ML20128M122
| ML20128M122 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 10/08/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20128M108 | List: |
| References | |
| 50-440-96-05, 50-440-96-5, NUDOCS 9610160007 | |
| Download: ML20128M122 (33) | |
See also: IR 05000440/1996005
Text
U. S. NUCLEAR REGULATORY COMMISSION
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REGION lli
Docket No:
50-440
License No:
Report No:
50-440/96-05
Licensee:
Centerior Service Company
Facility:
Perry Nuclear Power Plant
Location:
P. O. Box 97, A200
Perry, OH 44081
Dates:
June 8 - July 26, 1996
Inspectors:
D. Kosloff, Senior Resident Inspector (SRI)
R. Twigg, Resident Inspector
S. Stasek, SRI Davis-Besse
S. Burgess, Reactor Inspector
J. Guzman, Reactor Inspector
M. Holbrook, INEL
P. Louden, Senior Radiation Specialist
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K. Selburg, Reliation Specialist
T. Telia, Reactor Inspector
M. Bugg, NRR Observer
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Approved by:
R. D. Lanksbury, Chief, Projects Branch 2
Division of Reactor Projects
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9610160007 961008
ADOCK 05000440
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EXECUTIVE SUMMARY
Perry Nuclear Power Plant, Unit 1
NRC Inspection Report 50-440/96-05
This integrated inspection included aspects of licensee operations,
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engineering, maintenance, and plant support. The report covers a 7-week
period of resident inspection; in addition, it includes the results of
announced inspections by engineering specialists who inspected the licensee's
response to Generic Letter 89-10, " Safety-Related Motor-Operated Valve (MOV)
Testing and Surveillance" (2515/109).
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Operations
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The operators performed well in response to a feedwater transient
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(Section 01.2).
Equipment deficiencies identified by the inspectors indicated that
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appropriate personnel did not always identify readily observable
equipment deficiencies or, for those that were identified, had not
communicated the deficient plant conditions to appropriate plant
personnel. After the inspectors reported the equipment deficiencies,
the licensee's reactions ~and followup actions to the reported conditions
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were prompt and appropriate (Section 02,1).
Two events associated with the plant's electrical systems were caused by
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operators not adequately considering their plans before taking actions.
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One event resulted in a non-cited violation and could have been avoided
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if the unit supervisor had heeded questions from operators (Section
04.1).
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Overall, the licensee used a variety of self-assessment techniques to
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identify issues that required corrective actions. However, the
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inspectors identified other deficient plant conditions. This indicated
that not all personnel utilized the licensee's self-assessment
identification techniques (Sections 02.1, 07.1, M2, and F5).
Maintenance
Activities were conducted in a professional manner, tagouts ware
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appropriately completed, engineering and management involvement was
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apparent.
Licensee personnel aggressively pursued corrective actions
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for previously identified weaknesses in work planning and timely
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execution of work (Section M1.1).
The licensee developed a program implementing the NRC maintenaace rule
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prior to the rule deadline (Section M3.1).
Failure to promptly communicate potential problems with contain:nent
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vacuum breaker valve indications resulted in a violation of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action" (50-440/96009-02)
(Section M4.1).
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A maintenance self-assessment, started late in the inspection period,
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had potential for identifying specific areas for improvement (Section
M7.1).
Enaineerina
The licensee identified that a modification had altered the operation of
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the RCIC system in a way that had not been conveyed to the operators
(Section El.1).
Regarding the MOV program:
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GL 89-10 program documentation and test data provided an adequate basis
to conclude that all GL 89-10 program MOVs would perform their intended
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safety functions under design-basis conditions (Section E2.1).
Perry had a capable technical MOV staff with a well organized and well
documented GL 89-10 program (Section E2.1).
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The MOV tracking and trending program was considered a strength (Section
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E2.1.9).
Self-assessments in the MOV area provided good technical findings and
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were beneficial in improving the MOV program (Section E7.1).
The licensee responded conservatively and aggressively to transformer
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failures (Section E2.2).
Plant Sucoort
The licensee continued to effectively implement the radiological control
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program at the station. The itcensee's program for radioactive material
control was being adequately implemented; however, a lack of
understanding of the program requirements existed among the general work
force and program improvements had not been implemented (Section RI.1).
The filtered ventilation program was determined to be effectively
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implemented. The radiation monitoring program was being adequately
implemented; however, licensee identified that reliability problems
existed with the radiation monitoring system (Sections R2.1 and R2.2).
The licensee's response to a bomb report was prompt, thorough, and
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conservative (Section S4.1).
The licensee determined that a number of motor operated valves may not
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be capable of performing their safety function under certain control
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room fire scenarios. The licensee submitted a Licensee Event Report and
was developing methods to further evaluate this problem (Section F2.1).
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Report Details
Summary of Plant Status
At the beginning of the inspection period the plant was in a forced outage due
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to the earlier failure of the auxiliary transformer. The plant was started up
on June 10 and the main generator was synchronized to the grid on June 11.
Power was increased and the plant operated at full power until July 11, when
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the "A" Reactor Feedwater Pump Turbine (RFPT) tripped and the plant
automatically reduced power to about 78%. Following recovery of the "A" RFPT
on July 12 the plant operated near full power for the remainder of the
inspection period.
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I. Doerations
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01
Conduct of Operations
01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent
reviews of ongoing plant operations.
In general, the conduct of
operations continued to be professional and safety-conscious.
01.2 Reactor Feedwater (FW) Pumn Turbine Overspeed Trio
a.
Inspection Scone (71707. 92901)
On July 11,1996, at 5:34 a.m., with the plant at full power, the "A"
Reactor Feedwater Pump Turbine (RFPT) tripped on overspeed. The
inspectors reviewed records of the transient, inspected plant equipment,
observed equipment maintenance, and interviewed plant personnel.
b.
Observations and Findinas
When reactor water level dropped to level 4, the plant responded as
expected by automatically reducing power to about 78% and starting the
motor driven feedwater (MDFW) pump.
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Heater isolated due to water level control problems.
Operations
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personnel promptly restored the FW heater and stabilized the plant
without further incident. Reactor water level was restored to normal
operating level by the remaining steam driven FW pump and the MDFW pump.
A reactor engineer was called to the plant and promptly verified that
the reactor power and core flow relationship did not require an
immediate power or fiow change. He also verified that power could be
increased to match the available FW capacity. Maintenance and
engineering personnel later determined that the overspeed trip had been
caused by an electronic failure in the speed governing circuit.
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c.
Conclusions
The operators performed well in response to the plant transient. The
plant equipment responded well to the significant reduction in feedwater
to the reactor vessel. Operations was promptly and appropriately
supported by maintenance and engineering personnel.
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02
Operational Status of Facilities and Equipment
02.1 Eauioment Deficiencies not Identified by the Licensee
a.
Insoection Scope (71500. 71707. 92901)
During the inspection period the inspector's observed that management
had emphasized improved communications related to routine plant
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inspections and followup. However, the inspectors identified several
deficient plant material conditions that had not been effectively
communicated to the appropriate licensee personnel.
b.
Observations and Findinas
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On July 11, when the "A" Reactor Feedwater Pump Turbine (RFPT) tripped
on overspeed, the MDFW pump started automatically.
Both the MDFW pump
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and RFPT, although not safety-related, were important equipment for
protecting the reactor core during some postulated accidents. While the
MDFW pump was running, the inspectors noted an oil leak on the motor and
brought it to the attention of an engineer in the vicinity and the shift
supervisor. The inspectors also identified a high vibration on the lube
oil sump cover of the "A" RFPT after it had been restarted. The shift
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supervisor determined that the main lube oil pump was causing the
vibration and the inspectors confirmed that the vibration levels were
reduced to normal after the licensee had shifted to the auxiliary lube
oil pump.
The shift supervisor also informed the inspectors that he
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planned to discuss the observed conditions with his nonlicensed
operators to clarify his expectations for the identification and
reporting of abnormal plant conditions.
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The next week the inspectors determined that personnel working on the
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MDFW pump motor had not received a detailed description of the oil leak.
