's review was initiated following the discovery of the missing pipe support
brackets for the 21B and 21C HHSI pump lube oil systems (see Sections 2.2 and 6.5 of this
report). Duquesne Light Company engineers were not able to locate the original isometric
drawings for the HHSI pump lube oil systems to perform the pipe stress analysis discussed in
Section 6.5 of this report. Consequently, they were forced to make their own drawings.
The inspectors were aware of changes to the HHSI pump lube oil system piping as a result of
DCP-1502, and questioned how adequate pipe stress margins were verified without the
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isometric drawmgs.
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Duquesne Light Company was not able to produce any documentation of an engineering
analysis or determination to support the adequacy of post-modification piping stresses for the
HHSI pump lube oil systems. According to the design concept document for DCP-1502,
pipe stress calculations for seismically supported piping would be required and checked.
Engineering personnel involved with the pipe stress calculations for DCP-1502 stated that
due to the minor nature of the modification they probably decided back in 1991 that it was
unnecessary to analyze such a change. They also stated that if the DCP had been generated
in 1993, pipe stress loading documentation would be available in the package. Duquesne
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Light Company engineering personnel said that they would generate adequate documentation
to support the current configuration of the HHSI pump lube oil piping. The analysis
discussed in Section 6.5 of this report already envelopes about 50 percent of the system
piping. Pipe stress calculations were available for all of the other piping modifications
encompassed by DCP-1502.
6.7
(Closed) Violation (412/92-07-02) Temporary Containment Penetration Seals
During the last Unit 2 refueling outage, temporary fire stops were used to seal two
containment penetrations to establish containment closure during core alterations. The
penetrations were used for temporary cables to support outage work. The type of seal used
was not in accordance with station procedures or technical specifications. For corrective
actions, the licensee requested an amendment to technical specifications and revised several
procedures.
By Amendment 170 to the Unit 1 technical specifications and Amendment 50 to Unit 2
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technical specifications, both issued on April 6,1993, the use of an approved functional
equivalent to a valve or blind flange was approved for closing containment penetrations to
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establish containment closure during core alterations. A new installation procedure,
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1/2 CMP-47-Penetration-1ME, was developed detailing the installation and removal of
temporary containment penetrations. This procedure is common to Units 1 and 2. It
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replaced Unit 2 procedure 2 CMP-75-SG Cable Install-1E and the corresponding Unit 1
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installation procedure. Plant installation process standard PIPS M16.3 was revised to include
temporary containment penetration seals for use in Modes 5 and 6. PIPS M16.3 is
referenced by the installation procedure and details using silicone foam to seal the
penetration. Technical evaluation report TER 7216 was prepared which evaluated the
technical acceptability of using the sealant. A new administrative procedure, NGAP 7.10,
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" Control of Penetrations," was developed which consolidated the administrative requirements
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and controls for all types of permanent and temporary penetration seals. Administrative
procedure NGAP 3.5, " Fire Protection," was also revised. These new and revised
procedures were reviewed and approved by the Onsite Safety Committee.
The inspectors reviewed the installation of temporary containment penetration seals for the
current Unit I refueling outage. The inspectors concluded that the temporary seals were
properly installed in accordance with these procedures and revised technical specifications.
The installation procedures include the routing of both cables and tubing through the
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containment penetrations. Tubing installed through the temporary penetration seals included
isolation valves to provide containment closure. The inspector observed that the position of
these temporary valves was properly controlled in accordance with procedure LOST-47.3,
" Containment Integrity Checklist for Refueling." The installation of the cables to the
penetrations was under review by the inspectors at the end of the inspection period. The
inspectors considered the licensee's corrective actions for the violation to be very thorough.
This item is closed.
7.0
SAFETY ASSESSMENT AND QUALITY VERIFICATION (40500,71707,
90712, 91700)
7.1
Unit 2 Reactor Trip System Surveillance Enforcement Discretion
On April 5, while reviewing NRC Information Notice 93-15, the licensee determined that
surveillance test OST 2.1.17 did not assure that the manual reactor trip switch contacts
tripped the shunt trip coils of the reactor trip breakers. As described in the information
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notice, this occurred because a switch which blocks the undervoltage trip signal was not
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depressed while testing the shunt trip. The operability of the undervoltage and shunt trips
was assured by other tests; only the actuation of the shunt trip by the reactor trip switch was
determined to be inadequate.
The licensee promptly reported this as a condition prohibited by technical specifications.
Because of this condition, the licensee entered Technical Specification 4.0.3, which requires
action within 24-hours. During conference calls between the licensee and NRC on April 5
and 6, the licensee described their rationale and request for enforcement discretion so that
Unit 2 could continue to operate until this revised test could be performed during the next
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refueling outage which is scheduled to begin on September 17,1993. The licensee formally
requested enforcement discretion by letter dated April 6,1993. That request was approved
verbally by NRC headquarters on April 6 and by NRC letter dated April 9,1993. This
event showed that the licensee was responsive to industry events involving the manual reactor
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trip switch. At the end of this inspection pericd, the licensee was completing their review of
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this information notice and preparing a response to an NRC request for additional
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information on the possibility of a similar situation involving the manual safety injection
switch.
8.0
ADMINISTRATIVE
8.1
Management Meeting and Media Briefm' g
Mr. Thomas T. Martin, Regional Administrator, NRC Region I, visited the site on April 22,
1993. The Regional Administrator discussed licensee performance with the inspectors,
toured the sitc, and met with site management. On April 23, the Regional Administrator
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held a media briefmg in Pittsburgh to discuss the status of nuclear power plants and other
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federally licensed users of radioactive materials in Western Pennsylvania and Western New
York. The Beaver Valley nuclear power plants were among those discussed.
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8.2
Preliminary Inspection Findings Exit
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At periodic intervals during this inspection, meetings were held with senior plant
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management to discuss licensee activities and inspector identified issues. Following
conclusion of the repon period, the resident inspector staff conducted an exit meeting on
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May 17,1993, with Beaver Valley management summarizing inspection activity and findings-
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for this period.
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8.3
Attendance at Exit Meetings Conducted by Region-Based Inspectors
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During this inspection period, the inspectors attended the following exit meetings:
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Dates
Subject
Recon No.
Insoector ..
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Inspection
Reporting
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4/08/93
Effluent and Environmental Monitoring
93-07/07
L. Peluso -
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4/09/93
AFW & Steam Line Stress Analysis
93-06/06-
J. Carrasco -
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4/16/93
Inservice Inspection
93-08/08
P. Patnaik
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4/30/93
Occupational Exposure
93-10/11
J. Nick
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6.4
NRC Staff Activities
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Inspections were conducted on both normal and backshift hours: 24.9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> of direct
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inspection were conducted on backshift; 12.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> were conducted on deep backshift. The
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times of backshift hours were adjusted weekly to assure randomness.
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Scot Greenlee, Resident Inspector, was assigned to the Beaver Valley site starting
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April 5,1993.
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R. Barkanic, Nuclear Engineer, Pennsylvania Department of Environmental Resources
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(DER) visited the site and the inspectors on May 7,1993, and discussed inspection activities:
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and the licensee's performance.
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