IR 05000440/1991003
| ML20029C268 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 03/20/1991 |
| From: | Lanksbury R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20029C261 | List: |
| References | |
| 50-440-91-03, 50-440-91-3, NUDOCS 9103270085 | |
| Download: ML20029C268 (30) | |
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S. NUCLEAR REGULATORY COMMISSION-
REGION III
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, Report No.-50-440/91003(DRP)-
Docket _No. 50-440 License No. NPF-58
. Licensee:. Cleveland Electric Illuminating Company
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Post.' Office Box 5000 Cleveland, OH 44101 M
Facility.Name:
Perry-. Nuclear Power Plant Inspection At:
Perry Site, Perry, Ohio Inspection Conducted: _ January 8 through Febreary 28', 1991-Inspectors:
G. O'Dwyer y
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J. Roton P. Hiland
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'R. D h lbury, Chief
&l'Lohl Approved.By:
Reactor Projects Section 3B
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Inspection Summary
--Inspection-on-January 8 through February 28, 1991 (Report No. 50-4'40/91003(DRP)) -
Areas Inspected:
Routine, unannounced safety inspection:by-resident inspectors:
of previously identified items;=. check. valve monitoring program; licensee event ^
report followup;. monthly' surveillance observations; monthly maintenance;
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observations;Doperational safety verification; and onsite followup of events.-
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- Results; c0f the.seven-areas inspected, one violation was identified in the-i area of ~ operational
- safety verification -(Paragraph 7'.h).
That violation.
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-concerned the failure to properly' restore the-Division-l' hydrogen.recombiner z
to.aistandby mode following-. test activities.
The violation was receiving-appropriate; licensee ma'agement attention at the'closelof the. report period,
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f-In addition,-.eight licensee identified violacions were identified in the areas-f of previously identified items (Paragraph 2.c),-licensee event report followup)
E-(Paragraph 4.a, di e.. g, h,' & j), and operational: safety: verification t
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L(Paragr'aph 7 9)., All eight of these' violations met the test of'10 CFR Part 2-
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for not-_' issuing'a Notice :of Violation.
In general, the eight violations t
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concerned missed technical specification action statements-following system-
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. outages or ' equipment-failures.
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9103270095 910320 PDR ADOCK 05000440
PDR L.i.
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For this report period, the functional area of plant operations was considered
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adequate and improving.
Examples of good operator response included a reactor recirculation pump manual trip; a prompt investigation into suspected thermal limit excursions; prompt response to a control rod drift event; and good operator response to several caplanned events such as Engineered Safety Feature actuations.- Poor performance was noted during the restoration of a containment hydrogen recombiner.
The area of maintenance and surveillance was considered good during the report period.
In addition to the observed maintenance and surveillance test a:tivities, the licensee's response to several surveillance test failures was prompt and conservative.
One negative item in the maintenance area was the use of draft maintenance instructions during the performance of safety-related maintenance.
Engineering and technical support was considered good and improving.
-Resolution of Rosemount trip unit anomalies, evaluation of indicated high thermal limits, resolution of high differential pump flow, and review of safety relief valve (SRV) anomalies were all examples of good engineering and technical support.
The area of radiological controls was considered adequate and improving.
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Efforts by the licensee to reduce man-rem exposure during steam-leak repair activities were evident.
Plant housekeeping (which was a noted weakness last report period) has improved and was considered adequate.
One notable improvement was the-decontamination effort in the reactor core isolation cooling. system pump room. On the negative side, several " locked high radiation" doors were found not properly secured.
The area of Safety assessment and Quality Verification was considered good.
Some examples included the SRV anomaly analysis; the 10 CFR Part 21 report on E-System snubbers; the quality overview of Rosemount transmitter repairs; and the continuing self assessment. program. The licensee self-identified several violations during the report period for which prompt and appropriate corrective action was taken.
In-general, the inspectors found the areas of security and emergency preparedness to be a strength based on routine observations, i
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DETAILS 1.
Persons Contacted a,
Cleveland Electric Illuminating Company (CEI)
M. Edelman, Executive Vice President, Power Generation
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+ #M. Lyster, Vice President, Nuclear-Perry
+*#R. Stratman, General Manager, Perry Nuclear Power Plant (PNPP)
+* M. Gmyrek, Opt: rations Manager, PNPP
- M. Cohen, Manager Maintenance Department, PNPP
- V. Higaki, Manager, Outage Planning Section, PNPP
- D. Cobb, Operations Superintendent, PNPP
- S. Kensicki, Director, Perry Nuclear Engineering Department (PNED)
- V. Concel, Manager, Technical Section, PNED a
- F. Stead, Director, Perry Nuclear Support Department (PNbD)
- H. Hegrat, Compliance Engineer, PNSD
- R. Newkirk, Manager, licensing and Compliance Section, PNSD
- E. Riley, Director, Perry Nuclear Assurance Department (PNAD)
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- W. Coleman, Manager, PNAD
- W. Wright, Acting Manager, Instrumentation and Controls Section, PNPP b.
