ML20057E833
| ML20057E833 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 09/30/1993 |
| From: | Lazarus W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20057E829 | List: |
| References | |
| 50-334-93-21, 50-412-93-22, NUDOCS 9310130212 | |
| Download: ML20057E833 (21) | |
See also: IR 05000334/1993021
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U. S. NUCLEAR REGULATORY. COMMISSION
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REGION I -
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Report Nos.
93-21
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93-22
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Docket Nos.
50-334
50-412
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License Nos.
NPF-73
Licensee:
.;Duquesne Light Company _
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One Oxford Center
301 Grant Street
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Pittsburgh, PA 15279
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Facility:
Beaver Valley Power Station, Units 1 and 2
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Location:
Shippingport, Pennsylvania-
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Inspection Period:
August 24 - September 27,1993
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Inspectors:
Lawrence W.~ Rossbach, Senior Resident Inspector L
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Peter P. Sena, Resident Inspector
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Scot- A. Greenlee, Resident Inspector
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. Richard A. Rasmussen, Reactor Engineer, RI
Gordon E. Edison, Project Manager,' NRR
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Approved by:
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W'%rdfhief, Reactor Projects Section 3B
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Inspection Summary
This inspection report documents the safety inspections conducted during day and backshift
hours of station activities in the areas of: plant operations; maintenance and surveillance;
engineering; plant support; and safety assessment / quality verification.
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9310130212 931001
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EXECUTIVE SUMMARY
Beaver Valley Power Station
Report Nos. 50-334/93-21 & 50-412/93-22
Plant Ooerations
Operators at Unit 2 completed a plant shutdown to mode 5, for the unit's fourth refueling
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outage, in a professional, competent, and safe manner. Two weaknesses were noted in plant
procedures during the shutdown.
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The licensee's scheduled Unit 2 motor operated valve testing, which would have placed one
of the emergency diesel generators out of service just prior to the refueling outage without
verifying a net safety benent. Upon further discussion with the NRC and internal review,
the licensee rescheduled the testing to the outage.
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Maintenance
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Good job site performance and oversight were observed during maintenance activities.
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Performance during all observed surveillance activities was satisfactory. On two occasions,
spurious alarms were received at Unit 2 when instrumentation and control test equipment was
installed in the plant. The licensee determined that the cause was a combination of test
equipment design and installation technique. Adequate corrective actions were taken to
prevent recurrence.
Non-outage maintenance backlog was reviewed and found to be appropriately prioritized and
managed by the licensee.
The licensee failed to perform 18 month calibrations on four gaseous effluent process flow
rate monitors. The failure to perform the calibrations is a violation (50-412/93-22-01) of
technical specifications. The cause of the violation appeared to be an inadequate tracking
system for calibration due dates.
Engineering
The licensee demonstrated excellent initiative, and good technical insight during the
investigation and resolution of two generic issues: (1) gas accumulation in the Unit I low
head safety injection piping; and (2) the possibility of high head safety injection pump run-
out during the transfer from cold leg to hot leg recirculation following a large break loss of
coolant accident.
Station modification procedures were generally found to be of good quality, except in the
case of design equivalent changes. Design equivalent change procedures were not covered in
sufficient detail.
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Executive Summary
A review of the 10 CFR 50.59 process showed that the 10 CFR 50.59 evaluations were
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thorough and indicated that the licensee was committed to the process.
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Plant Sunnort
Fifteen temporary fire seals were found in the Unit I charging pump cubicles. The seals
were installed in 1989, and were not controlled by the licensee's temporary modification
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program. The seals were evaluated as satisfactory and will be replaced with permanent seals
during the next refueling outage.
Chemistry support and corrective actions were good for a high gas concentration in the
Unit I reactor coolant system.
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TABLE OF CONTENTS
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) . . . . . . . . . . . . . . . . . . . . . . . . . .
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2.1
Operational Safety Verification . . . . . . . . . . . . . . . . . . . . . . . . . . .
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2.2
Safety System Walkdowns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
2.3
Unit 2 Pre-Outage Emergency Diesel Generator (EDG) Maintenance.
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2.4
Unit 2 Diesel Air Start Piping Configuration . . . . . . . . . . . . . . . . . . . 3
2.5
Unit 2 Shutdown for Refueling . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
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3.0
M AINTENANCE (62703, 61726, 71707)
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3.1
Maintenance Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
3.1.1 Inoperable Unit 1 Control Rod Assemblies
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3.2
Surveillance Observations
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3.3
Spurious Alarms During Surveillance Testing . . . . . . . . . . . . . . . . . . 7
3.4
Maintenance Backlog and Inoperable Unit 2 Velocity Probes
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4.0
ENGINEERING (37001, 90712, 92700, 71707, 92702)
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4.1
Review of Written Reports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
4.2
Gas Accumulation in the Unit 1 Low Head Safety Injection Piping . . . .
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4.3
10 CFR Part 21 Notification . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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(Closed) Violation (412/92-07-01) Diesel Sequencer Relay Failures . . . .
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(Closed) Violation (412/93-09-03) Missing Pipe Support Brackets . . . . .
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4.6
Review of Beaver Valley 10 CFR 50.59 Process
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5.0
PLANT SUPPORT (71707)
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5.1
Radiological Controls .
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5.2
Security . . . . . . . . . . . . . .
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5.3
Housekeeping . . . . . . . . . . . .
