ML20057E291
| ML20057E291 | |
| Person / Time | |
|---|---|
| Site: | Wolf Creek  |
| Issue date: | 10/04/1993 |
| From: | Barnes I, Wagner P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20057E288 | List: |
| References | |
| 50-482-93-21, NUDOCS 9310080291 | |
| Download: ML20057E291 (29) | |
See also: IR 05000482/1993021
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APPENDIX C
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U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection Report:
50-482/93-21
License: NPF-42
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licensee: Wolf Creek Nuclear Operating Corporat',on
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P.O. Box 411
Burlington, Kansas
Facility Name: Wolf Creek Generating Station
Inspection At: Burlington, Kansas and Arlington, Texas
Inspection Conducted: August 9-13 and 23-27, 1993, Onsite
August 16-20, 1993, Inoffice
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Team Leader:
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jf27/93
Philip C. Wagner, Tean) Leader, Division of
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Reactor Safety
Team Members:
H. Bundy, Reactor Inspector
P. Goldberg, Reactor Inspector
C. Paulk, Reactor Inspector
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M. Satorius, Project Engineer
W. Reckley, Project Manager
J. Whittemore, Reactor Inspector
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Approved:
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darnes,' Acting Deputy Director
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g Di ision of Reactor Safety
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EXECUTIVE SUMMARY
An announced team inspection of the licensee's corrective action programs was
conducted from August 9-27, 1993.
The inspection was performance based and
focused on the products of the licensee's efforts. The team reviewed
corrective action documents and interviewed facility personnel during the
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inspection.
Plant tours and walkdowns were conducted to observe the material
condition of systems and components.
The team also evaluated the licensee's
actions in response to previously identified inspection findings and reported
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events.
The team used the guidance contained in Inspection Procedure 92720,
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" Corrective Action," while performing the inspection.
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The licensee conducted a quality assurance audit of the corrective action
programs in May 1993 and identified a continued reluctance on the part of some
employees to initiate corrective action documentation. This problem resulted
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in a revision to the procedure for performance improvement requests. However,
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the team had indications that some problems continued to persist. For
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example, some interviewed employees stated that the process had gotten better
but others may still feel that initiating a document could lead to
disciplinary action.
(No one indicated that he or she felt that way, but
others may.) The team was also informed that a supervisor had recently
instructed a worker not to initiate performance improvement requests.
Therefore, the team determined that this area warrants continued management
emphasis.
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The team noted that the requirement to complete a root cause determination and
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a corrective action plan within 30 days had been removed in the recent
revision to the performance improvement request procedure. The team also
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noted that corrective action due dates were initially established and
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routinely extended without a documented justification or a technical basis.
This practice could lead to misleading trending information and result in
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untimely implementation of corrective actions.
Another concern identified during the inspection was the adequacy of the
documentation.
In many cases, adequate actions had been conducted, but the
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record did not reflect those actions. An effective corrective action program
requires a good written record of problems that have been identified, and the
actions taken to resolve the problems, to properly track and trend issues.
During the inspection the team noted attributes that indicated a good
corrective action program. The team also identified the following problems:
There have been several long standing issues related to relief valves
that have not been resolved. This issue will be further evaluated in a
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followup inspection.
The team determined that plant records were not being stored in
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accordance with the USAR commitment to ANSI N45.2.9.
The present
storage of records had also been identified as unacceptable in licensee
initiated performance improvement requests, however, corrective actions
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had not been initiated. This issue was determined to be a deviation
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from an NRC commitment.
The team identified the following examples of inadequate corrective
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Residual heat removal system relief valves have experienced seven
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bellows failures since 1984.
This was a concern because of the lack of timeliness in resolving
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the problem and the apparent lack of a thorough evaluation of the
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causes and consequences of the problem.
Flow Transmitters Drawing Differences - A problem with the model
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number of four flow transmitters was identified on August 1,1992,
and assigned to engineering on September 1, 1992, but no action
was initiated until this inspection.
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This issue was a concern because of the lack of timely resolution
of a problem.
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Instrument Tubing Ovality - A performance improvement request was
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initiated on July 10, 1991, but no action was undertaken until
June 3, 1993.
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This was another example of untimely resolution of an identified
problem.
The team identified a procedural violation related to a valve that had
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been stuck in the mid position since 1991.
The plant winterization
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procedure required the valve to be opened in the fall and closed in the
spring. The procedure had been implemented without mention that the
valve was not properly positioned.
This problem was a concern for two reasons.
First, the valve had been
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inoperable for over 2 years and no action had been taken to correct the
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problem. The second concern was the failure to notice that the valve
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was stuck ir the mid position during system alignments. This later
concern 0
Tted a lack of a questioning attitude on the part of the
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operators
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team also noted that the determination of valve
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operability
w of system operability with an inoperable valve were not
made until those questions were raised by the NRC team.
A violation was identified that involved procedure. acceptance criteria
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not being met and not reported. The procedure was written to ensure
adequate free play in the check valve for cooling water from the
instrument air compressors.
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This violation was a concern because of the quality of the instructions
and because the involved check valves had experienced multiple failures
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in the past 12 months with inadequate action taken to correct the
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problem.
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The team reviewed selected quality assurance audits and surveillances and
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found them to be of appropriate scope and depth.
These self-assessment
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efforts identified substantive issues that were usually adequately resolved.
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However, some issues may warrant further management involvement to. ensure
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timely resolution.
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The team found the material condition of the facility to be generally good.
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The safety-related batteries condition was excellent but the team observed.
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that the nonsafety-related batteries did not receive the same level of
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attention.
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The team concluded that the corrective action program provided an acceptable
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framework. Although improvement was detected, the program implementation'had
not progressed as far as expected considering the emphasis that the program
had received over the past 2 years.
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DETAILS
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INTRODUCTION
A team of NRC personnel conducted an integrated evaluation of the licensee's
corrective action programs. The team evaluated the licensee's identification,
evaluation, and correction processes for facility problems.
The team also
reviewed selected open items and licensee event reports. The team used a
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performance-based approach in evaluating the effectiveness of the licensee's
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programs.
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The inspection included hardware, software, and personnel related problems.
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The team utilized documentation reviews, personnel interviews, and direct
observations to evaluate the licensee's programs.
2 WORK REQUEST (WR) REVIEWS (92720)
2.1
Items Inspected
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The licensee utilized the WR to document and disposition hardware problems.
The team reviewed 133 WRs. An initial sample of 54 WRs was selected from a
listing of open and closed items that was provided by the licensee before the
inspection.
Additional selections were based on the review of the initial
sample and other documentation. The licensee's evaluations and corrective
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actions were scrutinized for adequacy and timeliness.
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2.2 Findings
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2.2.1
Poor Documentation
The team reviewed WR 2815-93, initiated on April 24, 1993, concerning
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emergency diesel generator starting Air Relief Valve, KJV0716A. The valve
relieved above the acceptable set pressure during a surveillance test. The WR
stated that the valve had lifted high due to the lifting lever shaft being
jammed against the spindle.
The WR recommended that a walkdown be performed
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to check similar valves and that an evaluation be performed to determine a
method to prevent reoccurrence of the problem.