V. S. Nuclear Regulatory Commission J. Curtiss, Commissioner, NRC
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A. Davis, Regional Administrator, RIII
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- C. Paperiello, Deputy Regional Administrator, RIII
- R. Knop, Chief DRP3, RIII
+ #R. Lanksbury, Chief DRP3B, RIII
- J.'Hannon, Director, Project Directorate III-3, NRR
- R. Hall, Project Manager, NRR
+* P. Hiland, Senior Resident Inspector, RIII
+*#G. O'Dwyer, Resident Inspector, RIII
' Denotes those attending the exit meeting on March 1, 1991.
+ Denotes those attending Commissioner Curtiss' briefing on February 2S, 1991.
- Denotes those attending the Plant Status meeting on February 8,1991, 2.
Licensee Action on Previous Inspection Findings (92701)
(Closed) Open Item (440/88020-04(DRP)):
Licensee declared an a.
unusual Event on December 22, 1988, due to a high airborne radioactivity problem after the "A" dryer skid loop seal blew out because the "A" dryer inlet valve did not open as required during an automatic shift from the "C" dryer to the "A" dryer.
Licensee's condition report (CR)-88-306 (closed on February 24,1989) stated:
1) that the root cause of the event was a previously identified
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deficiently-designed locking collar on each of the dryer inlet and outlet valves (IN64-F1686A-P and 1N64-F1692A-D, respectively),
2) that these collars were not needed and have prevented these valves from opening on other occasions and, 3) that the locking collars had
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been removed from all of these dryer inlet and outlet valves as of January 21, 1989, by Work Order 87-6288 in accordance with Design Change Package 87-343.
Based on completion of the design change, the inspectors consider this item closed, b.
(Closed) Unresolved Item (440/90018-01(DRP)):
Rotameter instrument used to verify system " Operability" not calibrated in accordance with licensee administrative procedures. As previously documented
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in Inspection Report 50-440/90018, paragranh 6.b.(1), the licensee i
identified that the rotameter installed in the standby liquid control (SLC) s.' stem test line was not included in the periodic
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calibration program.
Failure to calibrate that flowmeter was contrary to the requirements established in licensee acministrative procedure IAP-0501, Revision 1 " Calibration / Loop Calibration Check
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Intervals for Plant Instruments." At the time of identification, i
this remained an Unresolved Item pending further review by the licensee to assure other iristruments used to verify system
" Operability" were included in the periodic calibration program.
During this report period, the inspectors reviewed lic M see memorandum A. Clark to File dated August 9,1990. That memorandum
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documented the licensee's basis for concluding the subject rotameter (C41T2001) was maintained at an acceptable level of calibration. As documented, the licensee had performed special tests in May 1989 and
- August 1990 with a calibrated " turbine meter" that verified the calibration of the subject rotamete.
In addition, the licensee
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performed a review of all instrumentation used to satisfy Technical Specification requirements and confirmed periodic calibrations were performed in accordance with the licensee's administrative requirements.
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' Based on the inspectors review of the licensee's justification for not performing a periodic calibration of the subject rotameter and the verification that all other instruments used to verify system i
operability were included in a periodic calibration. program, this item is closed.
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(Closed) Unresolved Item (440/90018-03(DRP)):
Failure to properly-verify valve position.
As previously documented in Inspection Report' 50-440/90018, Paragraph 6.b.(7), the licensee had made a verbal report to the NRC Operations Center of a suspected engineered safety feature (ESF) actuation when main steam line drain valves 1821-F067A, B, C, and 0 were found in the closed position (i.e.,
in-the automatic isolation position). A subsequent review by the licensee determined that no automatic isolation had occurred.
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The four drain valves had been closed in accordance with system operating instructions.
However, with the u ntrol circuits deenergized during the second refuel-outage, the remote position indication (in the control room) was not available. Just prior to
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s the event discovery, on three separate occasions, control room operators incorrectly " assumed" the four drain valves were open during the performance of surveillance test valve lineup instructions.
As documented in ifcensee Condition Report 90-245, approved January 21, 1991, the root cause for this event was operator error.
The three control room operators failed to follow the procedural requirements detailed in Plant Administrative Procedure (PAP)-0201,
" Conduct of Operations," and PAP-0205, " Operability of Plant Sy,tems." The corrective actions taken by the licensee included counselling of_the control. room operators and discussing the causes for this event in current events training with all operators.
Based on the corrective actions and minimal safety significance of this event, the NRC is exercising its discretion under 10 CFR Part 2, Appendix C, Section V.G, and is not issuing a Notice of Violation; this issue is considered closed (NCV 440/91003-01(DRP)).
No deviations were identified. One violation was identified for which a Notice of Violation was not issued.
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Check Valve Monitoring Program (73756)
During this report period, the inspectors reviewed licensee activities to assure adequate testing of check valves.
Specifically, the inspectors reviewed actions taken by the licensee to date, in response to Institute of Nuclear Power Operations (INP0) Significant Operating Experience Report (SOER) 86-3, " Check Valve Failure or Degradation." SOER 86-3 recommended that a design review be performed of check valve applications on various plant systems. The inspectors noted thet the licensee had performed a previous study on check valves in 1983 id incorporated the results of that effort into their evaluation perfcrmed in response to SOER 86-3.