The inspectors also encountered a technician who was looking for a lube
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oil pump to take vibration readings on, but he did not know which pump.
On June 12, the inspectors identified an oil leak that had sprayed from
the inlet flange of the Division 1 Emergency Diesel Generator (EDG) lube
oil cooler.
Following discussions with the shift supervisor and system
engineer, it was found to have been only observable and distributed when
the high volume room ventilation fan was running. The leak had been
previously identified, however the work request had been cancelled for
unknown reasons.
The inspectors observed the "fix-it-now" team correct
the leak by tightening the flange bolts.
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On July 11, the inspectors questioned the shift supervisor about a
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deficiency tag on an annunciator window for one of two local control
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panels for the safety-related drywell hydrogen control compressors. The
deficiency tag indicated that a normally lighted annunciator enclosure
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had been degraded by heat from the annunciator lamps.
In response to
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the inspectors' questions, the shift supervisor determined that there
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were additional similar problems with annunciator windows. The
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inspectors verified later that the annunciators windows had been
repaired.
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On July 15, the inspectors notified the shift supervisor and the system
engineer of a black oily residue on the drain funnel for the air
receiver common drain line in the Division II EDG room, with a similar
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residue spattered on the surrounding area. Although it had no impact on
EDG operability, this abnormal condition was clearly visible and it
should have been identified as an equipment deficiency.
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On July 22, the inspectors observed water leaking onto the floor from
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the hotwell pumps. The inspectors notified the duty radiation
protection technician, who had not been informed of the leak. The
licensee determined that the water was not radioactively contaminated.
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Throughout the inspection period, the inspectors observed numerous other
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deficiencies that had been identified by licensee personnel from various
organizations. The inspectors also noted that maintenance activities
were slowly improving plant materiel condition.
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c.
Conclusions
Although the conditions observed did not have any impact on equipment
operability, the fact that they were identified by the inspectors
indicated that plant personnel, including non-licensed operators, health
physics technicians, fire watches, and managers who perform housekeeping
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inspections had not always identified the conditions or kept appropriate
personnel fully appraised of deficient plant conditions. Many other
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deficiencies identified and addressed by the licensee from various
organizations indicated that this problem was limited.
Communications
through the organization to personnel who followed up on the MDFW pump
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oil leak and the RFPT vibration were weak. The deficiency tag on the
hydrogen control compressor control panel did not address the extent of
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the deficient conditions. The licensee's reactions to the reported
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conditions were prompt and appropriate, as were their follow up actions.
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04
Operator Knowledge and Performance
04.1 Operator Errors Affected Operation of the Electrical System
a.
Inspection Scope (71707. 92901. 93702)
On July 3, a nonlicensed operator inadvertently tripped open a motor
control center (MCC) feeder breaker while instructing an operator
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trainee.
Later the same day a safety-related direct current (DC) system
was incorrectly configured.
In both cases, the inspectors responded to
the control room and/or associated spaces to verify that the operators
had taken appropriate actions.
In addition, the inspectors reviewed
related procedures, maintenance history, and evaluations; and
interviewed the operations manager, superintendent and individuals
involved.
04.1.1 Inadvertent Trio of an MCC Feeder Breaker
b.
Observations and Findinas:
The nonlicensed operator and the trainee stated that the operator had
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placed his hand on the face of the breaker over the trip button, but had
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not pushed it in, and that they were surprised that the breaker had
tripped. This had occurred while the operator was showing the trainee
how a breaker would be tagged out. The nonlicensed operator was
experienced and the trainee was an experienced engineer who was in the
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SR0 license training program.
The inspectors independent review of this
event did not reveal any equipment conditions or configuration::, such as
the trip button protruding from the face of the breaker, that could have
caused the trip to occur. The breaker that had tripped was reset and
tripped several times after the event with no problems. The licensee
indicated that on rare occasions that this type of breaker would trip
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without the button being depressed and that the only postulated
explanation was that it may not have been fully reset. The licensee
considered such breaker trips to be isolated random occurrences with no
available corrective actions because of the rarity of the occurrences
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and the fact that once a breaker had tripped with minimal or no known
force it had not been possible to identify the trip mechanism's prior
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configuration.
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04.1.2 Electrical System Placed in Incorrect Confiauration
b.
Observations and Findinas:
On the evening of July 3 the unit supervisor (US) directed the operating
crew to cross tie the Unit 1 and Unit 2 direct current (DC) electric
supply busses for Division 2.
The US had misread the system operating
instruction (S0I) and did not declare the Unit 1 bus (ED-1-B) inoperable
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as required by the S01. Three other operators had asked the US about
the appropriate status of Bus ED-1-B, but he assured them that he had
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checked the procedure and that there was no problem.
The other
operators did not review the procedure or ask the US to further explain
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his conclusion, and the US did not recognize the questions as
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indications that he might have misread the procedure. The more
experienced shift supervisor (SS) was aware that his US had directed the
bus lineup cnange, but did not review the details with him. The US who
misread the 501 had been a US for about 3 months and before that he had
been a licensed reactor operator and a nonlicensed operator.
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S01-R42 (Div 2), "DIV 2 DC DISTRIBUTION, BUSSES ED-1-B AND ED-2-B:
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BATTERIES, CHARGERS, AND SWITCHGEAR," Revision 0, Subsection 7.2.2, Step
2, directed Bus ED-1-B be declared inoperable. The US stated that he
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thought that the SOI required Bus ED-2-B be declared inoperable instead
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of Bus ED-1-B.
Declaring Bus ED-2-B inoperable had no impact on plant
operation since it was a Unit 2 bus and all its loads had been isolated
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for MCC cleaning. The US's failure to declare Bus ED-1-B inoperable was
a failure to follow procedure. This was a violation (50-440/96005-01)
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of Technical Specification 6.8.1 which required that written
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instructions be implemented for changing modes of operation of the DC
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system. The potential safety consequences of this violation were minor
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because the licensee had already fortuitously isolated the loads from
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Bus ED-2-8 and the indication that had not been isolated had not
threatened the operability of Bus ED-1-B.
As corrective actions the licensee provided the US and SS with formal
coaching and counseling. The licensee also promptly trained each
operating shift on initial lessons learned from the event. The
inspectors reviewed the training with the operations manager and
verified that the importance of communications follow through and
feedback had been emphasized and that expectations had been reinforced
for responding in appropriate detail to questions.
The operations
manager also recognized that he needed to continue to insure that the
organizational hierarchy did not become a barrier to questioning
attitudes, requests for detailed explanations, and appropriate feedback.
The inspectors initially reviewed this event on July 5 and verified that
the DC busses had been properly restored. The inspectors reviewed the
licensee's draft Human Performance Enhancement Systems (HPES) evaluation
of the event. The final report had not been completed at the end of the
inspection period. The licensee also planned to review the completed-
HPES evaluation for any additional corrective actions. This licensee
identified and corrected violation is being treated as a Non-Cited
Violation, consistent with Section VII.8.1 of th:: NRC Enforcement Policy
(60 FR 34380, June 30, 1995).
c.
Conclusions
The operators who caused both events did not adequately consider their
actions before taking them. The cperators who questioned the US
displayed an appropriate questioning attitude but did not follow through
on their questions. The licensee's initial response to the events was
prompt and appropriate.
07
Quality Assurance in Operations
07.1 Licensee Self-Assessment Activities (40500)
a.
Inspection Scope
The inspectors' reviewed the following self-assessment activities that
addressed multiple functional areas, as well as operations:
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Routine Plant Operations Review Committee (PORC) Meeting
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Special PORC Meeting prior to startup from the forced outage
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caused by the failure of the auxiliary transformer
" Mini Integrated Performance Assessment Process (IPAP)" exit
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meeting
Potential Issue Forms (PIF)
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b. Observations and Findinas
The meetings were attended by appropriate personnel and there was
substantive discussion of the topics covered. More than 300 PIFs were
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written by a variety of personnel who represented a wide cross section
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of plant organizations. Many of the PIFs demonstrated a good
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questioning attitude, provided valuable insights into methods of
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improving performance, or challenged accepted practices.