In June 1993, the licensee
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contacted the valve manufacturer about the problem and was sent Engineering
Bulletin 91-001 dated February 2, 1991. The bulletin stated that during
assembly there was a possibility that the lifting lever shaft could be
installed too far into the cap and contact the valve spindle.
The bulletin
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recommended that the distance from the cap to the outer end of the lever shaft
be measured to ensure that the shaft was inserted to the proper length.
In addition, the team reviewed the engineering evaluation requested in
WR 2815-93, dated July 20, 1993. The evaluation recommended that maintenance
inspect all affected valves, measure the length of the lever shaft, and rework
any shafts to conform to the required length.
It also recommended that a
collar be installed on the affected valves to prevent over-insertion of the
lever shaft and that the vendor maintenance manuals be updated with the
information.
The licensee stated that the inspections had been performed to
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measure the length of the lever. shafts on the affected valves, however, the
inspections had not been documented.
The licensee's resolution of this issue,
and other relief valve issues discussed later, will be evaluated in a followup
inspection (Inspection Followup Item 482/9321-01).
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The team reviewed numerous WRs and noted instances of poor quality
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documentation of the work performed and the cause of the problem.
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example, on four WRs written to add oil to the auxiliary feedwater pumps, the
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cause was listed as " low oil." On one WR written to repair a leaking valve,
the mechanic stated that no work was performed but failed to indicate that the
valve was repaired under a different WR. The team also noted that the
licensee's evaluation of an' electrical splice (WR 04366-92) did not provide
information that indicated all aspects of equipment environmental
qualification requirements had been considered. The team conducted personnel
interviews and independent evaluations to ensure that the identified examples
did not represent a safety or operability concern.
2.2.2
Timeliness of Corrective Actions
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2.2.2.1
Residual Heat Removal System Relief Valves
The team reviewed Hardware failure Analysis Request (HFAR) MA 92-004, dated
January 17, 1992.
This HFAR evaluated a rupture of the bellows in Residual
Heat Removal Discharge Header Relief Valve EJ8856B.
The response to the HFAR,
dated November 4,1992, documented that the bellows had failed and the valve
had been replaced under WR 00170-92.
In addition, the HFAR stated that the
root cause of the failure could not be determined because the damaged bellows
was not available.
The licensee's engineering department had reviewed the failure of the bellows
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and had determined that it would not affect the ability of the valve to lift,
relieve pressure, and close.
Since the bonnet of the valve had a vent hole
open to atmosphere, any liquid that leaked through the failed bellows could
discharge through the vent hole onto the floor. The licensee determined that
there would be no significant back pressure above the bellows because of the
vent hole.
The licensee's corrective actions were to salvage the failed parts
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the next time the bellows failed on either Valve EJ8856A or EJ8856B and obtain
a laboratory assessment of the failure.
Based on the type of failure, the
licensee would review the operating and inspection history of the valves to
determine the cause of the failure.
The team reviewed the WRs for Valves EJ8856A and -B and determined that there
had been seven bellows failures since 1984; three for Valve EJ8856A and four
for Valve EJ8856B.
The corrective action for these failures had been to
either replace the bellows or replace the valve.
The most recent failure was
documented on WR 70247-93, dated March 4, 1993, for Valve EJ8856B.
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WR stated that the valve was to be refurbished. At the time of this
inspection, the failed bellows had not been examined to determine the cause of
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failure as recommended by HFAR MA 92-004.
The team agreed with the licensee's determination that these relief valves
would function and open near the required relief setpoint pressure. The team,
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however, expressed a concern about area contamination if the relief valves
lifted and the ' ruptured bellows allowed flow out of the vent hole onto the
floor.
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Criterion XVI of Appendix B to 10 CFR Part 50 requires that measures. shall be
established to assure that conditions adverse to quality are promptly
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identified and corrected.
For significant conditions adverse to quality, the
measures shall assure that the cause of the condition is identified and
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corrective actions taken to preclude repetition. The licensee's failure to
promptly correct the root cause of the repetitive relief valve bellows
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failures and the apparent lack of a thorough evaluation of the consequences of
these failures was the first example of a failure to implement prompt
corrective actions (Violation 482/9321-02).
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2.2.2.2
Drawing Discrepancies
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The team reviewed WR 3909-92, dated August 1, 1992.
The WR identified a
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problem with the model number of the flow transmitters for the component
cooling water to the reactor coolant pump thermal barrier coolers.
The flow
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transmitters (BBFT 17/18/19/20) were identified as Model No. Il53DD4PA on one
drawing and Model No.1153HB4 on another drawing.
The first model number
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indicated a stainless steel housing and the second an aluminum housing. The
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WR was assigned to engineering on September 1, 1992, but no action was
initiated until this inspection.
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Criterion XVI of Appendix B to 10 CFR Part 50 requires that conditions adverse
to quality be promptly identified and corrected. The licensee's failure to
determine the correct model number for the flow transmitter and correct the
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drawings in a timely manner was the second example of a failure to take prompt
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corrective action (Violation 482/9321-02).
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2.2.2.3
Auxiliary Feedwater Pumps
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The team reviewed Performance Improvement Request TS 92-0461 initiated on
June 18, 1992. The performance improvement request addressed the operation of
the auxiliary feedwater pumps in the low flow cavitation region for greater
than one hour. Operation of the pump in the low flow cavitation region for
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long periods could result in pump damage.
The supervisor stated that the
performance improvement request was "to address the programmatic aspects of
why the run times were not found earlier, not the technical hardware
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condition." The licensee initiated WRs 03980-92, 03981-92, and 03982-92 on
August 4, 1992, to document that each of the pumps had been operated for
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greater than one hour in the low flow cavitation region.
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The team reviewed these WRs and noted that the low flow condition identified
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in WR 03980-92 occurred on November 10, 1991; WR 03981-92 occurred on
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February 20, 1992; and, WR 03982-92 on February 19, 1992. WR 00094-93 was
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initiated on January 8,1993, but did not specify the date that the
"B" motor-
driven auxiliary feedwater pump (PALOlB) was operated in excess of the one
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hour limit in the low flow condition.
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On May 21, 1993, the licensee initiated Performance Improvement
Request OP 93-0461 to document "eight occasions since August 1992 [that] the
Auxiliary Feedwater Pumps (PALOIA & B and PALO2) [ exceeded] the maximum time
limit the pumps should be run in low flow conditions." Although the
supervisor stated the " repetitive nature of this problem warrants further
investigation," the responsible manager did not categorize the performance
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improvement request as significant.
The initiator provided three possible solutions to resolve the problem. The
first would have required the operators to track the time the pump was
operated in the low flow region and stop t'c pump when the time limit expired.
The second would have replaced the orifice in each recirculation line with a
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locked throttle valve to ensure proper recirculation flow during testing.
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third required a reevaluation of- the low flow requirements.
The licensee
informed the operators that all test equipment and personnel should be staged
before starting the pump and to secure the pump as soon as possible. -The
licensee also initiated Engineering Evaluation Request 93AL01 to reevaluate
the condition. On the basis of these two actions the licensee closed
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Performance Improvement Request OP 93-0461.