The licensee had analyzed about 350 check valves which were locatet in the main steam, feedwater, service water, diesel air, suppression pool, residual' heat _ removal, control rod drive, reactor water cleanup, core spray, and the reactor core isolation cooling systems.
The design review-of.the check valve installations included the following attributes: were check valves sized properly for anticipated operating modes?; was the proper type of check valve installed for the required service?; and were check valves properly oriented and located a suitable distance from upstream components that caure turbulent flow? In addition, the licensee established a reasonable classification priority to establish the intended inspection scope or modification priority.
The classification priority was established for five groups of valves (Class A, B, C, D-and E) with A having the highest priority.
The licensee identified 66 check valves as potential problems from their design review.
The identified valves were distributed amongst 15 plant systems and were evaluated to fall into the licensee's priority classification as follows:
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Class A1-3 non-safety. valves with velocity / turbulence problems.
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8 (4 safety and 4:non-safety) valves with-velocity / turbulence problems
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Class C'-
35 (23 safety and 12 non-safety) valves with velocity / turbulence problems.
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14 valves with potential flow problems; however, in practice these valves rarely see flow.
Class E >
'6 valves with a history of maintenance activities.
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- s a result of the above review, the swing check valves in " Class A" and
" Class B" were recommended to be added to.the established inspection-program._ In addition, seven tilting disc " Class C valves were also
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recommended to'be added to that program.
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The : Inspectors reviewed 'the f" check valve data sheet" used by. the licensee t
to evaluate the design cor.ditions.
The_ inspectors noted that attributes j
identified included:the valve detail (i.e.,_ manufacturer, model, type, and size);' system details, such~as line size, operating temperature, process
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fluid, and operating pres <ure; the geometric details, such as' valve orientation.and aistance to closest disturbance; the tests performed and periodicity; and the maintenance history.
At'the time of the inspectors review, the licensee-was reviewing the impicmented inservice. Test Program with the_ Nuclear Reactor Regulation
'(NRR) staff. A working-meeting _ was scheduled-for March 1991-to resolve NRR comments, some of.which concerned the acceptable method for testing and/or_ inspecting check valves.
Further review of the licensee's check l valve monitoring program will_ be' performed by the inspectors-following;
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resolution of!NRR staff comments on the licensee's Inservice Test Program'..
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No violations or deviations were identified, a
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Licenseo Event Report' (LER) ' Followup (90712)
- Through review of records, the following event reports were1 reviewed-to. determine'if reportability requirements wcreifulfilled,1immediate-corrective actions were: accomplished-in:accordance with Technical-Specificat_ ions,land corrective action to prevent recurrence had been established, a.
~(CLOSED) LER 50-440/90-031: Failure t'o' perform surveillance
- requirement prior to withdrawing;a control rod.resulted in-Violation of Technical-. Specification 4.0.4.-
t On October 22,11990, following-the completion of fuel movement, a
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Leontrol rod was withdrawn'without first. demonstrating by channel check that the Scram' Discharge VolumeL(SDV) level instrumentation
.-was operable; Technical: Specification 4.0.4 required that-all-Surveillance Requirements (including channel cnecks) Lbe current prior to withdrawing rods.
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Licensee's Evaluation of Cause and Corrective Actions Root Cause:
The cause of this event was inattention to detail combined with a deficiency in the technical specification rounds program for anticipating plant condition changes.
Corrective Actions Issuance of a Standing Instruction requiring the taking of
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all readings when instrumentation is available.
Inclusion of this LER in requalification training.
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Inspecto"s' Evaluation:
The :nspector concluded that the licensee had performed a prompt evaluation of the cause for this event with appropriate management attention. The corrective actions taken appeared reasonable to prevent recurrence.
Failure of the licensee to conduct the required surveillances prior
- to initial rod withdrawal following fuel movement was a Violation of Technical Specification 4.0.4 (NCV 50-440/9102;-02(DRP)). This violation was a " licensee identified item" which meets the test of 10 CFR Part 2, Appendix C, Section V.G; therefore, a Notice of Violation will not be issued.
This item is closed.
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(CLOSED) LER 50-440/90-032:
Inadequate procedure cesulted in the Residual Heat.lemoval (RHR) "A" shutdown cooling system being isolated.
On November 16, 1990, the RHR "A" shutdown cooling system was isolated while the licensee was performing a replacement of the control relay.
While the steps in the work procedure were performed in the sequence specified, a step to remove a jumper was incorrectly sequenced. As-a result of this improper sequencing, RHR "A" shutdown cooling system isolated when the jumper was removed.
Licensee Evaluation of Cause and Corrective Actions Root Cause:
The.cause of this event was a deficiency in the planning and review process for the control relay replacement work package.
Correct'<e Actions:
Instrument and Control (I&C) personnel involved in the
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planning and review of this work package were trained on this event and on the impor+ance of proper sequencing of actions in all work orders.