For example:
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QA review of implementation of the operations fuse policy (PIF 96-
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2475)
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An engineer questioned a part of the recently implemented improved
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technical specifications (PIF 96-2540)
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A shift supervisor questioned the material condition of a Unit 2
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electrical cubicle, even though the condition had been accepted
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for years (PIF 96-2522)
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Contract assessment specialists and licensee personnel used the NRC IPAP
inspection module as a basis for a self-assessment of plant activities
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that was primarily focused on operations, maintenance, and corrective
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actions.
Important issues, such as a reluctance by some individuals to
write a PIF, were developed for corrective actions.
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c.
Conclusions
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The licensee used a variety of self-assessment techniques to identify
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issues that required corrective actions. However, the inspectors
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observed other deficient plant conditions (Sections 02.1, M2, and F5)
that had not been identified. This indicated that not all personnel
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consistently utilized'the licensee's self-assessment techniques.
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II. Maintenance
M1
Conduct of Maintenance
M1.1 General Comments
a.
Inspection Scope (62703. 61726. 92902)
The inspectors observed the conduct of maintenance and surveillance
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testing during routine plant operation and forced outrge activities.
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b.
Observations and Findinas
The inspectors observed some examples of weaknesses in communications
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and work planning situations (see Section M4.1).
Similar weaknesses
have been identified in the past.
Licensee managers emphasized the risk
significance of a scheduled reactor core isolation cooling (RCIC)
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maintenance outage. As a result, the licensee identified problems with
a modification that was planned to be completed during the outage.
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Licensee managers concluded that all required materials would not be
available and deleted the work from the outage the week before the
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outage. The remaining work was planned for completion within 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br />
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and was actually completed within 44 hours5.092593e-4 days <br />0.0122 hours <br />7.275132e-5 weeks <br />1.6742e-5 months <br />.
The inspectors observed the
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licensee conduct a thorough critique of the outage with good preparation
for the critique by the system engineer and broad participation in the
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critique, including managers who were present.
The inspectors observed all or portions of the following surveillance
tests:
SVI M17-T410A Containment Vacuum Breaker Functional
SVI C51-T0027 Average Power Range Monitor Trip Functionals
SVI R42-T5221 Division III Quarterly
SVI P53-T6305 Air Lock Seal Test
TXI 248
Control Room Heat Load Train A
TXI 249
Control Room Heat Load Train B
Surveillance procedures were appropriate for testing conditions and
correctly identified parameters needed to verify proper equipment
performance. Test personnel followed the procedures during the observed
testing and equipment problems were promptly identified and resolved.
The inspectors observed the performance of TXI-249, which was the first
performance of a new surveillance which was going to be required by the
improved technical specifications. The test provided a more detailed
verification of the cooling function of the control room emergency
ventilation system. The licensee's pre-test briefing was thorough with
broad participation in the discussion of the expected equipmeat
performance and potential problems. The responsible system engineer was
well prepared for the briefing and actively monitored test performance.
The equipment performed as required by the improved technical
specifications and the UFSAR.
c.
Conclusions
All activities observed were conducted in a professional manner, tagouts
were appropriately completed, engineering and management involvement was
apparent.
Licensee personnel aggressively pursued corrective actions
for previously identified weaknesses in work planning and timely
execution of work.
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M2
Maintenance and Material Condition of Facilities and Equipment
a.
Insoection Scope (71707. 92720)
The inspectors conducted plant walkdowns throughout the inspection
period that identified plant material condition problems. The
inspectors also reviewed other licensee-identified problems.
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b.
Observations and Findinas
During maintenance activities the licensee discovered foreign materials
in two nonsafety-related pumps. A piece of a metal file was found in
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the RCIC water leg pump coupling and an extra set screw was found loose
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in a control rod drive water pump which had been refurbished off-site.
Each case was documented for further evaluation.
A lack of adequate lighting on the refuel floor in containment delayed
maintenance activities on a containment vacuum breaker (see Section
M4.1).
Also, the inspectors identified a rubber scaffolding pad on the
containment shell that had been left from the recent refueling outage.
Earlier in the inspection period, during an NRC management inspection of
the plant, NRC managers found duct tape on a piping flange associated
with a residual heat removal valve in containment and an abnormally high
quantity of oil from leaks on the Division I and II EDGs.
The inspectors also identified several equipment deficiencies discussed
in E tions 02.1, M2, and F5.
c.
Conclusions
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The licensee usually identified and corrected materiel condition
deficiencies.
Personnel were sensitive to the importance of documenting
problems with foreign material exclusion. However, some obvious
deficiencies identified by the NRC indicated that some personnel had not
taken appropriate actions to identify and correct deficiencies.
M3
Maintenance Procedures and Documentation
M3.1 Maintenance Rule Proaram Implementation
a.
Inspection Scope (62703)
On July 3, 1996, the licensee implemented its program for complying with
the NRC maintenance rule. The inspectors reviewed various documents
associated with the maintenance rule, interviewed personnel, and
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observed administrative controls of maintenance activities to confirm
implementation of the licensees maintenance rule program.
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b.
Observations and Findinas
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Revision 2 of procedure PAP-1125, " Monitoring the Effectiveness of the
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Maintenance Program Plan," became effective on July 3,1996. The
licensee trained personnel on the impact of the maintenance rule and
provided informal reference material to familiarize personnel with the
maintenance rule requirements. The inspectors observed that corrective
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actions had been taken as a result of a maintenance rule implementation
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self assessment. The inspectors verified that the licensee had
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developed a list of systems subject to the maintenance rule and had
evaluated past performance of those systems.
The inspectors also
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verified that licensee managers emphasized the maintenance rule
implementation goal of maximizing availability of equipment within the
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scope of the rule.
c.
Conclusions
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The licensee developed a program implementing the maintenance rule prior
to the deadline established in the rule. A strong effort was made to
familiarize personnel with the requirements of the program and managers
were sensitive to the risk implications of maintenance activities.
N4
Maintenance Staff Knowledge and Performance
M4.1 Failure to Promotiv Identify a Condition Adverse to Quality
a.
Inspection Scooe (62703. 92902)
The inspectors observed troubleshooting and rework activities to correct
dual position indication in the control room for containment vacuum
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breaker valve IM17-F010. The inspector later followed up on the
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completion of the associated Work Order 960002479.
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b.
Observations and Findinas
On July 22, the inspectors observed the work process, including a
thorough supervisory briefing and technician review of the package. The
briefing took place about 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after the valve had been taken out of
service by operations. Additionally, as a result of an earlier job
walkdown, the work package stated that the work area was poorly lighted.
Even though this was noted in the work package, there was an additional
hour delay in starting work due to the need for temporary lighting.
Once the vacuum breaker was opened, the inspectors independently
verified that the associated containment isolation valve was closed,
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which isolated the penetration from outside atmosphere.
In troubleshooting the vacuum breaker valve the technicians identified
that a linkage arm connecting the position indicator and the valve was
bent, preventing accurate position indication. The technicians stated
that this condition had occurred before and resulted from local leak
rate testing (LLRT) of the vacuum breaker valves during plant refueling
outages.
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The inspectors discussed the situation with the maintenance technicians
and supervisors, operations management, and the system engineer and
questioned why a PIF was not written.
Licensee personnel acknowledged
that communication had not occurred promptly for the problem with the
containment vacuum breaker and the potential for similar problems with
the other vacuum breakers.
Subsequently, two PIFs were written to
address the issue.
PIF 96-2573 was written on July 24 and taken to the
control room the same day.
PIF 96-2578 was written on July 23 and taken
to the control room on July 25.
c.
Conclusions
Based on the information that maintenance personnel had about the
problem related to the vacuum breaker indications, a PIF should have
been written promptly on July 22 and taken to the control room the same
day for review and evaluation.
Delaying the initiation of the PIF
needlessly delayed the start of the corrective action process.
Failure
to promptly communicate the potential problems with containment vacuum
,
breaker valve indications resulting from a known deficiency in the
performance of the associated LLRT was a tiolation (50-440/96005-02) of
i
10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action," which
~
requires that measures be established to assure that conditions adverse
to quality such as deficiencies are promptly identified and corrected.