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Following the team's request for copies of WRs 03980-92, 03981-92, 03892-92,
and 0094-93, the licensee determined that no significant work activity was
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associated with the documents for over 1 year. As a result of this finding,
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the licensee initiated Performance Improvement Request RS 93-0871 on August 9,
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1993. This performance improvement request was then evaluated by the
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Performance Improvement Review Group, categorized as not significant, and
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closed without being submitted to a responsible manager.
The team found the licensee's determination of the operability of the pumps to
be acceptable but questioned the categorization of the involved performance
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improvement requests.
The subject of significance determination is discussed
further in Section 3.2 of this report.
2.2.2.4
Instrument Air Compressor Check Valve
The team reviewed WRs associated with Valve EF-V046, the "A" instrument air
compressor essential service water (ESW)- return check valve.
This valve had
been worked five times within the previous 12 months to correct problems with
valve leakage identified during inservice testing.
Because of the recurring
failures, the licensee was performing a leak rate test quarterly.
Valve EF-V046 was a 2%-inch carbon steel body swing check valve.
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internal bushing, hanger, retaining fasteners, and swing pin were manufactured
of corrosive resistant ferric material with the valve disk, except for the
seating surface, constructed of carbon steel.
The team reviewed the following WRs:
Work Request Number
Date Initiated
Date Worked
03784-92
July 23, 1992
July 23,1992
05311-92
October 22, 1992
October 23, 1992
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00377-93
January 22, 1993
January 22, 1993
03042-93
May 1, 1993
May 1, 1993
04595-93
July 23, 1993
July 23, 1993
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These WRs were identical in scope and content and were all performed in
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response to inservice testing failures. Maintenance in all of these WRs
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consisted of disassembling the valve, cleaning the internal components, valve
reassembly, and satisfactory completion of the inservice testing leakage test.
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An HFAR to address the repetitive valve failures was assigned to the system
engineer for action on November 12, 1992.
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Although the valve having failed three more times since the request had been
made, the only action taken by the system engineering organization to
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determine the root cause of the valve failures was a fact gathering meeting on
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July 29, 1993. The team considered the failure of system engineering to take
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prompt action to determine the root cause of the repetitive failures of this
safety-related valve to be a weakness in the corrective action program.
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Based on the review of the five WRs, the team noted an inconsistency in the
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manner that Steps 2.2 and 2.3 were performed.
These steps directed craft
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workers to record critical tolerances internal to the valve between the
bushings, hanger, and hanger block. These measurements were necessitated by a
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10 CFR Part 21 report dated January 18, 1991.
In that report, the vendor
identified that swing check valves of the size installed in this application
could fail open due to incorrect tolerances in the valve internals. As a
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result, the vendor recommended that these tolerances be routinely measured as
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a part of a check valve program internal inspection.
Steps 2.2 and 2.3 of the
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WR directed the craft to record the degree of engagement that existed between
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the valve hanger pin bushings. Step 2.4 gave the minimum acceptance value for
this measurement as 0.010-inch.
If the measurements were less than this
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acceptance criteria, WR 04595-93 directed workers to generate a corrective WR.
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WRs 03784-92, 05311-92, 00377-93, and 03042-93 directed workers to contact the
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maintenance engineer if any readings were discovered to be less than the
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minimum acceptable.
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The team's review of the WRs revealed the following recorded measurements:
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Work Request Number
Step 2.2 Measurement
Step 2.3 Measurement
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03784-92
No Measured Gap
No Measured Gap
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05311-92
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00377-93
No Movement Detected
No Movement Detected
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03042-93
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.032
04595-93
Less Than .0025-inch
less Than~.0025-inch
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Based on the requirements contained in WRs 03784-92, 05311-92, and 00377-93,
the maintenance engineer should have been contacted and for WR 04595-93, a
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corrective WR should have been initiated because the measurements were not
within the acceptance criteria. The team determined that WRs had not been
initiated as a result of these measurements not meeting the acceptance
criteria.
In addition, the team interviewed the maintenance engineer and
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determined that he h.r] rot been contacted regarding the unacceptable check
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valve tolerances.
Technical Specification 6.8.1.a states that written procedures shall be
established, implemented, and maintained covering the applicable procedures
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recommended in Appendix A of Regulatory Guide 1.33, Revision 2, dated
February 1978. Regulatory Guide 1.33, Appendix A, Item 9a, recommends, in
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part, that maintenance that can affect the performance of safety-related
equipment should be properly planned and performed in accordance with written
procedures appropriate to the circumstances. The failure of maintenance
workers to generate a corrective WR and inform the cognizant maintenance
engineer that the measured critical tolerances in Valve EF-V046 were not
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within the acceptance criteria were violations of this requirement
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(Violation 482/9321-03).
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Additional followup was conducted by the team to determine if the critical
tolerances recorded in WRs 03784-92, 05311-92, 00377-93, and 04595-93 would
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indicate potential unacceptable check valve performance.
The team determined
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that the values recorded were not the bushing engagement measurements as
required by the WRs; rather the recorded values were the bushing clearance
gaps.
Further review by the team revealed that the these measured gaps
provided sufficient information to conclude that a binding problem did not
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exist and that there was little potential for the check valve to fail open in
the manner described in the valve vendor's 10 CFR Part 21 report.
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2.3 Conclusions
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The team noted examples of poor quality documentation of the work performed
and determination of the cause of the problem in the WRs that were reviewed.
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The team concluded that the licensee had established a WR program capable of
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functioning to resolve the problems that were identified. The team determined
that program implementation was a weakness and that program implementation was
not producing timely resolution of some problems.
The team identified one violation of adherence to procedural requirements.
3 PERFORMANCE IMPROVEMENT REQUEST REVIEWS (92720)
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3.1
Items inspected
The licensee utilized the performance improvement request to document and
disposition programmatic problems. The team reviewed 126 performance
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improvement requests. An initial sample of 98 performance improvement
requests was selected from the listing of open and closed items that was
provided by the licensee before the inspection. Additional selections were
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based on the review of the initial sample and other documentation. The
licensee's evaluations and corrective actions were reviewed for adequacy and
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timeliness.
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3.2 Findings
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3.2.1
Program Development
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The team noted that performance improvement requests were initiated and
dispositioned in accordance with Procedure KGP-1210, " Performance Improvement
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Requests," Revision 8. The team determined that the programmatic requirements
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had undergone significant change in the past 2 years.
Previous revisions had
changed requirements as noted below:
Revision 6 was issued on October 9, 1991. The determination of problem
significance was determined by subjective evaluation by the designated
responsible manager. There were no timeliness requir2ments for the
determination, but a root cause determination was required.
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Revision 7, dated September 1,1992, also required a root cause
determination for significant performance improvement requests.
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Significance was determined by evaluating the condition to criteria
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provided in the procedure. The procedure also imposed time limits. The
root cautr determination, development of corrective action, and
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establishment of a completion date were required within 30 days of
performance improvement request receipt by the responsible organization.
The current Revision 8, dated June 8, 1993, removed the timeliness
requirements, but still required a formal root 'cause determination for
all significant performance improvement requests. Significance was
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determined by evaluating the condition to criteria that was improved
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over Revision 7.
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3.2.2 Documentation Deficiencies
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3.2.2.1
Reactor Vessel Flange Damage
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Performance Improvement Request 91-0973 was issued in November 1991, because
damage had occurred to the reactor vessel flange while installing the reactor
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vessel head.