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This event will be reviewed by all licensed ope-ators during requalification training.
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i Inspectors' Evaluation:
The inspector concluded that the licensee had performed a prompt evaluation of the cause of this event and appropriate corrective actions had been implemented.
Based on completion of corrective actions as stated above, this item is closed.
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(CLOSED) LER 50-440/90-33: Unexpected actuation of Traiti-B of control room emergency recirculation system during system restoration.
On November 20, 1990, Train-B of the control room heating, ventilation, and air ennditioning (CRHVAC) system actuated unexpectedly in the emergency recirculation mode of operation when temporary power to a power distribution panel was removed to allow restoration of the normal power supply.
Licensee's Evaluation of Cause and Corrective Actions Root Cause:
The cause of this event was the deletion of informat, ion, in the off-normal-instruction (ONI), regarding the initiation of emercency recirculation when power was lost to the normal-power supoly.
The revision had been made in response to a design change which removed the automatic initiation of the eme gency recirculation mode due to a loss of power to the ethylene oxide monitors.
The revision did not recognize that loss o' power to the K-1-N bus would still cause an automatic initiat'on of the emergency mode of the CRHVAC system due to a loss of power to the control room airborne gas radiation monitor.
Corrective Actions:
ONI-R25-2 w<s revised to reflect the correct guidance
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during loss of power to the K-1-N bus.
Detailed system operating instructions were developed
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to provide guidance for the operations of low voltage electrical systems.
_ Inclusion of this LER in requalification training.
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Inspectors' Evaluation:
The inspector concluded that the licensee's evaluation was accurate.
The stated corrective actions were appropriate.
This item is closed.
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{ CLOSED)LER 50-440/90-034:
Reactor pressure vessel watsr 19 vel instrumentation equalizing valve misposition resulted in a Technical Specification Violation.
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r On November 25, 1990, plant technicians discovered an open instrument equalizing valve to a reactor level transmitter.
This normally closed valve affected the operability of seven reactor level and pressure i
transmitters including one level transmitter required to be operable by Technical Specification 3 3.2.
During the time of the potential
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' operability, the plant was in Operational Ccndition 5 (REFUEL with core altreations in progress) and 4 (COLD SHUTDOWN).
Licensee's Evaluation of Cause and Corrective Actions Root Cause:
The root cause of this event could not be determined.
This equalizing valve had last been cperated during a calibration on September 30, 1990, and was verified shut upon completion of the calibration.
Upon discovery, the equalizing valve was immediately closed and a verification of all other reactor water level equalizing valve positions was conducted with no discrepancies noted.
Corrective Actions:
All Instrument and Control technicians have reviewed the
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circomstances of this event.
This event will be reviewed will all licensed and
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non-licensed operators as part of the operator requalificatior, program.
Inspectors' Evaluation:
Although the root causu of this event was not determined, the inspector concluded that the licensee had performed a prompt evaluation of the cause for this event with cppropriate management attention.
Technical Specification 3.3.2 requires two channels per trip system be operable for reactor vessel water level low, Level 2, during core alterations and operations with the potential for draining the reactor vessel. With the equalizing valve open, only one char.nel j-was operable in one trip system. This is a violation of Technical Specification 3.3.2 (NCV 50-440/91003-03(DRP)).
This violation was a " licensee identified item" which meets the test of 10 CFR Pert 2 Appendix C,Section V G; therefore, a Notice of Violation will not
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be issued.
This item is closed, e.
(CLOSED) LER 50-440/90-036:
Previously unidentified system interaction resulted in control rod scram accumulator level switch inoperability and Technical Specification" Violation, On December 7,1990, it was concluded that improper servicing resulted in as many as 54 control rod scram accumulator level switches potentially being inoperable throughout the second fuel cycle in violation of Technical Specification 3.1.3.3.
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l Licensee's Evaluation of Cause and Corrective Actions
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Root Cause:
The cause of this event was a previously unidentified system interaction.
It was not recognized that using the nitrogen supply system to service control rod scram accumulators could result in level switch damage.
Excessive flow, while servicing the accumulators caused the level switch float to rotate, which caused the bias spring to unravel, tangle, and thus prevent proper operation of the level switch.
Corrective Actions:
To prevent recurrence, System Operating Instruction (501)-C11 (CRDH), " Control Rod Drive Hydraulic System (Unit 1)," has been revised to ensure proper level switch operations after accumulator servicing. All level switches have been retested to ensure operability after accumulator servicing.
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surveillance iristruction has been revised to ensure that each level switch is tested only after the accumulator is serviced.
Additionally, a design change is beina considered to make an improved servicing rig a permanent part of the Nitrogen Supply system.
Inspectors' Evaluation:
The inspector concluded that the licensee had performed a prompt evaluation of the casse of this event with appropriate management attention. The corrective actions taken appeared adequate to prevent recurrence.
In this event, as many as 54 control rod scram accumulator level switches were potentially inoperable during power operation.
The inability to monitor internal accumulator water leakage resulted in the inoperability of,the 54 control. rod scram accumulators in accordance with Technical Specification 4.1.2.3 and the requirement to declare the 54 associated control rods inoperable in accordance with Technical Specification 3.1.3.1, Action a.2.