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5.4
Unit 1 High RCS Gas Concentration . . . . . . . . . . . . . . . . . . . . . . .
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6.0
ADMI NISTR ATI V E . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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6.1
Preliminary inspection Findings Exit
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6.2
Attendance at Exit Meetings Conducted by Region-Based Inspectors
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6.3
NRC Staff Activities
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DETAILS
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1.0
MAJOR FACILITY ACTIVITIES
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Unit 1 operated at full power throughout this inspection period without any significant
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operational events.
Unit 2 operated at full power from the beginning of this inspection period until August 29
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when end oflife coast-down began. The licensee reduced power to 75% on September 3 and
to 65% on September 10 as part of the coast-down, and to enable pre-outage maintenance on
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various secondary components. Unit 2 was shut down on September 17, as previously
scheduled, to begin the unit's fourth refueling outage. Mode 5 (cold shutdown) was entered
on September 19.
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PLANT OPERATIONS (71707,71710)
2.1
Operational Safety Verification
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Using applicable drawings and check-offlists, the inspectors independently verified safety
system operability by performing control panel and field walkdowns of the following
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systems: river water, diesel starting air, and residual heat removal. These systems were
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properly aligned; however, a difference was noted between the Unit 2 diesel starting air
system configuration and the system prints. This is discussed in more detail in Section 2.4
of this report. The inspectors observed plant operation and verified that the plant was
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operated in accordance with licensee procedures and regulatory requirements. Regular tours
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were conducted of the following plant areas:
Control Room
Safeguards Areas
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Auxiliary Buildings
Service Buildings
Switchgear Areas
Turbine Buildings
Access Control Points
Intake Structure
Protected Areas
Yard Areas
Spent Fuel Buildings
Containment Penetration Areas
Diesel Generator Buildings
Containment Building
During the course of the inspection, discussions were conducted with operators concerning
knowledge of recent changes to procedures, faciUty configuration, and plant conditions. The
inspectors verified adherence to approved procedur:s for ongoing activities obsen'ed. Shift
turnovers were witnessed and staffing requirements confirmed. The inspectors found that
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control room access was properly controlled and a professional atmosphere was maintained,
Inspectors' comments or questions resulting from these reviews were resolved by licensee
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personnel.
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Control room instruments and plant computer indications were observed for correlation
between channels and for conformance with technical specification (TS) requirements.
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 identined equipment status or de0ciencies. These records included operating
logs, turnover sheets, system safety tags, and the jumper and lifted lead book. The
inspectors also examined the condition of various fire protection, meteorological, and seismic
monitoring systems.
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2.2
Safety System Walkdowns
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The operability of the Unit I high head safety injection (HHSI) system and the Unit 2 low
head safety injection (LHSI) system was verified by performing detailed walkdowns of the
accessible portions of the systems. The inspectors conGrmed that system components were
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in the required alignment, hangers and supports are made up properly, instrumentation was
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valved in with appropriate calibration dates, as built prints reDected the as-installed system,
essential support systems were operational, and the overall material condition was
satisfactory. Specific observations are discussed below.
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Unit i HHSI
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The accessible portions of the HHSI inspected included suctions from the refueling
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water storage tank, LHSI, and emergency boration and charging pump discharge to
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the hot legs and cold legs (via the baron injection tank). No major discrepancies
were identiGed. Minor housekeeping items and valve leakage deficiencies were
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turned over to licensee personnel for resolution.
The inspector identified a 250 mR/hr hot spot (on contact) adjacent to CH-148
(charging pump IC suction isolation from LHSI). The dose rate was less than 100
mR/hr from a distance of 18 inches. This hot spot was not present one week earlier
as indicated by the licensee's last survey map of this area. Health physics toscrael
subsequently initiated proper action to adequately post this area. Follow-up surveys
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by health physics personnel in all three charging pump cubicles did not identify any
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other new radiation hot spots.
The inspector identified 15 temporary Ere seals in the charging pump cubicles (pump
suction and discharge piping penetrations). These temporary seals were installed in
1989, but were not included in the quality services unit's recently developed periodic
inspection program for temporary seals, nor were these seals controlled via the
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licensee's temporary modification program because the work orders were closed.
These seals were subsequently inspected and evaluated by engineering as being
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satisfactory. Maintenance work requests have been initiated to replaced the temporary
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seals with permanent Gre seals during the next refueling outage. The inspectors were
satisfied with the licensee's actions.
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Unit 2 LHSI
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No significant discrepancies were found. Several minor de6ciencies were turned over
to the licensee for resolution.
2.3
Unit 2 Pre-Optage Emergency Diesel Generator (EDG) Maintenance.
Duquesne Light Company scheduled motor operated valve testing on one of the Unit 2 EDG
service water valves prior to the unit's fourth refueling outage. The testing would have
required the licensee to enter a 72-hour shutdown technical specification action statement.
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This would have been necessary because all service water would have been isolated from the
EDG in order to test the valve.
The inspectors asked Duquesne Light Company to explain the safety benefit associated with
doing the testing prior to the outage. The licensee explained that they wanted to perform the
test prior to the outage primarily because of outage scheduling conflicts. Duquesne Light
Company was reminded of the NRC's position that performance of preventive maintenance
on-line, rather than during shutdown, should improve safety by making equipment more
reliable, and should be warranted by operational necessity, not just by the convenience of
shortening a refueling outage. Moreover, the licensee should be able to justify such an
expectation of improved safety. Duquesne Light Company subsequently rescheduled the
testing to the refueling outage.