M7 Quality Assurance in Maintenance Activities
M7.1 Maintenance Self Assessment
a.
Insoection Scone (40500)
While observing maintenance activities associated with a containment
vacuum breaker (see Section M4.1), the inspector observed a two person
team associated with a maintenance self assessment program. The
inspectors also reviewed the reporting of findings associated with the
work activities.
b.
Observations and Findinas
The objective of the self-assessment was to identify specific areas
neeaing improvement in the Maintenance Section. The self-assessment
involved seven teams that would observe work activities over a 2 week
period. The team observed by the inspector consisted of a maintenance
supervisor and a plant helper.
Both team members demonstrated
understanding of the objective and an inquisitive perspective toward
ongoing maintenance activities. The team members had several findings
which were reported collectively with the other teams at the end of the
work day.
13
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c.
Conclusion
This portion of the inspection occurred close to the end of the
'
inspection period. Therefore, overall conclusions would be
inappropriate however, the self-assessment efforts had potential for
identifying areas for improvement in maintenance activities.
I
III. Enaineerina
El
Conduct of Engineering
El.1 Modification Alters Safetv-Related System Response
"
a.
Insnection Scone (37551. 40500)
'
The inspectors evaluated a self-identifying concern with a modification
,
to the Leakage Control System (LCS) completed during the recent-
{
refueling outage (RF05),
b.
Observations and Findinas
.
During a review of simulator operations the licensee observed that the
l
'
Reactor Core Injection Cooling (RCIC) system isolated during a simulated
loss of electrical power to the General Electric (GE) Nuclear
!
Measurement Analysis and Control (NUMAC) steam leak detection monitor
equipment. The modification that installed the NUMAC equipment had been
submitted by the licensee to the NRC for review and a safety evaluation
review had been written.
Prior to installation of the NUMAC equipment,
RCIC did not isolate on a loss of power accident. The licensee found
'
that a relay which prevented RCIC isolation in the previous design had
been removed when the NUMAC design was installed. The licensee
concluded that RCIC remained operable and capable of performing its
.
'
designed function. NRR and Region III independently reviewed the
!
licensee's operability determination and concluded, based on the initial
information available, that the licensee was in compliance with the
Technical Specifications. The inspectors also determined that the
licensee had written a UFSAR request to be submitted as part of the
,
routine update submittal. The licensee had not completed its
!
investigation at the end of the inspection period. The licensee planned
i
to include a review of other plant modifications where similar concerns
,
may exist.
c.
Conclusions
The changes introduced by this modification were of concern because the
RCIC system, a safety-related system required by technice.1
,
specifications, would no longer perform in the manner that operators
'
were trained to expect. This is an Unresolved Item (50-440/96005-03)
'
pending the inspectors' review of the licensee's investigation.
14
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E2
Engineering Support of Facilities and Equipment
,
i
E2.1 Generic letter 89-10 Proaram Imolementation
a.
Inspection Scope (TI 2515/109)
g
This inspection evaluated the process for qualifying the design-basis
capability of motor-operated valves (MOVs) and closure of GL 89-10
review. The inspection concentrated on MOVs that were tested under
static or low differential pressure (dP) conditions. A valve sample
that included several program closure methods used by Perry was selected
to verify design-basis capability. The inspectors reviewed design-basis
documents, thrust calculations, test packages, and engineering
evaluations for the MOVs listed below:
i
1E12-F024A Residual Heat Removal "A" Test Valve to Suppression Pool
IE12-F0028B Containment Spray "B" First Shutoff
IE12-F0042B Low Pressure Core Injection "B"
Injection
1G33-F0040 Reactor Water Cleanup Return Header Inboard Isolation
IM51-F0090 Combiner Gas Dry Well Purge Inboard Isolation
IP54-F0340 Containment CO, Supply Isolation
OP42-F0295A Control Complex Chiller "A" Crosstie Isolation
IM17-F0025 Containment Vacuum Relief Isolation
The inspectors also reviewed other Perry documentation used to justify
program assumptions, such as stem friction coefficients and load
sensitive behavior.
Further, the inspectors reviewed documentation
related to program issues, such as periodic verification, post-
maintenance testing, and program audits.
b.
Observations and Findin u
E2.1.1 Proaram Scope Chanaes
'
A previous inspection report (50-440/95006) questioned the
appropriateness of allowing manual versus automatic operation of certain
spent fuel pool cooling system valves that the licensee had previously
removed from the program. The NRR staff found that manual operation of
the valves after a design-basis accident was acceptable, and therefore
the valves do not need to be dynamically flow tested in accordance with
Since the previous inspection, seven valves were removed from the
program. The inspectors determined that two valves, IP22-F015 (Mixed
Bed Water Drywell Supply Isolation) and IP51-F652 (Drywell Outboard
Isolation Valve for Service Air System), were inappropriately removed
since surveillance stroke-time testing was performed without declaring
the valves inoperable. The NRC staff position is that an M0V placed in
a position that prevents the safety-related system (or train) from
performing its safety function must be capable of returning to its
safety position, or the system (or train) must be declared inoperable.
15
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The licensee opted to keep both valves out of the program and plans to
declare the valves inoperable during the surveillance testing.
With the removal of these valves, the program scope consisted of 154
MOVs including; 76 gate,_34 globe, and 44 quarter-turn (butterfly)
valves.
From this population, the licensee was able to dynamically test
64 MOVs.
E2.1.2 MOV Sizina and Switch Settinas
Perry's thrust calculations utilized the industry's standard thrust
equation to determine thrust requirements for rising stem gate and globe
valves.
For rising stem MOVs that had been dynamically tested, measured
nominal valve factors were used. Non-dynamically tested gate valves
relied on the application of test data that was obtained from in-plant
testing, testing performed by EPRI, or other industry sources. The
licensee used a 15% bias margin to address MOV load sensitive behavior
j
(see below) for rising stem MOVs that were not dynamically tested. A
1
'
bias margin of 10% was included to account for potential future valve
degradation. Minimum thrust requirements for setting of actuator torque
j
switches were adjusted to account for diagnostic equipment inaccuracy
and torque switch repeatability.
E2.1.3 Valve Factors
Measured valve factors (VF) were used for dynamically tested rising stem
l
<
MOVs.
Perry had divided MOVs into groups based on valve manufacturer,
valve type, and ANSI pressure class rating.
Some groups had been
divided into subgroups based on valve size.
Perry used in-plant data
first, and then data from industry testing for justification of VFs for
,
non-dynamically tested MOVs.
l
'
Assumed VFs used in the design thrust calculations were generally
adequately justified for the 13 rising stem valve groups, although some
i
weaknesses were noted as discussed below.
'
,
Valve Group 6 - Close Direction (6" Borg Warner 1500# Gate
.
Valves):
This sub-group consisted of five MOVs; none were
dynamically tested.
Perry had applied a 0.50 VF based on EPRI
performance prediction methodology (PPM) results performed on two
MOVs (IG33-F001 and 1G33-F004) that could potentially experience
steam blowdown conditions due to postulated line breaks outside
containment. However, the inspectors noted that the identified
design-basis conditions for IG33-F039 and IG33-F040 varied from
the system parameters used by the PPM analysis for IG33-F001 and
IG33-F004. Therefore, there was some uncertainty that the
existing PPM data was applicable to IG33-F039 and 1G33-F040. The
lowest margin valve in this grov (1G33-F040) had an available VF
.
of 0.618, after accounting for diagnostic equipment uncertainty,
torque switch repeatability, load sensitive behavior, and margin
for valve degradation.
Perry personnel were evaluating the
potential for revising the existing PPM analysis using the
i
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4
alternate system parameters.
Further, this valve was scheduled to
l
be modified during the next scheduled outage as part of Perry's
i
margin improvement program.
,
Valve Group 3 (4" Anchor Darling 900# flex-wedge gate valves):
.
,
This group had only two MOVs (IE22-F012 and IE51-F059). The
inspectors noted that only lE51-F059 was dynamically tested in the
closed direction, which yielded a VF of 0.28.