This Violation (NCV 50-440/91003-04(DRP)) was a " licensee identified item" which meets the test _of 10 CFR Part 2, Appendix C, Section V.G; therefore.
- a Notice of Violation will not be issued.
This item is closed.
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(CLOSED) LER 50-440/90-037: Operation of the wrong slide link while performing surveillance testing resulted in an inadvertent start of the residuel heat removal (RHR) "B" pump.
On December 9, 1990, during the performance of surveillance testing, two unexpected automatic starts of RHR pump "B" occurred during the timing portion of the test.
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O Licensee's Evaluation of Cause and Corrective Action Ruot Cause:
The root cause of this event is personnel error.
The surveillance instruction required a sliding link to be opened prior to the timing portion of the test, to prevent automatic pump start. Although the sliding links are adequately identified, and the technicians were following the procedures as written, the technicians opened the wrong sliding link.
Corrective Actions:
The corrective actions taken for this event included appropriate counseling and disciplinary action for the Instrument and Control (I&C) technicians involved.
Additionally, this event will be discussed during I&C technician continuing training and all licensed operators will review this event during operator requalification training.
Inspectors' Evaluation:
The inspc-tor concluded that the licensee had performed a prompt and accurate evaluation of the cause for this event.
The corrective actions taken as stated above were appropriate.
This item is closed, g.
.(CLOSED) LER 50-440/90-038: Open gas purge valve un control room radiation monitor resulted in a Technical Specification Violation.
On December 11, 1990, the control room noble gas radiation monitor was found to be inoperable due to a nonrepresentative sample being drawn through an open gas purge valve.
Licensee's Evaluation of Cause and Corrective A9tions Root Cause:
The root cause of this event was personnel error of an indeterminate nature.
The last documentatior, of the valve being in the proper position was an independent verification of valve position on Februan 1, 1300.
Corrective Actions:
In order to prevent recurrence of this event, Valve Lineup Instruction (VLI)-D17 was changed to require the gas purge valves of all of the D17 cirborne radiation monitors to be locked closed.
System Operat.:n; instruction (501)-017 was i
revised to include additional guidance if proper flow on the radiation monitor was not met.
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Additionally, the operation of the radiation monitors will be discussed during the Health Physics continuing training.
This event will also be discussed with all licensed and nonlicensed operators during their requalification training.
Inspectors' Evaluation:
The inspector concluded that the licensee had performed a prompt evaluation of this event with appropriate management attention.
The corrective actions taken appeared adequate to prevent recurrence.
Since this monitor had been inoperable for greater than seven days without compensatory actions being taken, the licensee failed to comply with Technical Specification 3.3.7.1.
This Violation (NCV 50-440/91003-05(DRP)) was a " licensee identified item" which meets the test of 10 CFR part 2, Appendix C,Section V.G; therefore, a Notice of Violation wil' not be issued. This item is closed, h.
(CLOSED) LER 50-44?/90-039:
Inadequate surveillance instruction resulted in Technical SpE ification Violation.
On December 11, 1990, a review of Surveillance Instruction (SVI)
E12-T1182B revealed that both loops of the containment spray mode of the residual heat removal (RHR) system were inoperable due to the unverified position of two isolation valves.
Licensee's Evaluation of Cause and Corrective Actions Root Cause:
The cause of this event was inadequate instructions.
SVI-E12-T1182A and B were initially written in 1986 to satisfy the surveillance requirements of Technical Specification 4.6.3.2.a; however, verificati_on of the second isolation valve for each loop was not included.
I Add;t unally, periodic reviews of the instruction failed to identify the deficiency.
Corrective Actions:
To prevent recurrence, SVI-E12-T1182A and B were revised to include the appropriate isolation valves for position verification. A review was performed to ensure that these valves were not omitted from other surveillance requirements.
As part of an established administrative program, all surveillance instructions were required to be periodically
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reviewed on a two year cycle to ensure fulfillment of appropriate Technical Specification requirements. Appropriate personnel were provided additional training to reinforce the necessity for thorough and accurate two-year periodic procedural reviews,
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l Inspectors' Evaluati:n:
i The inspector concluded that the licensee had performed a prompt
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evaluation for this event with appropriate management attention.
Corrective actions taken appeared reasonable to prevent recurrence.
Since the position of these secondary isolation valves were not verified by any surveillance instruction, previous power operations were in Violation of Technical Specification 3.6.3.2 (NCV 50-440/91003-06(ORP)).
However, if these valves had been left in the open position, they still would have permitted the containment spray system to perform its intended function had containment spray been required.
This violation was a " licensee identified item" which meets the test of 10 CFR Part 2, Appendix C, Section V.G; therefore, a Notice of Violation will not be issued.
This item is closed.
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(CLOSED) LER 50-440/90-040:
Reactor Water Cleanup System isolation caused by a blown fuse while troubleshooting isolation circuitry.