2.4
Unit 2 Diesel Air Start Piping Configuration
During a routine walkdown of the Unit 2 diesel air start system, the inspectors determined
that the system configuration was not as shown on the system diagram, and not as described
in the plant operating manual. The difference involved piping which supplies air to boost the
fuel racks during diesel startup. During a normal diesel start, air pressure boosts open the
fuel racks to provide adequate fuel for starting. The Beaver Valley system diagram shows
that air for the fuel rack boost is supplied from a point just downstream of the main air start
valves. The actual con 6guration is such that the air comes from downstream of the air start
solenoid valves. The air start solenoid valves supply air which opens the main air start
valves on diesel start signal.
This difference in con 6guration only has implications in the event of a local manual start. If
the diesel fails to start because the air start solenoid valves will not open (e.g., during a loss
of 125 V d.c. control power), the operators are trained to start the unit manually, by opening
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one of the main air start valves. The system print configuration showed that the fuel racks
would get boost air if a main air start valve was opened manually. The actual configuration
would not allow for boost air on a manual start.
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The licensee contacted the diesel vendor (Colt) about the diesel air start piping configuration.
The licensee was told that the piping design configuration was changed back in the late 1970s
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because of overspeed concerns, and was delivered to the site that way. The vendor also
stated that the governor should build up enough oil pressure to open the fuel racks on a
manual diesel start; however, the start would be slower than a start with boost air.
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Duquesne Light Company is going to change their documentation to reflect the current air
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start piping configuration.
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2.5
Unit 2 Shutdown for Refueling
On September 17, 1993, Dnquesne Light Company started a Unit 2 shutdown for the plant's
fourth refueling outage. Th; shutdown started from approximately 65 percent power at
7:10 p.m. The unit entered Mode 5 at approximately 12:35 a.m. on September 19.
The inspectors observed a significant part of the plant shutdown and cooldown. The
operators completed the rea; tor plant mode changes in a professional, competent and safe
manner. This included hardling several minor problems, such as a failed source range
nuclear instrument, a feedv ater regulating valve which did not fully close, and a blocked
residual heat removal system sample line. The nuclear shift foreman also noted a problem
with Abnormal Operating Procedure (AOP) 2.2.1, " Nuclear Instrumentation Malfunction."
The AOP was not consistent with the technical specification actions for a failed source range
nuclear instrument channel. The Operations Manager initiated actions to resolve the AOP
deficiency.
3.0
M AINTENANCE (62703, 61726, 71707)
3.1
Maintenance Observations
The inspectors observed and reviewed selected maintenance activities to assure that: the
activity did not violate Technical Specification Limiting Conditions for Operation and that
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redundant components were operable; required approvals and releases had been obtained
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prior to commencing work; procedures used for the task were adequate and work was within
the 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.
The maintenance work requests (MWRs) and preventive maintenance procedures (PMPs)
listed below were reviewed. The observed activities were properly conducted without any
notable deficiencies unless otherwise indicated.
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MWR 022427
In-plant Computer Input Verification
MWR 023095
Rod Control Troubleshooting (see Section 3.1.1)
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MWR 011732
Charging Pump (CH-P-1B) Alignment
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PMP 018526
Charging Pump (CH-P-1 A) Bearing Inspection
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During the 'A' charging pump inboard bearing inspection, the bearing clearances were found
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to be out of speci6 cation (>.006 inches) using plastigage measurement. Subsequent
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micrometer readings of the bearing sleeve inner diameter and shaft outer diameter were
within specification. Thorough action was initiated by maintenance supervision to resolve
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this discrepancy. This included coctacting the vendor for additional guidance, performing a
blue check of the bearing sleeve seating surface, and plastigage measurements between the
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bearing housing and bearing sleeve. The bearing was subsequently replaced and tested
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satisfactorily. The inspector also noted proper foreign material exclusion controls practiced
by the workers. During the 'B' charging pump alignment, good on-site job support and
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oversight were provided by the maintenance foreman. This exacting process was
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methodically completed by the workers and resulted in a satisfactory vertical and horizontal
alignment.
MWR 020395
Replace low Head Safety Injection (LHSI) Pump P21 A Inboard and
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Outboard Seals
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The inspectors noted good job site performance and supervision during the replacement of
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the LHSI pump mechanical seals. Quality control and radiological controls coverage were
also good. Some minor problems were noted with the seal replacement procedure
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(2 CMP-llSIS-P-21 A-B-lM, " Low Head Safety Injection Pump Overhaul"). Some of the
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procedural steps and illustrations did not rc6cct the actual conGguration of the pump. The
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licensee identified and corrected most of the deficiencies by issuing a revision to the
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procedure prior to the start of the job. Another procedure deficiency, involving pump
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bearing configuration, was identified during the job, and was within the skill of the craft to
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work through using the technical manual. The licensee is pursuing a procedure change to
reflect the correct bearing con 6guration. The procedure was a product of the licensee's
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procedure upgrade process, but the quality was not typical of their upgraded maintenance
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procedures.