The licensee determined that the damage had occurred because of
foreign material on the vessel mating flange. The responsible manager had
evaluated this performance improvement request as significant. A corrective
action due date extension had been handled in accordance with the procedure.
However, the documentation of the licensee's efforts to resolve the deficiency
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was inadequate to determine the status of corrective action and the root cause
determination had not been completed. The team was informed that the
corrective action was nearly complete and had involved changing several
procedures.
3.2.2.2
Motor-Operated Valves (MOVs)
The team reviewed Performance Improvement Request NP-93-0252, initiated on
March 26, 1993, to document an MOV actuator that had its motor heater
energized.
The actuator had been qualified for a 40-year lifetime with the
motor heater not energized.
The licensee determined that an additional
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14 MOVs had energized motor heaters.
The licensee concluded that the heaters
should have been deenergized under the guidance' of the environmental-
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qualification program.
The licensee determined that the root cause was
personnel carelessness and inattention.
The licensee stated that 13 of the 15 actuators had been replaced, 11 during
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Refueling Outage IV and two during Refueling Outage V.
The team noted that
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the licensee had disconnected all heaters during Refueling Outage VI'
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licensee performed an evaluation that concluded that the motors in question
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would be qualified until Refueling Outage VII.
The initial motor qualified
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lifetime was based on an ambient temperature of 60 C (140a F) and the revised
qualified life was adjusted for the ambient temperature plus any heat rise
that resulted from the heater being energized. The published heat rise from
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the motor heater was 10 C (18 F). The team performed an evaluation and
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verified that the actuators would remain qualified unti? Refueling Outage VII.
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The licensee stated that additional evaluations would be performed to
determine if the motors will need to be replaced during Refueling
Outage VII, or if they can be qualified for an additional amount of time.
These evaluations will be performed as part of the corrective actions for
Performance Improvement Request NP-93-0252.
3.2.2.3
Relief Valves
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The team reviewed Performance Improvement Request OP 93-0145 dated March 4,
1993, concerning a relief valve on an instrument air compressor that lifted
and remained open.
The performance improvement request stated that the ESW
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pressure regulator bypass valve was found open which allowed the full ESW
system pressure of 106 psig to be supplied to the air compressor cooler while
the relief valve had a set pressure of 80 psig.
The bypass valve was closed
to stop the over-pressure condition and the performance improvement request
,
stated that the bypass valve was required to be closed during normal
3
4
operation. This performance improvement request was identified as a
,
significant condition.
,
The performance improvement request documented that the root cause for the
bypass valve being open was unknown. The team discussed this root cause with
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licensee personnel who indicated that due to personnel error, the valve had
been opened while work had been performed on the air compressor. The team
considered this to be another example of a weak root cause analysis and a
further example of poor documentation.
The team also reviewed Performance Improvement Request TS 92-0825 dated
December 31, 1992.
This performance improvement request identified two
pressure relief valve setpoints listed in the total plant setpoint
document (TPSD) that did not agree with the setpoints listed in a surveillance
test procedure. The performance improvement request documented that the
correct spring setpoint, which corrected for temperature and/or back-pressure
conditions, was listed in the surveillance test procedure. The TPSD contained
the operational set pressure, which did not compensate for back pressure
and/or temperature.
The supervisor assessment section of the performance
improvement request stated that an analysis of each Westinghouse purchased
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relief valve would compare the actual test pressurc- to the cold differential
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test pressure.
This supervisor assessment was dated January 28, 1993.
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Performance Improvement Request TS 92-0825 was closed on August ~2,
1993,
without performing the analysis based on a' proposal by system engineering to
form a task team to gather, analyze and document information on. pressure
relief valves.
The data would be used to update the TSPD as the correct
information became available.
Performance Improvement Request 93-0822,- dated
August 2,1993, was generated to update the TSPD with the correct valve data.
,
In addition to the performance improvement requests, the team reviewed
interoffice correspondence, EN 93-0291, dated August 23, 1993.
This document
proposed a more complete program because relief valve information was either
non-existent, conflicting, or not easily accessible.
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Evaluation of the licensee's actions concerning the update of the TSPD and:
'
other relief valve issues will be included in a followup inspection discussed
earlier in this report (Inspection Followup Item 482/9321-01).
3.2.2.4
Human Performance Enhancement System (HPES)
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The team reviewed the licensee's HPES and determined that the use of the
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program had been significantly curtailed in recent years.
The program was
governed by Procedure ADM 01-251, " Human' Performance Enhancement System (HPES)
Program." The procedure called for HPES evaluations to be performed in
.
response to requests by licensee managers and at the discretion of the manager
plant support based upon the availability of resources. The current program
coordinator hsd been appointed in early 1992 but was not dedicated full-time
"
to the HPES function.
The number of evaluations performed under the heading
)
of a HPES review had declined from 15 to 20 per year performed in the late
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1980's to 6 performed since January 1992.
The change in the coordinator
position may have been a factor in the reduction in HPES evaluations
.per orme . However, the principal reason seemed to have been a decision by
f
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licensee management to incorporate the HPES function into the normal
co ective action process.
The team determined that the formal HPES evaluations generally utilized an
extensive list of questions to assist the evaluator in performing the root
cause analysis. The HPES evaluations, such as HPES Report 92-003, involving
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diesel fuel oil spraying an operator during sampling, were thorough and
adequately determined the cause of the human performance problems.
The performance improvement request procedures and training documents were
reviewed to determine if human performance considerations were incorporated
into the performance improvement request root cause evaluations. The training
material included methods that could, if performed thoroughly, identify human
performance issues similar to HPES evaluations. However, the training
material and procedures did not include guidance comparable in detail to the
questions provided to assist in ADM 01-251 HPES evaluations.
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Several performance improvement requests with possible human performance
issues were selected to determine if the root cause evaluations identified
the issues and possible corrective actions.
Two of the performance
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improvement requests selected were considered to have good root cause
-evaluations that addressed various aspects of human performance. These
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performance improvement requests involved the failure of control room -
operators to recognize the auxiliary feedwater switches remained in
pull-to-lock during a mode transition and a problem encountered with clearance
orders during Refueling Outage VI.
It should be noted that the first issue
involved an NRC escalated enforcement action and the second involved a
licensee incident investigation team.
The other performance' improvement-
requests involved more routine events and the quality of the documented
evaluations was found to be less detailed. Although the proposed corrective
actions for these performance improvement requests included procedure changes,
man-machine interface enhancements, and other human performance enhancements,
the documentation was insufficient to determine if thorough consideration had
been given to potential human performance issues.
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3.2.2.5
Weak Root Cause Determination And Planned Corrective Action
,
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Performance Improvement Request 93-0180 was initiated on March 11, 1993, when
lighting system fuses were not reinstalled following the test discharge of
!
batteries for five emergency light fixtures.
The affected emergency lights
would not have functioned for the one week period before the condition was
i
discovered. One of the affected emergency lights was installed in the
auxiliary shutdown panel room.
The responsible manager evaluated the event to
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be significant within 4 days of the performance improvement request
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initiation.