On December 18, 1990, while performing a work order to correct the cause of the reactor water cleanup (RWCU) system outboard isolation valves not opening with the RWCU leak detection isolation bypass switch in " Normal," a Division 1 RWCV outboard isolation occurred.
Licensee's Evaluation of Cause and Corrective Actions Root Cause:
The root cause of this event was indeterminate personnel error.
The plant technician performing the work order caused an inadvertent short during the performance of the work order.
Although the responsible system engineer observed the work and conducted a thorough inspection of the panel following the event, no indication of shn-ting to ground could be found on any of the t'ols used in the panel or on components within the panel. However, since the RWCU isolation occurred at about the same time as the lifting of the lugs, it was probable that the events were related.
Corrective Actions:
The corrective actions for this event included inspecting the panel and tools for 1-dications of shorting, replacing the fuses, and restoring the RWCU system to normal.
The individuals who performed the evolution were significantly involved with the investigation. This event will be discussed at Instrument and Control section continuing training and at operator requalification training, hspectors' Evaluation:
The inspector concluded that the licensee had performed a prompt i
evaluation of the cause for this event with appropriate management attention.
The corrective actions taken appeared adequate to prevent recurrence.
This item is closed.
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(CLOSED) LER 50-440/90-041:
Inoperable instrumentation resulted in high pressure core spray system inoperability and a Technical Specification Violation.
Between December 12 and December 28, 1990, inoperable reactor pressure vessel level instrumentation channels resulted in the high pressure core spray (HPCS) system being inoperable in Violation of Technical Specification 3.3.1, 3.3.2, and 3.3.3.
Licensee's Evaluation of Cause and Corrective Actions Root Cause:
The cause of this event was personnel error. The initial positioning of the Channel "0" reference leg isolation valve was directed by a valve lineup instruction performed on December 12, 1990. Because no work was performed on or around the affected valve, it was assumed that the mispositioning was the result of an unintentional error by unidentified personnel during the performance of refuel outage work.
Corrective Actions:
To prevent recurrence, plant management generated a memorandum to all plant personnel to address the importance of maintaining the integrity of valve lineups, and the necessity of equipment operation by only qualified personnel with proper authorization.
These events will be discussed with all Inst'tument and Control (I&C) technicians, plant operators, r
chemistry and health physics technicians to stress the importance r)f procedural compliance and attention to detail.
Additionally, all plant licensed and non'.icensed operators will be trained to this event, with emphasis placed on the evaluation of plant equipment performance and the importance of early detecticn of the cause of equipment malfunction.
Inspectors' Evaluation:
The inspector concluded that the licensee had performed a prompt evaluation of the cause for this event with appropriate management attention. The corrective actions taken appeared adequate _to prevent recurrence.
The isolation of the Channel "D" reactor pressure vessel level reference leg placed the High Pressure Core Spray (HPCS) system in an inoperable condition.
This is a Violation of Technical Specifications 3.3.1, 3.3.2, and 3.3.3 (NCV 50-440/91003-07(DRP)).
These violations are " licensee identified items" which meets the test of 10 CFR Part 2, Appendix.C.Section V.G; therefore, a Notice of Violation will not be issued. This item is closed.
No deviations were identified.
Six violations were identified for which a Notice of Violation was not issued.
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MonthlySurve11*anceObservation(61726)
For the below listed surveillance activities the inspectors verified one or more of the following:
testing was performed in accordance with procedures; test instrumentation was calibrated; limiting conditions for operation were met; removal and restoration of the affected ccmponents were properly accomplished; test results conformed with technical specifications, procedure requirements, and were reviewed by personnel other than the individual directing the test; and any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
Surveillance Test No.
Activity SVI-R43-T1318 Emergency diesel generator-2 start and load test.
SVI-C51-T0024 Average Power Range Monitor gain and channel calibration.
No violations or deviations were identified.
6.
Monthly Maintenance Observation (62703)
Station maintenance activities of safety-related systems and components listed below were observed and/or reviewed to ascertain that activities were conducted in accordance with approved procedures, regulatory guides and industry codes or standards, and in conformance with technical specifications.
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The following items were considered during this review:
the limiting conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished b, qualified personnel; parts and materials used were properly certified; radiolo0 cal i
controls were implemented; and fire prevention controls were implemented.
Work requests were reviewed to determine status of outstanding jobs and to assure that priority was assigned to safety-related equipment maintenance which might have affected system performance.
The following specific maintenance activities were observed:
Work Order Subject 90-4852 Retorque bolts on emergency diesel generator-2 turbo-charger.
89-5161 Replaced all fuel injection pump supply / return lines and orifice adapter on emergency diesel generator-2,
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l Work Order Subject 90-5283 Repair oil leaks on uergency diesel
generator-2.91-612 Repair emergency diesel generator-2 temperature recorder.
90-5101 Replaced overload relay on Division-2 waterleg pump bret.ker.
90-4516 Replaced the coupling cover nut and bolt on the Annulus Exhaust Gas Treatment System compressor
"B", and tightened the grease fittings.
R86-5950 General Electrical Instruction (GEI) for
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calibration of differential relay.