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3.1.1 Inoperable Unit 1 Control Rod Assemblies
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On September 18, 1993, during monthly control rod movement testing, two sets of rod banks
failed to move on demand. Speci6cally, shutdown bank 'A' (group 2) and control bank 'C'
(group 2) would not step in or out while in manual control. There was no indication of rod
movement by either the analog rod position indication or primary voltage changes. All other
rod banks tested satisfactorily. At the time of this incident, these eight rods were in the fully
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withdrawn position. At 12:45 p.m., the shift supervisor declared these rods inoperable and
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correctly applied Technical Speci6 cation 3.1.3.1. Per the technical specifications, it is
incumbent upon the plant to verify the trippability of the inoperable control rods within I
hour. If the trippability of the inoperable rods could not be veri 6ed, then emergency
boration would be required since the technical specification shutdown margin would not be
satis 6ed.
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Immediate assistance was provided by the instrumentation and controls (I&C) department for
troubleshooting of the rod control system. The inspectors observed these efforts and at 1:38
p.m., the I&C foreman identified a control system failure. The bank select in power cabinet
'2AC' was determined to be electrically stuck in the control bank 'A' position. Thus, when
either shutdown bank 'A' or control bank 'C' was selected by the reactor operator. control
bank 'A' rods would respond to the demand signals. The inspector concluded that the
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licensee's determination that the rods were trippable was appropriate. Multiplexing relay
MXR1 was replaced per MWR 023095 to allow for proper bank selection. The operability
of the rods was restored by 3:55 p.m. following successful surveillance testing. However,
on September 20, I&C personnel identified that power cabinet '2AC' had again incorrectly
selected control bank 'A'.
This identification was a result of I&C personnel attempting to
determine the root cause of MXR1 relay being electronically stuck. I&C identi6ed that a
signal conditioning card, which provides input to MXR1, had failed. This card has been
replaced and the rods returned to operable status. The licensee has shipped the failed card to
Westinghouse for further evaluation.
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Overall, the I&C foreman demonstrated excellent system knowledge and good
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troubleshooting efforts to diagnose the failure during the limited time constraints. These
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efforts by the I&C foreman in verifying the trippability of the rods is commendable, as it
averted the need for an emergency boration. Good follow-up action by the I&C director,'per
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root-cause analysis, resulted in the identi6 cation of the rods again being inoperable and the
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initiation of proper corrective action.
3.2
Surveillance Observations
The inspectors witnessed / reviewed selected surveillance tests to determine whether properly
approved procedures were in use, details were adequate, test instrumentation 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) and Beaver Valley Tests (BVTs)
listed below were reviewed. The observed surveillance activities were properly conducted
without any notable deficiencies unless otherwise indicated.
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Boric Acid Transfer Pump (1CH-P-28) Operational Test
IOST-7.5
Centrifugal Charging Pump (ICH-P-1B) Test
LOST-36.1
Diesel Generator No.1 Monthly Test
IOST-24.4
Turbine Driven Auxiliary Feed Pump Test (lFW-P-2)
During OST 24.4, the auxiliary feedwater (AFW) system engineer initiated the use of
visicorder instrumentation for enhanced monitoring of the turbine governor based on past
industry experience. The parameters specifically monitored are turbnx speed, governor
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valve position, and pump discharge pressure. The inspectors considered this a good practice
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to monitor governor performance and ensure high reliability. Also during this surveillance
test, the inspectors noted boric acid buildup on the piping Dange for auxiliary feedwater flow
transmitter FT-FW-100B. A boron concentration of between 5 and 10 ppm is maintained in
the steam generators. Although this concentration is minimal, deposits of boric acid crystals
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are highly concentrated and may be very corrosive for carbon steel. A deficiency tag was
previously hung to identify the leak and generate a work request. However, the boric acid
buildup was not identi6ed for prompt cleanup to minimize its corrosive effects.
IBVT 8.3.1
Incore Movable Detector Flux Mapping
The reactor engineers demonstrated excellent knowledge of the flux mapping procedure and
equipment. During the procedure, the 'C' incore detector acted erratically. The reactor
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engineers quickly identified the faulty incore detector. Maintenance personnel promptly
responded to check the accessible portion of the equipment. After a brief evaluation, the
reactor engineers decided to continue the map using another detector via the emergency path.
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The reactor engineers ensured the requirements of Technical Specification 3.3.3.2, regarding
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the maximum number of faulty detector thimbles, were met. The procedure was well written
with good use of prerequisites, precautions, contingencies and notes.
OST 2.24.2
Motor Driven Auxiliary Feed Pump 2FWE*P23A
2BVT 1.21.2
Trevitest Method for Main Steam Safety Valve Setpoint Check
2BVT 1.11.3
SI Accumulator Discharge Check Valves Full StroM Tat
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2OST1.1
Control Rod Assembly Partial Movement Test
2OST 2.11.1
Imw Head Safety injection Pump [2 SIS *P21 A] Test
2OST 2.36.15
4 kV and 480 V Emergency Bus Undervoltage Test
OST 2.42.2
Shutdown Margin Calculation
OST 2.2.3
Nuclear Source Range Channel Functional Test
3.3
Spurious Alarms During Surveillance Testing
On September 1 and 2,1993. Unit 2 operators received spurious alarms during
instrumentation and control equipment surveillance testing. The spurious alarms were not
functionally related to the equipment being tested. The licensee conducted an investigation
into the events. They found that the same individual was involved in both occurrences, and
the cause was a combination of test equipment design and installation technique. Some test
equipment connectors were configured such that they could easily short across the pins of the
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mating connector. Shorting across mating connector pins while installing the test equipment
caused the spurious alarms. The mating connectors are mounted on circuit cards which are
used only during testing.