The inspectors
'
l
noted that the closed VF justification for this group did r>ot meet
j
the intent of the GL 89-10 Supplement 6 recommendation to
j
dynamically test 30% of a valve group (no less than two).
The VF
results from at least two MOVs are needed to have reasonable
!
assurance that MOVs in the group perform in a similar manner.
l
Perry had applied a 0.45 VF for 1E22-F012 and had also determined
3
that, after accounting for diagnostic equipment uncertainty,
~
torque switch repeatability, load sensitive behavior, and a 10%
margin for valve degradation; the current settings for IE22-F012
could support a VF of 0.552. Open stroke dynamic testing of IE22-
-
!
F012 had resulted in an open VF of 0.38.
While the inspectors did
l
not identify any operability concerns with this valve group, as
i
part of the ongoing periodic verification program, Perry will
)
[
continue to evaluate applicable VF information to cor. firm the
'
l
close VF assumptions used for this group.
!
Similarly, the VF justification for some subgroups of Groups 4 and
i
.
6 (4" and 12" Borg Warner 300# gates, 4" and 6" Borg Warner 1500#
gates, and 12" Borg Warner 1500# gates) relied either on a single
1
dynamic test or a single EPRI test and therefore the subgroup did
i
not meet the recommendations of GL 89-10, Supplemant 6.
Although
.
these valves were acceptable based on adequate capability margin,
3
1
the licensee will continue to evaluate applicable VF information,
~
1
particularly for these valve groups, as part of their periodic
j
verification program.
The inspectors noted that Perry had not incorporated the tested
i
.
open VF for IE12-F028B into the thrust calculation.
The
inspectors also noted that this higher VF should have been used in
,
j
the thrust calculations for the three other MOVs in Valve Group 4.
Perry personnel agreed and initiated a design change control
,
document to correct these calculations.
Becaur.e of the small
difference in VFs, the change will have little effect on the
available thrust margin. The inspectors considered the licensee's
actions to correct this issue to be acceptable.
E2.1.4 Load Sensitive Behavior
Rising-stem MOVs that were dynamically tested were evaluated using the
measured load sensitive behavior margin.
Evaluation of non-dynamically
tested MOVs relied on analysis of Perry's load sensitive behavior data
that determined the mean and the standard deviation of the test results.
Based on Perry's use of FelPro N5000 stem lubricant, a load sensitive
behavior margin of 15% was used in the thrust calculations. The
17
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inspectors found the licensee's assumptions for gate valves to be
adequate. However, Perry determined that the globe valves had an
average load sensitive behavior margin of 15.79%, with a standard
deviation of 12.02%. Based on this performance, the inspectors
considered the licensee's assumed load sensitive behavior margin of 15%
unacceptable for globe valves.
Perry personnel pointed out that all
globe valves had been dynamically tested with actual load sensitive
behavior margins incorporated into the current thrust calculations.
However, Perry personnel agreed that the program documents should be
revised to include a globe valve load sensitive behavior assumption that
better represented existing plant data.
Based on implementation of the
measured load sensitive behavior test data, the inspectors considered
the licensee's globe valve load sensitive behavior margins to be
adequate.
E2.1.5 Stem Friction Coefficient
The inspectors found the licensee's open stem friction coefficient (SFC)
assumption of 0.20 to be adequate based on test data reviews.
The close
SFC assumption of 0.15 was acceptable based on available margins but the
test data was not as well supported statistically.
Perry is expected to
continue to review SFC performance under the tracking and trending
program and under the periodic verification program to further confirm
the SFC assumptions.
E2.1.6 Toraue Switch Repeatability
The inspectors considered Perry's methods for addressing torque switch
repeatability to be adequate for program review closure.
Perry's
program documents typically followed the guidance contained in
Limitorque's Maintenance Update 92-2; however, in cases where more
margin was desired, Perry used values based on 200 diagnostic plant
tests. The performance of each actuator size (for a given spring pack
and dial setting) was analyzed statistically to determine greater than
97% confidence values for each actuator. The results from this study
were applied to only 13 gate and globe valves.
E2.1.7 Butterfly Valve Testina
Design-basis capability for butterfly valves was appropriately based on
27 dynamic diagnostic tests with the untested valves grouped in
accordance with GL 89-10, Supplement 6, requirements. Six untested
butterfly valves were either in very low dP water conditions (less than
16 psid) or in air systems (less than 1 psid). With the exception of
two valves, analytical margins for all butterfly valves were greater
than 30%. The remaining two valves had adequate margins of 14% and 27%.
E2.1.8 Periodic Verification of Desian-Basis Capability
Perry planned to statically test all MOVs at least once every six fuel
l
cycles with increased frequencies based on valve margin and risk
priority. Dynamic testing of valves will also be based on valve margin
18
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_
and valve risk priority.
Eleven valves were scheduled for periodic
verification (PV) dynamic testing during fuel cycle 6.
Further, as a
minimum, Perry intends to dynamically test cae gate, one globe, and one
butterfly valve each fuel cycle. The same three valves are planned to
be tested each fuel cycle to monitor for chanles over time.
The NRC staff is preparing a generic letter (Gl.) on PV of MOV design-
basis capability and will review the PV program in greater detail
following issuance. As stated in the Generic letter consideration of
the benefits (such as identification of decreased thrust output and
increased thrust requirements) and potential adverse effects (such as
accelerated aging or valve damage) when determining appropriate periodic
verification testing for each program valve needs to be considered.
E2.1.9 Trackina and Trendina of Failure. Maintenance. and Diaanostics
Perry's tracking and trending program was considered to be a strength to
the overall MOV program. The program documented in FTI-0028, "MOV
Tracking and Trending," Revision 1, appeared well established with
thorough procedural and programmatic required actions. The program was
supported by a computer database and the inspectors determined that the
licensee's trending prugram appeared capable of tracking and evaluating
data to maintain MOV design-basis capability. The program was capable
of analyses of a comprehensive range of parameters (diagnostic, failure,
preventive maintenance, and corrective maintenance) by individual valve
as well as by group or other subset. Compilation and evaluation of
trends was prompted after every maintenance or testing activity and was
required via trending reports every 2 years (or after each refueling
outage) which described recommended actions and feedback.
The
licensee's program included the M0V failure codes developed by the MOV
Users Group (MUG).
A review of selected MOV-related PIFs generated over the last year
indicated that, overall, MOV failures were appropriately reviewed and
dispositioned. Direct involvement of the M0V engineering team was
evident and was considered instrumental in identifying and correcting
problems, and where applicable, in determining root causes and
implementing corrective action to preclude repetition.
E2.1.10 Post-Maintenance Verification /Testina (PMT)
Post-maintenance verification / testing requirements as documented in FTI-
F0036, "PMT Program Matrix," Revision 2, were found acceptable for
program closure. The licensee had appropriately established static and
dynamic test requirements and controls for use after MOV maintenance and
modifications.
c.
Conclusions
All significant issues related to Perry's M0V program have been
resolved; therefore, the GL 89-10 program review will be closed.
Program documentation, test data and margin improvement plans provided
19
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.
.
,
an adequate basis to conclude that all GL 89-10 program MOVs would
perform their intended safety functions under worst-case design-basis
conditions.
The inspectors noted that Perry had a capable technical M0V
staff with a well organized and well documented program.
E2.2 Transformer Failure Evaluations
'
a.
Jaspection Scone (37551. 71707. 92901. 92903)
4
The inspectors interviewed licensee personnel and reviewed documents in
order to assess the licensee's evaluations of transformer failures.
b.
Qbservations and Findinas
Near the end of the previous inspection period balance-of-plant (B0P)
transformer LFIC failed while being energized. The resulting electrical
transient contributed to the failure of the Unit 1 Auxiliary Transformer
which led to a reactor scram. Two dayo later another B0P transformer
failed while being deenergized. Due to the transformer failures the
licensee organized a panel of transforner experts with a variety of
related backgrounds. The panel reviewed the recent failures, other
industry experience, and current transformer inspection and test
results.
The licensee sent the two 13.8 kilovolt (kV) to 480 volt alternating
current (VAC) B0P transformers that failed to a manufacturer's facility
for evaluation. The manufacturer determined that the transformers had
failed due to the effects of electrical corona. This determination was
supported by the evaluation of an independent consultant.