Regarding Work Order R86-5950, the inspectors noted that in addition to i
the prescribed calibration procedure at the job location, maintenance technicians were also referencing a marked-up draft revision of the same
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procedure. The task being performed was the calibration of a Gould 87M percentage differential relay on the Division 2 emergency bus switchgear.
As written Generic Electrical Instruction (GEI)-0110 Revision 1, was
intended to be used during " bench" calibration.
However, the relay calibration was performed in the installed condition.
At the relay location, pern,anently installed test switches were provided.
Since the prescribed procedure assumed the tested relay was removed from the switchgear, detailed instructional steps omitted any reference to the test switches. The marked up draft procedure provided the necessary correlation between relay termination points and test switch termination
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point (e.g., relay terminal number 1 = test switch terminal number 16).
Since the marked-up draft procedure was not an " approved" work instruction, the inspectors requested the maintenance technicians to explain how the draft information was verifiable.
In response, the technicians referenced " contre 11ed" electrical single-line drawings, aise located'at the work lecation.
The technicians clearly demonstrated to the inspectors their ability to verify draft information by use of the
" controlled" electrical drawings.
Followup review by the licensee identified that the marked-up draft procedure had been prepared shortly after-the last calibration performance (2 years prior). When submitted for review and approval, a low priority was assigned dae to the long time between calibrations (2 year cycie) and the low number of affected relays (3). With the low priority, procedural changes were not made, lhe licensee considered the changes to be an enhancement to the procedure which would improve or clarify the procedure steps.
The itapectors concluded that for the specific work activity (R86-5950),
adequate controls were in place to perform the task.
However, the
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inspectors requested the licensee to review the controls for revising procedures. The purpose of that requested review was to assure draft
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procedure revision requests were being acted on in accordance with the licensee's administrative controls.
This will remain an Open Item pending the inspectors review of licensee action (50-440/91003-08(ORP)).
No violations or devir.tions were identified.
One Open item was identified.
7.
Operational Safety Verification (71707)
a.
General The inspectors obsarved control room operations, reviewed applicable logs, and conducted discussions with control room operators during this inspection period. The inspectors verified the operability of selected emergency systems, reviewed tagout records, and verified (
tracking of Limiting Conditions for Operation associated with affected components. Tours of the intermediate, auxiliary, reactor, and turbine buildings were conducted to observe plant equipment conditions including potential fire hazards, fluid leaks, anti excessive vibrations, and to verify that maintenance requests hao been initiated for certain pieces of equipment in need of maintenance. The inspectors by observation and direct interview verified that the physical security plan was being implemented in accordance with the station security plan.
The inspectors observed plant housekteping, general plant cleanliess conditions, and verified hplementation of radiation protectun controls.
b.
1ransistor Degradation in Rosemount 5100U Tryi Units General Dectric (GE) Service _Information Eetter ($TL) No. 90.
Durint the report period, the inspectors reviewed the licensee's actions taken in response to the subject notification.
SIL No. 520 was issued by GE on August 10, 1990. As stated in SIL No. 520, Rosemount Model 510 DU master und slave trip units had experienced erroneous trip signals that were determined by the vendor to be
. caused by a faulty transistor.
The Perry plant was one of several Boiling Water Reactors that had the suspect components installed.
Prior to issuance of SIL No. 520, the licensee had been informed directly by Rosemount in a 10 CFR Part 21 notification dated June 8, 1990.
In response to that notification, the licensee initiated Condition Report (CR)90-155, dated June 15, 1990, to document the review performed and the corrective action taken.
Immediate action taken by the li ensee was to idntify all Model 510 DU master and slave trip units, determine whether they were normally energized or deenergized, and identify the safety function being performed.
In addition, a determination of continued operability was made based on the licensee's evaluation of past p rformance and field verification of proper output voltage on the " Priority 1" trip units.
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The licensee identified the normally deenergized with engineered safety feature (ESF) application as " Priority 1;" normally deenergized with annunciator /non-ESF application as " Priority 2;"
and the normally energized trip units as " Priority 3."
The results of the licensee's review identified the following:
Total Driority 1 122 Total Priority 2
Total Priority 3
The Priority 1 trip units were being repaired in accordance with vendor instructions under a licensee work order.
At the time of the inspectors review, 105 of the 122 Priority 1 trip units had been repaired with the remainder scheduled for completion by June 1991.
The Priority 2 and 3 trip units (including spares) were scheduled for repair by June 1992.
In addition, a non-conformance report was written (NR 90WS-217) for trip units installed in Perry Unit 2.
The inspectors concluded that the licensee had taken prompt action to address the concerns identified by the subject vendor information notice.
The licensee's evaluation of continued operability while performing repair activities was reasonable and based on quantitative analysis of field measurements.
In addition, the inspectors noted an adequate oversight by the licensee's Quality Assurance department as evidenced by surveillance reports associated with the corrective actions taken by the licensee, Control Rod Scram Accumulator level Switch inoperability c.
On January 7,1991, the licensee reported, in accordance with 10 CFR 50.73, the failure of 54 out of 177 control rod scram accumulator level switches.