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The licensee modified the test connectors to reduce the possibility of shorting the mating
connector pins during installation. Additionally, the events were discussed with all
instrumentation and control personnel who use the associated test equipment. The inspectors
concluded that there was no safety consequence associated with the two events, and the
licensee's actions in response to the events were appropriate.
3.4
Maintenance Backlog and Inoperable Unit 2 Velocity Probes
The inspectors reviewed the Unit 1 and Unit 2 non-outage maintenance backlog to ensure
that safety related maintenance activities were being appropriately prioritired and managed by
the licensee. The inspectors found that, overall, maintenance backlog management was
adequate. The inspectors did note a problem involving technical specification (TS) required
calibrations. A maintenance work request (MWR) was generated to calibrate two Unit 2
ventilation stack velocity probes. The velocity probes were used to measure process flow
rate from the condensate polishing building and waste gas storage vault ventilation systems.
The probes must be calibrated at least once every 18 months according to Technical Specification 4.3.3.10, " Radioactive Gaseous Effluent Monitoring Instrumentation
Surveillance Requirements." The MWR to calibrate the probes was more than 3 months old
at the time of the inspection, so the inspectors asked when the calibrations were due. The
licensee subsequently found that both probes were past due for calibration (including the 25
percent maximum extension allowed by TS 4.0.2). Condensate polishing building ventilation
probe was last calibrated on May 15, 1990; and, the waste gas storage vault ventilation probe
was last calibrated on June 6,1990. The licensee promptly declared the velocity probes out
of service, and commenced estimating process flow for the associated discharge paths every
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4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> as required by TS.
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The inspectors reviewed the circumstances associated with the licensee's failure to calibrate
the velocity probes. The inspectors found that the licensee did not have a formal system to
track ventilation system velocity probe calibration due dates. Additionally, some of the
personnel responsible for scheduling the calibrations thought the quarterly channel functional
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tests were meeting the 18-month calibration requirements.
The licensee looked at the calibration status for all velocity probes at Unit I and Unit 2.
They found the following additional problems:
(1)
The Unit 2 elevated release process flow rate monitor was past due for calibration
(last performed on March 30, 1989) from February 15, 1991, to April 20,1993.
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(2)
The Unit 2 plant ventilation system process flow rate monitor was past due for
calibration (last performed on April 1,1989) during the period from February 17,
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1991, to April 30, 1993.
The failure to calibrate the four Unit 2 velocity probes as required by TS, without taking
appropriate compensatory measures, is considered a violation (50-412/93-22-01). Unit 2 has
a total of five ventilation system velocity probes which have TS requirements. Four of the
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probes were discussed above. The fifth probe is used for monitoring ventilation How from
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the decontamination building. This probe had not been calibrated since August 17, 1990;
however, the decontamination building ventilation fans had been on clearance since October
16, 1991. TS do not require the gaseous release monitoring systems to be operable if
process flow is not present.
The licensee was able to conservatively calculate releases via the four active release paths
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during the period when the flow rate monitors were past due for calibration. The licensee
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does not use the actual process flow rate in their calculations. Instead, they use the
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maximum achievtle flow rate for the system.
4.0
ENGINEERING (37001, 90712, 92700, 71707, 92702)
4.1
Review of Written Reports
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The inspectors reviewed Licensee Event Reports (LERs) and other reports submitted to the
NRC to verify that the details of the events were clearly reported, including accuracy of the
description of cause and adequacy of corrective action. The inspectors determined whether
further information was required from the licensee, whether generic implications were
indicated, and whether the event warranted further onsite followup. The following LERs
were reviewed:
Unit 1:
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93-12 Plant Entry into Mode 2 with an inoperable Hydrogen Analyzer
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This event was discussed in NRC Inspection Report 93-16.
Unit 2:
93-08 Engineered Safety Feature Actuation Due to Loss of Emergency Response Facility
Substation
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This event was discussed in NRC Inspection Report 50-412/93-17.
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The above LERs were reviewed with respect to the requirements of 10 CFR 50.73 and the
guidance provided in NUREG 1022. Generally, the LERs were found to be of high quality
with good documentation of event analyses, root cause determinations, and corrective
actions.
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4.2
Gas Accumulation in the Unit 1 Low Head Safety injection Piping
The licensee had identified the presence of undissolved gas in the 'A' train low head safety
ujection (LHSI) piping. This identification was a result of the licensee's review of
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Information Notice 88-23, Supplement 4 (dated December 18,1992), " Potential for Gas
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Binding of High Pressure Safety injection Pumps During a Design Basis Accident." The
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information notice discussed the principle gas source as being from reactor coolant that leaks
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past the reactor coolant system cold leg check valves into the LHSI piping which
depressurizes and cools so that gases come out of the solution.
Ultrasonic examination of the LHSI piping identified about 2.2 cubic feet of gas in the
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recirculation mode transfer piping (i.e., charging pump suction from LHSI pumps). This
amount is minimal compared to the 108 cubic feet discussed in the information notice. .An
engineering evaluation concluded that these gases would not effect the operability of the high
head safety injection pumps. The gas void would be compressed by about 50 percent due to
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the discharge pressure of the LHSI pumps. An evaluation of the fluid dynamics of this
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two-phase flow concluded that the gas void would be broken down into smaller voids (less
than f inch in diameter) prior to entering the charging pump suction. The maximum
allowable gas void has been defined as 8.1 cubic feet based on the engineering evaluation.