Corona can
,
occur in dry-type transformers operating at greater than 10kV, causing
degradation of the insulation. Higher temperatures can accelerate this
effect. When the transformers are energized and deenergized during
switching operations the electrical transients can cause the degraded
insulation to fail.
Based on this information the licensee instructed
operations to minimize switching operations associated with the
transformers. They have also energized all available transformer
cooling fans to reduce operating temperatures and were planning to
purchase equipment which could monitor transformers for corona
indications.
The expert panel also determined that the safety-related 4160 VAC to 480
,
VAC transformers should be considered for replacement even though there
had been no failures at Perry. The inspectors observed an inspection of
a Unit I safety-related transformer by members of the expert panel.
They confirmed that the transformer, which operated at lower
temperatures than the failed transformers, had not been degraded by the
corona effect. One energized Unit 2 transformer identical to the
safety-related transformers was deenergized and shipped off site for
additional evaluation because it was observed to be making a louder
noise than the others.
20
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The licensee had the failed auxiliary transformer disassembled and
inspected on site by a consultant.
The consultant concluded that the
transformer had failed due to design weaknesses, material deficiencies,
'
and poor craftsmanship. The Unit 2 Auxiliary Transformer, which had
been installed in place of the failed transformer, was also manufactured
by McGraw Edison about 14 months later than the Unit I transformer.
However, the licensee could find no evidence of improvements in
identified weaknesses during that time.
Since there was no known
-
testing method that would identify the defects observed in the Unit 1
Auxiliary Transformer the licensee could not tell if the Unit 2
'
transformer had similar defects. Therefore, they had begun a search for
a replacement transformer.
.
Tha Unit 1 Startup Transformer, which had failed on February 5,1996, as
a result of a spurious fire protection system deluge actuation, had been
sent offsite for repairs. Once initial repairs were completed, the
I
transformer failed its post repair testing and had to be rewound. The
licensee estimated that the transformer would not be returned to the
4
site until February 1097.
The licensee planned to begin replacement of 13.8 kV to 480 VAC
transformers in October 1996. The manufacturer claimed that the new
transformers will be less susceptible to the corona effect.
c.
Conclusions
Although several transformer failures occurred over the last 6 months,
the availability of replacements from the abandoned Unit 2 allowed
continued operation with no reduction in electrical system redundancy.
Inspections of the current safety-related transformers indicated no
i
duplication of the problems experienced with the B0P transformers. The
'
licensee responded conservatively and aggressively to the failures.
E2.3 Review of Vodated Final Safety Analysis Report (UFSAR) Commitments
a.
Inspection Scope
While performing the inspections discussed in this report, the
inspectors reviewed applicable portions of the UFSAR that related to the
areas inspected.
Several inconsistencies were noted between wording of
the UFSAR and the plant practices, procedures, and parameters observed
by the inspectors,
.
b.
Observations and Findina
E2.3.1 UFSAR Table 5.4-2, " Design Parameters for RCIC Components," listed the
valve operation dP requirements for the RCIC pump discharge valve 1E51-
2
F013 as 1400 psi for opening or closing strokes. This contradicted the
GL 89-10 maximum expected design basis dP of 1247 psid with an active
design safety function to open only. Similar discrepancies were noted
for other valves listed in UFSAR Section 5.4, " Reactor Coolant System
and Connected Systems" (Component and Subsystem Design).
Perry
21
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4
i
j
contended that the higher dPs in the UFSAR for program valves were
!
considered " design parameters" used as original design sizing values by -
'
the nuclear steam supply system vendor and the architect / engineer and
'
were distinct from GL 89-10 criteria.
Based on a sample review of GL
'
89-10 dPs the inspectors were satisfied that the dPs for the program
valves were adequately determined to be the maximum expected design
i
basis dPs. However, as worded, the UFSAR values may be misleading and
i
without clarification, questions as to whether the facility or
procedures as described in the UFSAR had been changed would continue.
This issue will be reconsidered in the future and is an unresolved item
j
URI (50-440/96005-04).
!
E2.3.2 UFSAR Section 8.3.2.1.2.1 discussed safety-related DC electrical
l
systems.
It stated that " Batteries, battery chargers and distribution
(.
equipment for the Class IE, Division 1 and Division 2, 125-volt dc
'
systems are located in separate, locked rooms...".
The inspectors
,
I
observed that the doors for the battery chargers and distribution
equipment are not locked. There was no discussion in this UFSAR section
!
about benefits of locking the doors. Therefore the discrepancy did not
!
appear to have any potential safety conset,uence. There was no evidence
i
of a safety evaluation being performed for this change. This issue is
j
an an unresolved item URI (50-440/96005-05).
e
!
E2.3.3 UFSAR Section 9.1.4.2.3.5, " Fuel Pool Sipper" briefly discussed the use
,
!
of the fuel pool sipper to concentrate fission gasses as an evolution
,
i
that would be accomplished in the fuel handling building. The
i
inspectors observed that during the last refueling outage a new method
i
of fuel sipping was used that allowed the fuel to be sipped while it was
!
still in the reactor vessel in the containment. There was no evidence
1
of a safety evaluation being performed for this change. This issue is
an unresolved item URI (50-440/96005-06).
1
i
E2.3.4 UFSAR Section 9.3.3.3 discussed flooding of the emergency core cooling
i
system (ECCS) rooms.
It stated that "Each ECCS pump compartment is
i
provided with watertight locked doors...".
The inspectors observed that
the watertight doors were not locked. There was no discussion in this
'.
UFSAR section about benefits of locking the doors. Therefore the
j
discrepancy did not appear to have any potential safety consequence.
l
There was no evidence of a safety evaluation being performed for this
!
change.
This issue is an unresolved item URI (50-440/96005-07).
I
E2.3.5 UFSAR Section 15A.5.3, " Repair Time Rule" discussed restrictions that
must be observed to maintain the validity of assumptions used to
i
!
establish the " repair time rule". The licensee could not verify that it
had observed the restrictions. The potential safety consequence of this
,
issue was not clear at the end of the inspection period.
There was no
S
evidence of a safety eval w :cs being performed for this change. This
j
issue is an unresolved it - UU (50-440/96005-08).
5
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c.
Conclusion
l
The inspectors will evaluate the findings and determine whether a
l
violation of NRC requirements has occurred.
E7
Quality Assurance in Engineering Activities
E7.1 Licensee Self-Assessment Activities (40500)
'
The inspectors reviewed a recent MOV self-assessment along with earlier
documented QA MOV activities. The recent self-assessment was completed
,
i
by consultants knowledgeable in MOV program requirements.
Both the
,
self-assessment and the QA audits provided good technical findings and
a
were beneficial in improving the MOV program.
E8
Miscellaneous Engineering Issues (92720, 92903)
E8.1 Simulator Computer Interaction With Control Room
'
On July 8 while testing a program revision for the simulator computer, a
scenario file was inadvertently started that affected computer screen
3
indications in the control room such as control rod positions and core
l
thermal power averages. The operators determined the information to be
inaccurate based on control panel indications and plant performance.
'
The condition was corrected and a PIF was initiated.
The simulator
computer performed two basic functions:
1) operate the simulator and 2)
provide plant status information during an emergency from the plant
computer to the Emergency Operating Facility computer.
Evaluation of
how the simulator computer altered computer indications in the control
room is an IFI (50-440/96005-09).
E8.2 (Closed) Unresolved Item 50-440/93023-03:
Loss of safety function for
Emergency Closed Cooling Water System.
Corrective actions taken to
ensure proper butterfly valve limit switch set up was accomplished with
revised maintenance procedures, training, and butterfly valve testing
performed in accordance with the licensee's GL 89-10 program. This item
is being tracked with LER 93021.
IV. Plant Suonort
R1
Radiological Protection and Chemistry (RP&C) Controls (83750)
RI.1 Radioactive Material Control Proaram
a.