The root cause investigation determined the cause to be poor work turnover
between shifts and insufficient importance given to emergency lighting testing
i
because workers were being hurried to complete the work before the outage
'
started. The team determined that the stated root cause listed symptoms
rather than the causes for why personnel were hurried and why the shift
turnover process did not function as intended. The aspects of scheduling and
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shift turnover were not addressed in the corrective action. The team
considered this root cause investigation to be weak and the perfarmance
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improvement request documentation to be poor.
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3.2.3
Timeliness of Corrective Action
A concern that safety-related tubing installed in the facility was not
verified to be in compliance with the applicable ASME Code for cross sectional
ovality of tubing bends was originally reported in Programmatic Deficiency
Report NP 91-021.
The responsible manager determined that verification of
ovality or other corrective action was not needed because the installation
i
process assured compliance with code requirements for tubing bend ovality.
This document was closed on July 1, 1991.
The identical concern was documented in Performance Improvement Request
91-0398 on July 10, 1991, and was evaluated to be significant by a different
responsible manager.
The significance determination was made on September 23,
1991, about 10 weeks after the performance improvement request was initiated.
There was no other activity to address the concern until June 3, 1993, when
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WR 03834-93 was initiated. The WR was to evaluate the "as built"
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acceptability for bends in installed tubing. The specified method for this
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evaluation was to bend tubing samples for all installed types and
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configurations using standard equipment, and evaluate the samples for "use as
is."
The due date assigned for completion was March 31, 1994.
The elapsed time between problem identification and significance determination
was considered untimely. A greater concern was the lack of activity between
the time the concern was determined to be significant, September 1991, and the
i
development of a corrective action plan in June 1993. The team determined
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that the tubing ovality issue was not addressed promptly.
Criterion XVI of
Appendix B to 10 CFR Part 50 requires that measures be established to ensure
conditions adverse to quality are promptly identified and corrected.
The
tubing ovality issue was the third example of a violation of 10 CFR 50,
Appendix B, Criterion XVI (Violation 482/9321-02).
3.2.4
Corrective Action Due Date Extensions
Revision 8 of Procedure KGP-1210 allowed the responsible manager to extend a
corrective action due date for significant performance improvement requests
one time. The second extension required the approval of the department head.
.
Extensions granted under the previous revision of Procedure KGP-1210 required
the department head of the responsible manager be cognizant of any significant
performance improvement request due date extension.
At the start of the inspection, there were 77 significant performance
improvement requests being processed. The team determined that 36 of these
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had been granted at least one corrective action due date extension.
From the
list of 36 open significant performance improvement requests that were
extended, the team identified 20 performance improvement requests with due
dates that had been extended under Revision 7 of Procedure KGP-1210.
The team
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reviewed 10 of those packages and found documentation that the responsible
manager had approved the due date extensions. However, there was no
I
indication that department heads were cognizant of any of these due date
)
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extensions. Although this was a procedural requirement, there was a lack of
guidance and process for meeting the requirement.
During the inspection, the team noted that the licensee's monthly management
report indicated that the number of performance improvement requests with
overdue corrective action had decreased from seven in the June report to one
for the July report. Additional questioning of licensee personnel revealed
i
that four of the original performance improvement requests had been closed and
the due dates had been extended on the remaining three. The team determined
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that changing due dates could provide licensee management misleading trending
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information.
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3.2.5
Significance Determinations
The team noted several performance improvement requests that appeared to have
the significance of the problem incorrectly categorized with regard to problem
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significance. Six examples of this concern, in addition to those discussed
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above, were:
Performance Improvement Request MA 92-0296, " Problems with Werk
Requests"; Performance Improvement Request MA 93-0601, " Wiring Terminations
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Not Verified by Quality Control"; Performance Improvement Request MA 93-0701,
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" Safety-Related Work Request Marked as Nonsafety-Related"; Performance
Improvement Request TS 93-0715 " Blown Fuses During Testing"; Performance
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Improvement Request TS 93-0738, "Two Safety-Related Work Requests Marked as
'Nonsafety-Related"; and, Performance Improvement Request MA 93-0781, " Lost
Maintenance and Test Equipment."
All six of these performance improvement requests represented recurring issues
that had been identified in earlier performance improvement requests. One of
the criteria to determine if an issue was significant was an " adverse trend or
ineffective corrective action for recurring problems."
The team asked the responsible managers for these performance improvement
requests why they were not significant conditions even though some were for
recurring problems. The managers stated that the threshold for considering an
issue to be recurring was at the discretion of the particular manager.
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The team also asked a performance improvement request reviewer about these
determinations.
The team was informed that the performance improvement
requests were not listed as significant even though the reviewer was aware
that the conditions were recurring. The reviewer stated that each performance
improvement request was not significant on its own merit.
The team concluded that the significance determination of issues was not being
implemented in a consistent manner.
.
3.3 Conclusions
Based on the above observations, the team determined that corrective action
,
due da_tes were initially established and routinely extended without a
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documented justification or a technical basis. The team expressed a concern
that these practices could lead to misleading trending information and could
result in untimely implementation of corrective actions. The team determined
that some examples of untimely corrective actions were violations of NRC
requirements.
Another concern identified during the inspection was the adequacy of
documentation. Adequate actions had usually been conducted in response to-
identified problems but the record did not reflect those actions. The team
determined that a written record of problems that have been identified and the
i
actions taken to resolve the problem was necessary in order to track and trend
issues and ensure an effective corrective action program.
The team observed that the criteria to assist in the determination of
performance improvement request significance had been improved; however, there
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was an apparent lack of consistency in making the determinations.
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4 QUALITY ASSURANCE (QA) AUDIT EVALUATION
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4.1
Items Inspected
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The team reviewed the results of nine QA audits and five QA surveillances for
scope, detail, and validity of findings. The suitability, timeliness, and
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effectiveness of resultant corrective actions were also evaluated.
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4.2 Findinas
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The scope and depth of QA audits and surveillances appeared appropriate. The
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QA personnel issued performance improvement requests and recommendations for
improvement (RFIs) to initiate corrective actions.
Responses to both
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documents were tracked by QA. The team observed that suitable performance
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improvement requests and RFIs were being issued by QA in response to audit and
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surveillance findings. The team reviewed responses and corrective actions
associated with 12 performance improvement requests and 9 RFIs issued by QA
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and found them generally suitable and timely.
QA personnel stated that
80 percent of RFI responses were either fully or partially satisfactory.
The NRC team also reviewed the performance improvement requests that were
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issued as a result of QA Audit TE:50140-K386, " Records Management," conducted
1
in May 1993.
Performance Improvement Requests 93-0420 and 93-0421 dealt with
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failure to properly store certain QA records. The performance improvement
requests stated that compliance with American National Standards Institute
,
(ANSI) N45.2.9-1974, " Requirements for Collection, Storage, and Maintenance of
'
QA Records for Nuclear Power Plants," was committed to in Table 17.2-3, Sheet
2, of the Updated Safety Analysis Report. However, newly generated records
were being sent to a storage building in New Strawn that was not tornado
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proof, did not have a fire protection system, and did not have adequate
'
temperature and humidity controls as required by ANSI N45.2.9. Also, the
padlock on the door did not meet the requirement for the full-time security
system required by ANSI N45.2.9.