The inspectors also reviewed the inservice testing results of the cold leg check valves
(SI-10, 11, 12, 23, 24, 25) and noted that all valves exhibited zero leakage on May 29,
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1993. Follow-up monitoring of the LHSI piping has not identified any increase in the size of
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the gas void. Thus, it is possible that the gac void may be due to an improper fill and vent
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of the LHSI piping following the recent refueling outage as opposed to check valve leakage.
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The licensee is appropriately planning to continue monitoring the gas void. Contingency
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plans are available to vent the piping if needed. Overall, engineering personnel initiated
proper action in response to the information notice. The engineering evaluation was
thorough and con e sufficient basis for its conclusions.
4.3
10 CFR Part 21 Notification
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On September 10,1993, the licensee notified the NRC of a 10 CFR Part 21 issue regarding
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a possible run-out condition of the charging pumps under a specific condition. Previously,
on July 14, Duquesne Light Company received a Westinghouse nuclear safety advisory letter
(NSAL 93-12) for evaluation of 10 CFR Part 21 applicability. For Unit 1, the licensec
determined that following a large break loss of coolant accident (LOCA), a rtm-out condition
of a single high head safety injection (HHSI) pump could occur during the transfer to hot leg
recirculation. Emergency operating procedure ES 1.4, transfer to simultaneous hot leg and
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cold leg recirculation, is entered 14.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after the LOCA. This procedure directs
operators to initiate hot leg injection from the HHSI pumps, isolate the boron injection tank,
then isolate cold let injection from the HHSI pumps. The low head safety injection (LHSI)
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pumps remain lined up to supply both the HHSI pumps and cold leg injection. If a loss of
train 'A' power is proposed as the single active failure, then the remaining 'B' HHSI pump
would be aligned for both hot leg and cold leg recirculation since the cold leg injection could
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not be isolated via its motor operated valve. Continued operation of the remaining HHSI
pump in this parallel flowpath will lead to pump run-out conditions. Manual operator action
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to locally close the affected motor operated valves is not taken credit for, since these valves
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would be in a high radiation area due to containment sump recirculation.
As corrective action to prevent this condition, the licensee has changed ES 1.4 to alert
operators not to establish hot leg injection if the boron tank cannot be isolated (i.e., no
power available to train 'A' isolation valves). Instead, operators are instructed to consult the
technical support center. However, hot leg injection is still necessary to elimi7 ate boron
precipitation in the reactor vessel and thus maintain long-term core cooling. Thus, long-term
corrective actions are under development to establish LHSI hot leg injection or throttle the
HHSI pump discharge valves to prevent run out during simultaneous hot leg and cold leg
injection. The Unit 1 Operations Manager has delineated the change to ES 1.4 in the night
order book and has required all operators to read and understand this procedure change.
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The 10 CFR Part 21 notification also stated that Unit 2 was susceptible to the same pump
run-out condition as Unit 1. This, however, was only a very remote possibility. The
emergency procedures at Unit 2 required the operators to secure the HHSI pumps prior to
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changing the valve lineup from cold leg to hot leg recirculation. The HHSI pumps would
then be restarted after the lineup change was complete. Consequently, the only way to
establish parallel injection paths with the HHSI pumps running, was to deviate from the
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emergency procedures. The Unit 2 emergency procedures were changed to give the
operators specific guidance for problems encountered while shifting from cold leg to hot
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recirculation (because of a loss of power to one train).
The inspectors were satisfied with the licensee's immediate corrective actions. Duquesne
Light Company was the first utility to report this 10 CFR Pan 21 concern to the NRC. This
action is indicative of the licensee's continued proactive approach toward review of generic
issues. The timeliness of the licensee's review was acceptable, as it was completed within
the 10 CFR Part 21 criteria.
4.4
(Closed) Violation (412/92-07-01) Diesel Sequencer Relay Failures
The licensee was issued a notice of violation on June 17, 1992, which involved the failure to
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establish adequate design control measures for verifying the adequacy of a vendor-
recommended change to emergency diesel sequencer relays. The vendor-recommended
change resulted in the application of excessive voltage across the sequencer circuitry and
subsequent relay failures. This change was different than the qualified design configuration.
The vendor, in this case. was not a 10 CFR 50, Appendix B vendor as the relays were
purchased as commercial grade items.
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The inspector reviewed the adequacy and completeness of the licensee's long-term corrective
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action to prevent recurrence. The licensee has improved procedures on meeting
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documentation requirements where verbal input from vendors is used as the basis for any
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technical decision or modification. Engineering procedures for design change control,
engineering speci6 cations, and design verifications have been updated to include the
following:
Changes to vendor supplied designs should be evaluated to ensure that quali6 cation
testing is appropriate for the modified design, including commercial grade equipment
procured for Quality Assurance Category I applications.
Changes to vendor supplied designs made with the vendor's concurrence must be
documented with a confirmation letter sent to the vendor.
Training of engineering personnel on these issues has been completed.