S.cgn
The inspectors reviewed the performance of the licensee's radioactive
material (RAM) control program for tools and equipment moved within the
Radiologically Restricted Area (RRA). The inspectors interviewed
Radiation Protection, Maintenance, and Quality Assurance personnel to
determine the level of understanding of the program by the general
workforce.
23
b.
Observations and Findinas
Several recent Potential Issue Forms (PIFs) had been generated
addressing RAM storage within the RRA and the RAM control program in
,
general. The documented occurrences suggested that the program was not
fully effective in ensuring that workers 'nad a clear understanding of
the RAM control program (e.g. proper methods of returning tools and
equipment to storage locations).
Personnel interviews indicated that various interpretations of the " hot
tool" return process existed. Some workers believed that all material
'
should be directly returned to the hot tool crib while others indicated
that tools should be returned to the decontamination facility. This
uncertainty appeared to be a significant contributor to material not
being returned to the proper storage locations.
4
The station had identified several programmatic improvement
opportunities; however, these enhancements had not been implemented.
The inspectors will monitor the licensee's effectiveness in implementing
radioactive material control program improvements IFI (50-440/96005-10).
c.
Conclusions
The plant's RAM control program was being adequately implemented;
however, a lack of understanding of the program requirements existed
among the general work force and identified program improvem~its had not
yet been implemented.
RI.2 Review of 1995 Annual Radioactive Effluent Report
The inspectors reviewed the licensee's Annual Environmental and Effluent
Release Report for 1995 submitted to the NRC in April 1996.
The report
appropriately detailed environmental monitoring and radioactive effluent
releases for 1995 and demonstrated that plant operations did not result
in any significant environmental impact.
Effluent releases for 1995
were well below Technical Specification limits. The inspectors noted
that the licensee had continued to effectively implement the
environmental monitoring and effluent release programs.
R2
Status of RP&C Facilities and Equipment (84750)
R2.1 Review of Filtered Ventilation Systems
The inspectors reviewed procedures and performance test results for
selected filtered ventilation trains.
The review also included
inspections of the control room, fuel handling building, and annulus
exhaust gas ventilation systems. The charcoal and freon filter testing
was performed by individuals from the company's BETA Laboratory. The
procedures reviewed were technically sound and performance test results
verified filter train integrity and were performed at the Technical
Specification required frequency. The systems inspected were well
24
J
t
__
...
__ _ _ . _ .
__
.._
maintained. The inspectors concluded that the licensee had an effective
ventilation filter testing program.
R2.2 Review of Process and Area Radiation Monitor Proaram
a.
Scope
The inspectors reviewed procedures, alarm setpoint calculations, and
'
performance data regarding the licensee's process, effluent, and area
radiation monitoring system. The inspectors also observed the material
condition of selected monitors.
b.
Findinas and Observations
Based on reviews of licensee monitor setpoint methodology and
discussions with the Chemistry department staff, the inspectors
determined that a sound basis existed for the determination of radiation
monitor alarm setpoints. The Chemistry department was in the process of
revising procedures governing the radiation monitoring program to more
clearly define technical bases for alarm setpoint methodologies and
streamline the process for establishing setpoints in the field by
chemistry technicians.
A recently performed licensee review of system applicability to the
Maintenance Rule indicated that the Radiation Monitoring System failed
to meet the Reliability Performance Criteria and had been classified an
A(1) system. The review of system performance by the licensee from June
1,1992, to June 1,1996, identified 16 functional failures of various
i
radiation monitors. None of the failures resulted in a reportable
event; however, limiting conditions for operation (LCOs) had been
frequently entered to satisfy Technical Specification required sampling.
The licensee was establishing long term corrective actions to improve
the system's performance. One corrective action already accomplished
was the hiring of a radiation monitor specialist to provide increased
oversight of the program.
c.
Conclusions
The inspectors determined that the process, effluent, and area radiation
monitoring program was being adequately implemented. Technical bases
for alarm set point determinations appeared to be sound; however,
reliability performance of the system warranted improvement.
R2.3 Electronic Dosimeter Performance Monitorina
a.
Scope
The inspectors reviewed electronic dosimeter (ED) performance problems
the plant had recently experienced. This issue had been briefly
mentioned in Inspection Report 50-440/95009.
25
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.
. - -
- .
.-
. - - .
._-
.-.
- -
.
. _ .
.
b.
Observations and Findinas
The Radiation Protection department instituted an aggressive program to
'
monitor the noted problems which ranged frc;:: the EDs " turning off" to
'
erroneous displays on the readout.
Following extensive communications
with the ED vendor, the vendor determined that mest of the problems were
related to the computer software configuration installed at the station
combined with the use of older model dosi:neters. The Radiation
Protection group promptly implemented additional controls for high
radiation area entries to ensure workers were appropriately monitored in
the event of an ED failure while within such areas. The performance
trending had indicated that the failure rate had significantly been
reduced following several software modifications. The inspectors
discussed the problem with vendor representatives to determine if there
was a generic problem with the ED.
The vendor representative indicated
that the problems being experienced at Perry were isolated to that site
due to their unique configuration of the dosimeter software coupled with
the HIS-20 access software and the use of the old model DMC 90
dosimeters.
c.
Conclusions
The inspectors determined that the licensee had effectively monttored,
evaluated, and applied appropriate corrective actions to the ED
performance problems.
R8
Miscellaneous RP&C Issues
R8.1
(Closed) Inspection Followuo Item 50-440/96003-021 Radiation Protection
department response to the inadvertent creation of high dose rates
during Vibration Monitoring Instrumentation Removal (VMIR) activities.
The inspectors reviewed corrective actions taken to preclude recurrence
of creating high radiation dose rates within the upper drywell during
movements of in-vessel components. As discussed in IR 96003, this
incident did not result in any regulatory violation. However, several
program weaknesses were identified that contributed to the incident.
The licensee's review identified several weaknesses within the Radiation
Work Permit (RWP) program, Work Planning and Scheduling methodology, and
with Operations Manual procedures governing in-vessel component
movements.
Corrective actions included enhanced training for Radiation
Protection Technicians, the inclusion of this and similar events into
RWP/ALARA reviews for discussion during planning meetings and pre-job
briefings, and improvements to operations procedures addressing the
movement of in-vessel components.
In addition, improvements were made
to the NRC Information Notice review process to ensure applicability
reviews would be more broadly focused.
These corrective actions
appeared to address the root causes of the original problem.
26
$4
Security and Safeguards Staff Knowledge and Performance
S4.1 Resnonse to Renort of a Bomb
a.
Inspection Scone (71750. 92904)
At about 6:00 p.m. on June 28, the inspectors observed the operations
shift supervisor receive an offsite telephone report in the control room
of a bomb in the plant. The inspectors observed the response of
operating and security shift personnel.
b.
Observations and Findinas
The inspectors verified that the operations shift supervisor promptly
documented the information received and notified the security shift
supervisor. The inspectors verified that the security shift supervisor
promptly assisted the operations shift supervisor in evaluating the
report. The inspectors observed the shift supervisors' followup
discussions with the person who reported the bomb and with cognizant law
enforcement personnel. The licensee concluded that there was not a
cred1ble threat to the plant.
c.
Conclusions
The licensee's response to the bomb report was prompt, thorough, and
conservative. Observed discussions of the report were thorough and
professional.
Reportability was correctly evaluated and the decision
that the bomb report was not credible was appropriate.
F2
Status of Fire Protection Facilities and Equipment
4
F2.1 Valve Perfo)mance Durina Postulated Anoendix R Fire Scenarigji
Information Notice (IN) 92-18 identified the potential for loss of
remote shutdown capability during a control room fire. Due to potential
hot shorts caused by a control room fire, various MOVs subsequently
controlled from the remote shutdown panel could go to a stall condition
since the control signal would not be available to stop power to the
motor. This could cause valve and or operator degradation that could
result in the loss of safe shutdown capability.
Perry's April 1992 response to IN 92-18, concluded that the structural
integrity of the valves was considered to be acceptable based on use of
stall thrust in the valve seismic qualification reports.
In addition,
the licensee concluded that the stall thrust effects would still permit
valve operation and would not affect the valve's safe shutdown related
function. That stall thrust was based on standard methods in effect at
that time and the design stem coefficient of friction.