The team toured the records storage facility and observed water on the floor
indicating a roof leak and noted that the building was extremely hot and humid
i
during an inspection on August 24, 1993. Through interviews with the document
control staff, the team learned that some QA records had been stored in this
building since September 1992. Those records had been recovered from a
contract storage facility damaged by a fire in December 1991.
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After the fire at the contract storage facility in December 1991, certain QA
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records were sent to the site warehouse until November 1992. At that time,
the licensee moved all of those records to the New Strawn building, as well as
newly generated records. There were no records stored in the site warehouse
until the licensee moved radiographs from the New Strawn building in June
1993. On August 24, 1993, the team observed that temperature and humidity
controls in the site warehouse did not meet the requirements of ANSI N45.2.9.
Also, a licensee representative stated that the building could not withstand a
design basis tornado.
Radiographs were stcred in a separate room in the site
warehouse that had an air conditioner and a dehumidifier.
However, the
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licensee representative stated that they were having difficalty maintaining
the humidity within the desired range.
The team noted that Memorandum DS-93-0078, dated June 29, 1993, responded to
the QA Audit and indicated that compliance with ANSI N45.2.9 might not be
achieved until December 1995. There was no comprehensive corrective action
plan and the December 1995 completion date did not appear timely.
Involved QA
personnel stated that they were not satisfied with the proposed corrective
action plan. The team found no evidence of senior management involvement in
resolving this issue prior to this inspection.
The extended period of noncompliance with records storage requirements without
a comprehensive plan for timely recovery to full compliance is a deviation
from commitments made to the NRC (Deviation 482/9321-04).
During the conduct of the NRC inspection, a more comprehensive " action plan
for records storage recovery" was developed and endorsed by senior management.
The plan projected full compliance with records storage requirements by May
1994.
It required sending records to an offsite qualified storage facility if
sufficient qualified onsite storage capacity was not available by the full-
compliance date.
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The team also reviewed Performance Improvement Request 93-0422 that dealt with
failure to verify microfilmed records for quality, legibility, and accuracy
after February 24, 1992. The team was informed that all records that had not
been microfilmed and verified were removed from the New Strawn building to the
site warehouse on August 23, 1993. All other records the licensee determined
to be QA records had been moved from this building to the plant warehouse on
July 28 and 29, 1993. The team examined one box of records stored in the New
Strawn building and verified that a microfilm copy existed.
4.3 Conclusions
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The scope and depth of QA audits and surveillances appeared appropriate. QA
personnel were issuing suitable performance improvement requests and RFIs for
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audit and surveillance findings. The managers receiving performance
improvement requests and RFIs responded with suitable and timely corrective
action plans in most instances.
Corrective actions taken were usually timely.
However, some issues appeared to warrant furthur management attention to
ensure thorough and timely resolution. A deviation was identified involving
the licensee's failure to properly store QA records for an extended period of
time.
5 LICENSEE RESPONSE TO OPERATIONAL EXPERIENCE INFORMATION
5.1
Items Insnected
The team conducted procedure reviews, personnel interviews, and documentation
evaluations to determine the effectiveness of the licensee's use of
operational experience information received from outside organizations. The
team reviewed 24 industry technical information program (ITIP) reports to
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determine if the issues had been appropriately reviewed for applicability and
suitable corrective actions had been implemented.
5.2 Findinos
The ITIP was governed by Procedure KGP-1311
" Industry Technical Information
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Program," Revision 4.
The most recent revision of the procedure had been
issued on August 6, 1993. The procedure had been revised in response to a QA
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surveillance of ITIP evaluations issued on April 23, 1993, and a Nuclear
Safety Evaluation (NSE) effectiveness review. The. findings of the QA
surveillance dealt mainly with the need to improve the timely completion of
ITIP evaluations. The team could not assess the results from Revision 4 of
Procedure KGP-1311 because it was so recently issued.
The annual effectiveness review required by Procedure KGP-1311 showed a
,
significant decrease in the backlog of open ITIP items. The licensee had
'
recently focused attention to the ITIP backlog and specifically addressed
'
those ITIPs more than 2 years old. Dedication of.NSE resources to
coordinating the ITIP program was considered to be the primary reason for the
backlog reduction and the ability to continually monitor the actions related
to ITIPs.
The team performed a review of the program implementation. As of July 1993,
there were 117 open ITIP items. These were categorized as follows:
56 were
in the evaluation process, 53 were awaiting completion of actions such as
procedure changes, and 8 were pending long-term actions such as plant
modifications. The licensee had eliminated the backlog of items awaiting
initial NSE review. The licensee's system for coordinating and monitoring the
status of ITIP reviews appeared to be effective. The personnel interviewed
stated that continued attention will be applied to improving the timeliness
and quality of reviews.
The team performed a review of several recently closed ITIP items and a status
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evaluation of several open ITIP items that were greater than 2 years old. The
review of the closed ITIP items determined that the packages were
appropriately assigned and the licensee actions were reasonable.
Several ITIP
,
items had been addressed by NSE personnel based upon the existence of other
'
open ITIPs related to the same issue. These assessments were eased by the
computer-based tracking system developed by the licensee.
For those cases
reviewed, the team determined that closing of incoming ITIPs by reference to
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other related ITIP items was being performed appropriately. The team's review
of those ITIP reports used to address specific issues determined that licensee
personnel were using adequate analysis techniques or reasonable engineering
judgement in their determinations and development of issue responses.
!
5.3 Conclusions
,
All of the ITIP reports reviewed by the team had been appropriately reviewed
and dispositioned by the licensee. The corrective actions implemented were
appropriate and no examples of failure to take timely action were identified.
The team observed continuing program improvement in that corrective actions
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for recent ITIP reports were being implemented more promptly than for earlier
ITIP reports.
6 PLANT WALKDOWN OBSERVATIONS
6.1
Items Insoected
The team performed general plant walkdowns to evaluate the material condition
of the facility. The team also performed detailed walkdowns of selected
systems to determine if the available documentation reflected the observed
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conditions.
6.2 Findinas
6.2.1
Pipe Support Not Connected To Hanger
During a general tour of the control building on August 12, 1993, the team
f
noticed an unconnected pipe support hanging from a pipe. The 2-inch pipe
!
contained Halon fire suppressant.
When the team questioned the intent of this
!
unconnected support, the licensee initiated WR 4949-93. The licensee
determined that the support had been left on the pipe since construction of
the facility and was not required.
During the second week of onsite
inspection the team reviewed the disposition of the WR and found it
acceptable.
The team also verified that the support had been removed.
.
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6.2.2
Condition of Batteries
The team inspected the condition of the facility batteries as part of plant
tours.
The team considered the four safety-related, Class IE batteries to be
in excellent condition. The nonsafety-related 125V batteries (PKll and PK12)
continued to exhibit the terminal corrosion problems that had been observed by
team members on previous inspections. The team also informed the licensee
that several cells in the 250V nonsafety-related battery (PJ) had water levels
.
above the full-indication mark.
!
6.2.3
Essential Service Water System (ESW)
The team conducted a walkdown of the ESW system to determine if the system was
aligned in accordance with Piping and Instrumentation Drawings M-12EF01,
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Revision 4, M-12EF02, Revision 5, M-K2EF01, Revision 17, and M-K2EF03,
Revision 0.