The licensee also performed a review of design change packages involving Class lE
electrical equipment (of the last 5 years). No deviations from the qualified design
configuration were identified. Several deficiencies were, however, identified which involved
the lack of commercial-grade dedication or quality documentation. The scope of this review
was sufficient as evidenced by licensee identi6 cation of quality deficiencies. The noteworthy
examples involving commercial grade items installed in Class 1E equipment include:
two breakers which provide 480 V AC input to the four uninterruptible power supply
(UPS) units;
static switches which transfer 120 V AC vital bus power supplies between the normal
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(UPS) and the alternate supply (480/120 V AC voltage regulator); and
two 120 V AC vital bus breakers which supply both trains of the inadequate core
cooling instrumentation system.
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The static switches have been replaced and design changes have been initiated to correct the
other deficiencies. The inspectors did note, however, ths.t a timely documented basis for
continued operability (BCO) was not prepared when these issues were Crst identified in
December 1992. Generic Letter 91-18 states that the licensee should make an operability
determination and take follow-up corrective action upon the discovery of non-conforming
conditions where the qualification of equipment is called into question. Furthermore, the
concepts of operability and restoration of qualification should be treated separately to ensure
that the operability determination is focused on safety and is not delayed by the decisions or
actions necessary to plan or implement the corrective action (i.e., restoring ful1
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qualification). At the end of this report period, the formal BCO was being finalized. The
licensee's Manager of Nuclear Safety indicated that additional training would be conducted
on this concept to improve their applications of Generic Letter 91-18. Overall, the inspectors
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were satisfied with the licensee's corrective actions to prevent recurrence in response to the
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madequate design control measures. This violation is closed.
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4.5
(Closed) Violation (412/93-09-03) Missing Pipe Support Brackets
On May 25,1993, the licensee was issued a violation for inappropriate corrective actions
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associated with a missing pipe support bracket on the 21B high head safety injection pump
lube oil system. The licensee allowed the deDeient condition to exist from October 29,
1992, until April 15, 1993, when a similar condition was identified by the NRC.
The licensee concluded that the missing bracket was not corrected in a timely manner
because ofimproper coding of the maintenance work request (MWR), and failure by
personnel reviewing the MWR to identify the error. The deficiency was coded for a
miscellaneous system instead of the safety injection system. The licensee reviewed the MWR
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control program and concluded that adequate provisions were available to identify the
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improper coding, if the provisions were followed. Thus, the licensee's actions to prevent
recurrence were: (1) to reemphasize proper review of MWRs; and (2) to schedule training
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to reenforce the need for accurate identification and reporting of degraded and
nonconforming conditions.
The inspectors reviewed the licensee's non-outage maintenance backlog for evidence of other
improperly dispositioned deficiencies. No other instances were found. The inspectors
concluded that the licensee's corrective actions to prevent recurrence were adequate. This
violation is closed.
4.6
Review of Beaver Valley 10 CFR 50.59 Process
The licensee's procedures for controlling modifications at both units, the training records
related to training of their staff in the requirements of 10 CFR Part 50.59, logs of setpoint
changes and temporary modi 6 cations, and several modification packages including the
associated safety evaluations were reviewed.
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The licensee's station modi 6 cations are organized into three categories: design changes,
design equivalent changes, and administrative changes. Design changes include major
modifications, minor modi 6 cations, setpoint changes, temporary modiDeations and computer
system changes. Design equivalent changes are intended to include changes to structures,
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systems or components for which design requirements remain unchanged. Administrative
changes include UFSAR updates, technical specification changes, and other changes to
documents such as operating procedures, valve lists or administrative changes to drawings.
With the exception of design equivalent changes (DECs), all of these changes are controlled
with approved procedures which are generally of good quality. Some guidance for handling
DECs is included in Figure 6.4 of Nuclear Engineering Administrative Procedure 2.13,
whose stated purpose is to control the preparation and processing of technical evaluation
reports. However, there is no procedure to identify purpose, applicability, responsibilities,
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references, and to organize and detail restrictions, instructions and requirements for design
equivalent changes.
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The 10 CFR 50.59 training program was revamped in mid-1990 because of problems with
earlier 10 CFR 50.59 evaluations and resulting pressure from the Onsite Safety Committee
(OSC). This demonstrated good internal self-monitoring and a commitment to the 10 CFR 50.59 process. Training records indicated that about 150 persons rnaintained their 10 CFR 50.59 training current (within the past 2 years) and another 100 persons had completed initial
or partial training since mid 1990. All members of the engineering assurance group, which
performs most of the 10 CFR 50.59 evaluations for major modifications, had received
training within the past year. Two out of three persons who perform a similar function for
most tech spec changes also were current in their training. The licensee also stated that
Onsite Safety Committee (OSC) and Offsite Review Committee (ORC) managers involved in
10 CFR 50.59 program oversight and managers who oversee no significant hazards
evaluations received 10 CFR 50.59 training through the Technical Personnel Training
program.
Logs were being properly maintained in the control room for setpoint changes and for
temporary modifications (TMODs) including jumper connections and lifted leads. These logs
were found to be updated, reviewed on a quarterly basis, and the number of temporary
modifications is trended. A significant reduction in the number of outstanding TMODs
occurred during 1992 at both units.
The following operational surveillance test procedure changes, TMODs, and design change
packages were reviewed:
OST 1.39.l A, Rev 33,11/1/90,10 CFR Part 50.59 Evaluation, Unit 1, Weekly Station
Battery Check, Battery No.1.