Since then, GL 89-10 industry testing has shown that available motor torque is higher
and that actual stem coefficients of friction are lower, both of which
could result in a high stall thrust being appliet to the valve.
Therefore, subsequent analyses revealed that the initial evaluations
27
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..
-
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--
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,
1
l
were incorrect since the actuator capability and weak link data applied
,
was not conservative. Perry re-evaluated IN 92-18 in preparation for
the GL 89-10 closeout inspection and due to IN 92-18 concerns raised by
other licensees. A screening method using conservative weak link limits
identified up to 21 valves that have stall thrust greater than the weak
i
,
i
link limits.
.
The licensee was in the process of further evaluating the use of the
more conservative assumptions and the effects of a stall condition on
the valve and the potential loss of safe shutdown function. At the end
of the inspection period, the licensee had developed a method to further
<
evaluate the weak link limit calculation assumptions, the effects of a
stall condition on the valves, and the potential loss of safe shutdown
,
function. LER 96-006 was submitted on August 19, 1996 to document
.
identification of 12 MOVs that could be AT'ected by the postulated fire
!
scenario such that the valves would M dawd to the extent that they
1
cannot be relied upon to perform the b a fe shutdown related functions.
Final review of this issue, including rc+..< of the licensee's
evaluation, compensatory actions, and are required corrective action,
j
will be tracked as part of the closeout of LER 96-006,
n
F5
Fire Protection Staff Training and Qualifications
,
,
i
a.
Inspection Scone (71750. 92904)
,
4
The inspectors routinely observed fire protection equipment and
i
structures during their inspections of the plant.
J
.
b.
Observations and Findinas
!
On July 5,1996, the inspectors observed that an electrical breder
.
i
maintenance cart permanently stored in the Division II Electrical
Switchgear Room had worn a hole through the east firewall about 2 inches
above the floor. The inspectors informed the shift supervisor of the
condition and a fire impairment was promptly established for this fire
barrier deficiency. The hole was smaller than a hole that would require
a fire impairment in accordance with the licensee's impairment program.
The hourly fire watch required to compensate for the impairment had
already been established for another fire impairment.
The damage
appeared to be the result of repeated movements of the cart against the
wall.
--
c.
Conclusions
There had been earlier opportunities for the plant staff to identify
this damage, but there was no evidence that it had been identified prior
to the inspectors' observation. The prompt use of a fire impairment was
conservative.
28
V. Manaaement Meetinas
X1
Exit Meeting Sunnary
The inspectors presented the inspection results to members of licensee
management at the conclusion of the inspection on July 26, 1996. The licensee
acknowledged the findings presented.
l
The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary. No proprietary information was
identified.
X3
Management Meeting Summary
i
On June 11, 1996, the Director, Division of Reactor Projects-III/IV, ONRR
inspected the plant and met with various members of the licensee's staff to
discuss current plant issues.
i
29
-.
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- - - .
- _ _ .
.
-_
.
.
PARTIAL LIST OF PERSONS CONTACTED
Licensee
D. C. Shelton, Senior Vice President
R. D. Brandt, General Manager Operations
N. L. Bonner, Engineering Director
R. W. Schrauder, Nuclear Services Director
L. W. Worley, Nuclear Assurance Director
J. Messina, Operations Manager
INSPECTION PROCEDURES USED
IP 37551:
Onsite Engineering
IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and
'
Preventing Problems
IP 61726:
Surveillance Observations
IP 62703:
Maintenance Observation
IP 71500:
Balance of Plant Inspection
IP 71707:
Plant Operations
IP 71714:
Cold Weather Preparation
.
IP 71750:
Plant Support Activities
IP 83750:
Occupational Radiation Exposure
IP 84750:
Radioactive Waste Management - Inspection of Waste Generator
Requirements of 10 CFR 20 and 10 CFR 61
IP 90700:
Feedback of Operaticnal Experience Information at Operating Power
Reactors
IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power
'
Reactor Facilities
IP 92720:
Corrective Action
IP 92901:
Followup - Operations
IP 92902:
Followup - Maintenance
IP 92903:
Followup - Engineering
IP 92904:
Followup - P1 ant Support
3
TI 2515/109: Inspection Requirements for Generic Letter 89-10
'
30
ITEMS OPENED. CLOSED. AND DISCUSSED
Opened
50-440/96005-01
NCV Electrical system placed in incorrect configuration
50-440/96005-02
VIO Slow identification of condition adverse to quality
)
50-440/96005-03
URI Modification affects RCIC operation
!
50-440/96005-04
URI UFSAR Table 5.4.2, valve design parameters
50-440-96005-05
URI UFSAR SEC. 8.3.2.1.2.1, safety related de electrical
50-440/96005-06
URI UFSAR SEC. 9.1.4.2.3.5, fuel pool sipper
50-440/96005-07
URI UFSAR SEC. 3.3.3, Flooding ECCS rooms
50-440/96005-08
URI UFSAR SEC. 15A.5.3, Repair time rule
50-440/96005-09
IFI Simulator computer interaction with control room
50-440/96005-10
IFI Radioactive material control program
Closed
50-440/93023-03
50-440/95003-02
IFI Drywell dose rates high due to VMIR activities
50-440/96005-01
NCV Electrical system placed in incorrect configuration
Discussed
None
31
.
.-
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LIST 0F ACRONYMS USED
AS LOW AS REASONABLY ACHIEVABLE
ANSI
AMERICAN NATIONAL STANDARD INSTITUTE
B0P
BALANCE OF PLANT
CFR
CODE OF FEDERAL REGULATIONS
DIRECT CURRENT
DIV
DIVISION
dP
DIFFERENTIAL PRESSURE
ELECTRONIC DOSIMETER
1
ELECTRICAL POWER RESEARCH INSTITUTE
l
FR
FEDERAL REGISTER
TECHNICAL ENGINEERING INSTRUCTION
j
GL
GENERIC LETTER
HPES
HUMAN PERFORMANCE ENHANCEMENT SYSTEM
IFI
INSPECTION FOLLOW-UP ITEM
IN
INFORMATION NOTICE
-
INEL
IDAHO NATIONAL ENGINEERING LABORATORY
IPAP
INTEGRATED PERFORMANCE ASSESSMENT PROCESS
l
LCO
LIMITING CONDITIONS FOR OPERATIONS
LEAKAGE CONTROL SYSTEM
N0 TOR CONTROL CENTER
MDFW
MOTOR-DRIVEN FEEDWATER
MOTOR-0PERATED VALVE
MUG
MOV USERS GROUP
NON-CITED VIOLATION
OFFICE OF NUCLEAR REACTOR REGULATION
NUMAC
NUCLEAR MEASUREMENT ANALYSIS AND CONTROL
ONRR
OFFICE OF NUCLEAR REACTOR REGULATION
PERRY ADMINISTRATIVE PROCEDURE
PUBLIC DOCUMENT R00M
POTENTIAL ISSUE FORM
POST-MAINTENANCE TESTING
PLANT OPERATIONS REVIEW COMMITTEE
PERFORMANCE PREDICTION METHODOLOGY
psid
POUNDS PER SQUARE INCH DIFFERENTIAL
PERIODIC VERIFICATION
QUALITY ASSURANCE
REACTOR CORE ISOLATION COOLING
RF0
REFUELING OUTAGE
REACTOR FEEDWATER PUMP TURBINE
RI
RESIDENT INSPECTOR
RADIATION WORK PERMIT
SFC
STEM FRICTION COEFFICIENT
S0I
SYSTEM OPERATING INSTRUCTION
SENIOR RESIDENT INSPECTOR
SR0
SENIOR REACTOR OPEkATOR
32
.
.
. --
4
SHIFT SUPERVISOR
UPDATED FINAL SAFETY ANALYSIS REPORT
UNRESOLVED ITEM
US
UNIT SUPERVISOR
VAC
VOLT ALTERNATING CURRENT
VALVE FACTOR
VIC
VIOLATION
'
VMIR
VIBRATION MONITORING INSTRUMENTATION REMOVAL
,
l
33