The team also evaluated the system material condition based on
the number and safety significance of outstanding maintenance items.
The team observed that the material condition of the ESW system was generally
good. However, several WR tags were noted to have not been removed from
!
equipment after corrective maintenance had been completed on the components.
In addition, the team noted a housekeeping deficiency that consisted of a bag
of transient combustible material in the lower level of the control building.
The team also identified a safety hazard in the same room because a nitrogen
3
cylinder was standing unsecured with no safety cap in place to protect the
outlet valve.
Both items were reported to the control room and were promptly
corrected.
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During the walkdown, the team inspected the condition of the ESW warming water
isolation valves (EF-V0262, 0263, 0264, 0265). These valves were 30-inch
manually operated butterfly valves that were normally open in the cold weather
months and closed during warmer weather. The basis for positioning these
valves in this fashion was to direct a portion of ESW return to the ESW inlet
bays to prevent freezing during cold weather. Conversely, this flow was
isolated during warm weather to prevent exceeding the design ESW inlet
temperature of 95* F.
The team noted that several WR tags were attached to the protective guard
rails located at the ladder leading to the ESW warming water valve pit.
WR Tag 43343, dated October 19, 1989, and Tag 56403, dated April 30, 1991,
both documented that all four of the ESW warming water isolation valves were
hard to operate. WR Tag 56404, dated April 30, 1991, identified that
valve EF-V0263 was stuck % open. The team examined Valve EF-V0263, and noted
that the valve's manual actuator indicated that the valve was in the closed
position, even though the indication located on the valve stem revealed that
the valve was approximately % open. The team reported this inconsistency to
the control room. The control room dispatched an operator to check the actual
position of Valve EF-V0263, who reported that the valve was fully shut.
The team requested that the system engineer check the condition and position
of the valve because of their concern that Valve EF-V0263 was not actually
shut.
The system engineer and another operator inspected the valve and
determined that the manual actuator for Valve EF-V0263 indicated that the
valve was shut; however, the actual valve stem was positioned at approximately
% open. Since the valve could not be properly positioned, ~ the team requested
that the licensee perform an operability determination. The licensee
+
determined that Valve EF-V0263 was inoperable.
The team then questioned
system operability with the valve inoperable. The licensee decided since a
'
warming valve, EF-V0265, in series and downstream of Valve EF-V0263, was shut
and prevented flow into the ESW inlet bays, the ESW system was operable. The
team concluded that the licensee's operability determination was appropriate.
The team reviewed Procedure STN GP-001, " Plant Winterization," Revision 9.
This procedure was implemented to open the ESW warming valves when the outside
temperature remained less than 35 F for one week or as directed by the
Operations Manager.
Restoration of the system for warm weather operations was
also completed by Procedure STN GP-001, when the outside temperature remained
greater than 40* F for one week, by closing the ESW warming valves.
Procedure STN GP-001, Step 5.6.4.1 directed operators to open Valve EF-V0263
when aligning the system for cold weather operation.
Procedure STN GP-001,
Step 6.3.3.1 directed the ESW system be restored by closing Valve EF-V0263 for
warm weather. The team reviewed all of the instances where Procedure
STN GP-001 had been performed since Valve EF-V0263 had been rendered
inoperable oa April 30, 1991. The procedure had been completed on
November 10, 1991, and November 28, 1992, when operators opened Valve EF-V0263
for cold weather operation; and on April 13, 1992, and April 29, 1993, when
operators shut Valve EF-V0263 for warm weather. On all of these occasions,
the completed procedure indicated that Valve EF-V0263 had been successfully
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positioned with no documentation to indicate any problem with the manipulation
of the valve.
The team concluded that no actual change to the valve position
had been accomplished; the manual actuator had changed position, but the valve
had remained % open.
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The team reviewed the WRs associated with the tags that were identified on the
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ESW warming lines. Tag 43343 dated October 19, 1989, correlated to
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WR 04592-89 that was worked March 5, 1990.
It documented that all four of the
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ESW warming water isolation valves (EF-V0262, -0263, -0264, -0265) were hard
to operate. The scope of the maintenance performed consisted of cleaning the
exterior of the valve actuator, removing the actuator gearbox inspection
cover, and inspecting the condition and level of the grease, adding grease if
'
necessary, and then cycling the valve several times to ensure free movement.
'
This activity was performed on all four of the warming water isolation valves.
The team's review of this WR also revealed that Valve EF-V0263 required
additional lubrication of the lower portion of the valve stuffing box to cycle
satisfactory.
Action on Tag 56403 dated April 30, 1991, which correlated to WR 01658-91, was
on hold pending receipt of replacement parts. Tag 56404 dated April 30, 1991,
correlated to WR 01656-91 and identified that Valve EF-V0263 had been very
hard to operate and at approximately % shut the valve actuator gear box made
a loud pop and would not operate the valve further. This latter WR had been
closed to WR 1658-91; however the information concerning the valve failing at
% open was not transferred to WR 1658-91.
The effect of this information not
,
being transferred contributed to the valve remaining inoperable and % open
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!
from April 20,1991, until the team discovered the valve's condition. The
failure of the licensee's maintenance program to assure that the failed
condition of ESW Valve EF-V0263 was promptly identified and corrected was
'
considered a significant weakness in the corrective action program.
Technical Specification 6.8.1.a states that written procedures shall be
established, implemented, and maintained covering the applicable procedures
i
recommended in Appendix A of Regulatory Guide 1.33, Revision 2, dated
.
February 1978.
Regulatory Guide 1.33, Appendix A, Item 3.m, requires
!
procedures for startup, operation, and shutdown of safety-related systems.
The operators failed to follow the steps in Procedure STN GP-001 by not
!
properly positioning Valve EF-V0263 (Violation 482/9321-05).
,
In addition, the team considered the operators' failure to identify that
.
Valve EF-V263 was not changing position when the manual actuator was
manipulated to be a significant operator weakness. The team considered this
condition to indicate a lack of training and/or a non-questioning attitude by
operations personnel.
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6.3 Conclusions
The team found the material condition of the facility to be good. The team
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determined that the condition of the safety-related batteries was excellent
but observed problems with the condition of nonsafety-related batteries.
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The team also noted that by superseding an earlier WR for an inoperable ESW
warming valve, information on valve operability was lost. This contributed to
untimely corrective action that lead to a violation.
7 FOLLOWUP (92701)
7.1
(Closed) Inspection Followuo Item 482/9222-01: Component Coolina
Water (CCW) System Flow Alarms
Operation of a standby CCW pump in the recirculation mode during cold weather
conditions was causing low flow alarms. The pump was being operated to
preclude low CCW system temperatures.
During this inspection, the team reviewed the licensee's evaluation of the
effects of cold CCW system temperatures.
The licensee initiated Performance
Improvement Request 92-0507 on July 2,1992, with an initial due date of
December 31, 1992. The due date was extended to June 30, 1993, and later to
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August 30, 1993. The licensee completed an engineering evaluation of those
CCW components that had been designated in the USAR as having a minimua CCW
temperature of 60* F.
The licensee determined that those components could be
operated as low as 35
F.
Therefore, operating the standby CCW pump in the
recirculation mode was not necessary.