TMOD l-90-026,3/10/88, Install Temporary Power Supply for Betz Equipment to Cooling
Tower (Unit 1).
TMOD l-90-017,4/13/89, Remove Internals from Check Valve AS-7 (Unit 1)
TMOD 2-90-31,6/2/88, Maintain on-line the Circulation Water Pumps During a Chilled
Water Low-Temperature Trip (Unit 2)
TMOD 2-90-53,2/10/89, Modification to the Unit 2 Control Building Ventilation Filters
DCP No.1546, Rev. O,1/14/91, Replacement of Station Air Compressors (Unit 1)
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DCP No.1377, Rev. O,5/13/90, Auxiliary Feedwater System Design Pressure Change
(Unit 2)
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The 10 CFR 50.59 evaluations were thorough and indicated the licensee is committed to the
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10 CFR 50.59 process.
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5.0
PLANT SUPPORT (71707)
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5.1
Radiological Controls
Posting and control of radiation and high radiation areas were inspected. Radiation work
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permit compliance and use of personnel monitoring devices were checked. ' Conditions of
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step-off pads, disposal of protective clothing, radiation control job coverage, area monitor
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operability and calibration (portable and permanent), and personnel frisking were observed
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on a sampling basis. Licensee personnel were observed to be properly implementing their
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radiological protection program.
5.2
Security
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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
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delivered to the protected area were properly searched and access control was in accordance
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with approved licensee procedures; persons granted access to the site were badged to indicate
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whether they have unescorted access or escorted authoriration; security access controls to
vital areas were maintained and persons in vital areas were authorized; security posts were
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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
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was maintained. Licensee personnel were observed to be properly implementing and
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following the Physical Security Plan.
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5.3
Ilousekeeping
Plant housekeeping controls were monitored, including control and storage of flammable
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material and other potential safety hazards. The inspectors conducted detailed walkdowns of
accessible areas of both Unit I and Unit 2. Housekeeping at both units was acceptable.
5.4
Unit 1 Iligh RCS Gas Concentration
On August 24,1993, routine chemistry sampling identined a high total gas concentration in
the reactor coolant system (RCS) in excess of 60 cc/kg. The gas was mainly comprised of
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dissolved hydrogen and possibly ammonia. The licensee maintains the specifications for
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dissolved hydrogen between 25 - 50 cc/kg. The upper limit is based on limiting primary
water stress corrosion cracking ofInconel 600 steam generator tubing. Degasification of the
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RCS was initiated per the recommendation of the chemistry staff. The RCS gas
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concentration was successfully reduced to 40.9 cc/kg following 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> of degasification.
Licensee investigation revealed that argon activity had doubled on August 24. This is an
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excellent indicator of air intrusion into the RCS. The licensee believes it is possible that air
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may have been introduced while returning the chemical volume and control system to service
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following maintenance. Mixed bed demineralizer CH-I-1 A was drained between August 8
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and 20 to allow for maintenance on isolation valve CH-9. Overall, the chemistry personnel
conducted a thorough investigation and initiated proper action to restore RCS gas
concentration to within specification.
6.0
ADMINISTRATIVE
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6.1
Preliminary Inspection Findings Exit
At periodic intervals during this inspection, meetings were held with senior plant
management to discuss licensee activities and inspector areas of concern. Following
conclusion of the report period, the resident inspector staff conducted an exit meeting on
September 28, 1993, with Beaver Valley management summarizing inspection activity and
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findings for this period.
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6.2
Attendance at Exit Meetings Conducted by Region-Based Inspectors
During this inspection period, the inspectors attended the following exit meetings:
Inspection
Reporting
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Dates
Subject
Report No.
Inspector
8/26/93
Unit 1 Licensed Operator Requal Exams 93-19
R. Temps
9/03/93
Station Blackout Rule Implementation
93-80/80
J. Trapp
9/10/93
Emergency Preparedness Program
93-20/20
L. Eckert
6.3
NRC Staff Activities
Inspections were conducted on both normal and backshift hours: 48.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> of direct
inspection were conducted on backshift; 28.1 hours1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> were conducted on deep backshift. The
times of backshift hours were adjusted weekly to assure randomness.
R. Barkanic, Pennsylvania Department of Environmental Resources, and T. Reeves, Ohio
Emergency Management Agency, visited the site and the inspectors on September 7 and 8 to
accompany the emergency preparedness program inspection.
G. Edison, Project Manager, Nuclear Reactor Regulation (NRR), visited the site and the
inspectors from August 23 to 27 to evaluate the licensce's 10 CFR 50.59 activities as
discussed in Section 4.6.
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Four East Europeans visited the inspectors to become familiar with the NRC inspection
program. Gyula Fichtinger, Atomic Energy Commission, Hungary, and Yordan Hari7anov,
Committee on Uses of Atomic Energy for Peaceful Purposes, Bulgaria, visited the inspectors
from August 23 to September 2. Milan Musak, State Office of Nuclear Safety, C7ech
Republic, and Miroslav Lipar, Nuclear Safety Authority, Slovak Republic, visited the
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inspectors from August 30 to September 2. The visitors toured the site and discussed the
inspection program with the inspectors. The visitors also accompanied the inspectors on
inspections 50-334/93-19,21, and 80 and also 50-412/93-22 and 80.
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