7.2 (Closed) Inspection Followup Item 482/9304-01:
Review of Temporary
Modifications
During an engineering and technical support inspection, the inspectors noted
that temporary modifications that did not meet the requirements for performing
a safety evaluation were implemented without a review by the Plant Safety
Review Committee.
During this inspection, the team determined that the Technical Specifications
did not require Plant Safety Review Committee approval of temporary
modifications that did not require safety evaluations. This issue was,
therefore, considered moot.
The team also reviewed the minutes of two recent committee meetings and noted
that reviews of temporary modifications were being documented within 14 days
of implementation.
8 ONSITE REVIEW OF LICENSEE EVENT REPORTS (97200)
(Closed) Licensee Eveat Report 482/92-16:
Reactor Trio Caused BY Maintenance
on Substation Relays
On November 11, 1992, a main generator trip was caused by a ground fault on
the 138kV transmission system. The generator trip caused a reactor trip. All
safety equipment responded appropriately. The ground fault was caused by
improper installation of protective grounds for relay maintenance in an
offsite substation. The licensee evaluated the events that led to the trip
and stated that existing safety rules and procedures were adequate. The
licensee also stated that the non-nuclear personnel would receive additional
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training and that the coordination of different projects would be improved.
These actions were to be completed by March 1,1993.
During this inspection, the team reviewed copies of the involved procedures
and verification that the stated training had been completed and found them to
be acceptable.
9 OVERALL CONCLUSIONS
Overall, the team concluded that the corrective action program provided an
acceptable framework. Although improvement was detected, the program
implementation had not progressed as far as expected considering the number of
long-term issues and the emphasis that the program had received over the past
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2 years.
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The team identified several problems with the corrective action programs. The
adequacy of the root cause determination of some issues was considered poor.
Some instances of poor root cause determinations were found to be the result
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of poor documentation practices. The team also noted poor documentation of
observed conditions, the evaluation of those conditions and the corrective
actions to resolve those conditions.
The team identified three violations of the regulatory requirements for
corrective actions.
In addition, the team identified two procedural
violations and a deviation that represented conditions reflective of a weak
corrective action program.
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ATTACHMENT 1
PERSONS CONTACTED AND EXIT MEETING
1 PERSONS CONTACTED
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1.1
Licensee Personnel
R. Becha, Maintenance Engineering
R. Benedict, Manager, Quality Control
V. Canales, Supervisor, Maintenance and Modification
N. Carns, President and Chief Executive Officer
L. Chambers, Maintenance Engineer
- K. Clair, Supervisor, Maintenance Planning
- A. Clason, Maintenance Engineering Supervisor
K. Derakhshandegan, Supervisor, System Engineering
M. Dingler, Manager, Nuclear Plant Engineering
D. Dullum, Supervisor, Plant Trending and Evaluation
- R. Flannigan, Manager, Nuclear Safety Engineering
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J. Fletcher, Supervisor, Supplier Quality
- C. Fowler, Manager, Maintenance and Modifications
- D. Gerrelts, Instrumentation and Controls Manager
R. Gimple, Technical Staff Engineer, Support Engineering
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- R. Magan, Vice President, Nuclear Assurance
- K. Harvey, Manager, Document Services
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- N. Hoadley, Manager, Equipment Engineering
- W. Illing, Director, Employee Services
- D. Jacobs, Supervisor, Mechanical Maintenance
- W. Lindsay, Manager, Quality Assurance
- 0. Maynard, Vice President, Plant Operations
- B. McKinney, Manager, Training
- R. Meister, Senior Engineering Specialist
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- K. Moles, Manager, Regulatory Services
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A. Muh, Senior Engineer
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J. North, Maintenance and Modification
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B. Pae, Engineer
- C. Parry, Director, Performance Enhancement
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G. Pendergrass, Supervisor, Inservice Inspection / Inservice Testing Program
E. Peterson, Supervisor Quality Assurance Audits
- J. Pippin, Manager, Integrated Plant Scheduling
D. Rasmusson, Supervisor, Document Services
L. Ratzlaff, Supervisor, System Engineering
C. Reekie, Technical Specialist, Quality Assurance
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- F. Rhodes, Vice President, Engineering
- T. Riley, Supervisor, Regulatory Compliance
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- E. Schmotzer, Manager, rurchasing and Material Services
- M. Schreiber, Supervisor, Performance Improvement Request Group
A. Scott, System Engineer
R. Sims, Supervisor, Results Engineering
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- B. Smith, Manager, Modifications
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- C. Sprout, Manager, System Engineering
- C. Swartzendruber, Manager, Technical Services
- J. Weeks, Manager, Operations
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- D. Weninger, Motor-0perated Valve Engineer
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K. Wickman, Human Performance Enhancement System Coordinator
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- 5. Wideman, Supervisor, Licensing
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D. Williams, Supervisor, Electrical Maintenance Planning
M. Williams, Manager, Plant Support
J. Yunk, Compliance Specialist
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1.2 Contractor Personnel-
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J. Winkel, Authorized Nuclear Inspector, Factory Mutual Engineering
Associates
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l.3 NRC Personnel
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- H. Bundy, Reactor Inspector
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- S. Collins, Director, Division of Reactor Safety
- P. Goldberg, Reactor Inspector
- C. Paulk, Reactor Inspector
- G. Pick, Senior Resident Inspector
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- M. Satorius, Project Engineer
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W. Reckley, Project Manger
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J. Ringwald, Resident Inspector
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- P. Wagner, Team Leader
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J. Whittemore, Reactor Inspector
In addition to the personnel listed above, the inspectors contacted other
licensee personnel during this inspection.
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- Denotes personnel attending the exit meeting on August 27, 1993.
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- Denotes those personnel who attended the exit meeting and participated in the
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telephone meeting on August 31, 1993.
2 EXIT MEETINGS
An exit meeting was conducted on August 27, 1993. During this meeting, the
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team reviewed the scope and findings of the inspection. A supplemental
meeting was conducted via telephone on August 31, 1993. The licensee did not
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identify as proprietary any information provided to, or reviewed by, the team
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during the inspection.
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ATTACHMENT 2
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LIST OF ACRONYMS
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ANSI American National Standards Institute
Component Cooling Water
Essential Service Water
HFAR Hardware Failure Analysis Request
HPES Human Performance Evaluation System
ITIP Industry Technical Information Program
Motor Operated Valve
NSE
Nuclear Safety Engineering (Group)
Recommendations For Improvement
TPSD Total Plant Setpoint Document
Quality Assurance
Work Request
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ATTACHMENT 3
INSPECTION FINDINGS INDEX
The following violations were identified:
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482/9321-02 in paragraphs 2.2.2.1, 2.2.2.2 and 3.2.3
2.
482/9321-03 in paragraph 2.2.2.4
3.
482/9321-05 in paragraph 6.2.3
Deviation 482/9321-04 was identified in paragraph 4.2
Inspection Followup Item 482/9321-01 was identified in paragraphs 2.2.1
and 3.2.2.3
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The following inspection followup items were closed:
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482/9222-01 in paragraph 7.1
2.
482/9304-01 in paragraph 7.2
Licensee Event Report 92-016 was closed in paragraph 8
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