The cause of those failures and the corrective action taken were described in licensee event report (LER) 440/90036, dated January 7,1991 (see paragraph 4.e above).
During this report period, the inspectors discussed with cognizant licensee personnel the failure mechanism described in LER 440/90036.
The purpose of those discussions was to evaluate the generic implications of the reported switch failure. As detailed in G.E.
memorandum to Bill Kanda dated December 18,.1990, an evaluation of generic applicability was performed.
Based on the method (i.e.,
system) used at Perry to charge nitrogen into control rod scram accumulators, the licensee concluded that the failure mechanism was unique to the Perry plant design and not a defect reportable under the provisions of 10 CFR Part 21.
The inspectors determined that the licensee's conclusion was reasonable.
d.
Thermal Limits Indicated Above Technical Specification limits On January 8, 1991, while increasing reactor power to 100 percent, by increasing core flow, plant operators noted an increase in indicated thermal limits above Technical Specification limits.
Immediate actions were taken by reducing core flow and interting control rods to reduce reactor power and the indicated thermal limits.
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A prompt investigation into the reason for the indicated transient was performed by the "on-call" reactor engineer.
A review of the plant computer analysis (P1) indicated that a local power range monitor (LPRM) had drif ted high.
LPRM 16-178 was bypassed and the backup method of thermal limits calculations was performed.
That analysis verified thermal limits had been maintained within the allowable values of the Technical Specifications.
The licensee initiated Condition Report 91-005 to document the immediate corrective actions taken, the reactor engineering analysis performed, and the long term corrective actions.
The inspectors noted that the licensee's evaluation of the " indicated" thermal limit increase was prompt and the actions taken were in accordance with Technical Specifications.
e.
Safety Relief Valve Open Longer Than Anticipated On January 13, 1991, in an attempt to reduce "weeptge," Safety
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Relief Valve (SRV) IB21-F051D was cycled open.
At the time of that planned evolution, the reactor plant was at 90 percent power.
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Initial plant response to opening the 3RV was as expected; however, when the control switch was placed back in automatic, the SRV did not immediately close.
The control room operators expected the SRV to close quickly when the control switch was moved to the automatic position. After about 40 seconds, control room operators, in accordance with plant off-normal instructions, began to cycle the control switch between its open and close position. After the last cycle, the SRV closed following a 40 second delay.
The total time the SRV was open was about 3 minutes.
The suppression pool increased in average temperature from its starting point of
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80 degrees F to 90 degrees F.
i In response to the unexpected delay in closing for the subject SRV, the licensee declared that relief valve inoperable and began an investigation into the root cause for the observed valve performance.
Licensee Condition Report (CR)91-011, dated January 13, 1991, was initiated to document the corrective actions taken and the cause for the observed valve performance. As detailed in CR 91-011, the licensee concluded that the most probable cause for the slow closure of the subject SRV was a buildup of condensation inside the SRV which delayed the counterbalance forces required for SRV closure.
The most probable root-cause for the buildup of condensation was attributed to incomplete insulation.
After evaluating the SRV performance during this event and after evaluating information supplied by the responsible designer, General
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Electric, the licensee concluded that SRV 1821-F051D was capable of performing its intended safety function and declared the valve operable. Additional planned corrective action included inspection of the SRV actuator and installed insulation at the next plant shutdown.
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Manual Trip of Reactor Recirculation pump-A On January 24, 1991, at about 1:45 a.m., while operating at 100 percent reactor power, the temperature monitor for Reactor Recirculation Pump-A alarmed indicating a high bearing temperature.
In accordance with off normal instructions, plant operators reduced reactor power and secured Reactor Recirculation Pump-A placing the plant in " single-loop" operation.
In parallel with actions taken to comply with Technical Specification 3.4.1.1, Action a., the licensee investigated the reason for the high bearing temperature alarm. Based on other available sensors and troubleshooting, the licensee determined that the alarmed condition was not present and was due to failed instrumentation.
At about 4:00 a.m. Reactor l
Recirculation Pump-A was started and "two-loop" operation restored.
The plant was returned to 100 percent power at about 6:45 a.m.
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on January 24.
The inspectors noted that the licensee's actions
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were in accordance with pb't 'echnical Specifications.
g.
Failure of Rod Control and Information System Power Supply On January 29, 1991, failure of 10 volt and 5 volt power supplies within the rod control and information system (RCIS) resulted in a loss of control rod position indication, scram accumulator fault indication, and the ability to move control rods using the normal insert and withdrawal method (NOTE:
All control rods were tripable).
At about 12:30 a.m. on January 29 plant operators noted abnormal displays for control rod position indication on Channel 1.
Upon discovery, a work request was initiated and authorizstion was given to begin troubleshooting in accordance with plant administrative procedures. The troubleshooting effort, documented in Work Order 91-725, identified the failed power supplies and replacement parts were obtained. While the mode of failure affected only the Channel 1 position indication, removal of the failed components effected the RCIS interface and resulted in the above noted plant conditions.
Af ter discussion with the maintenance technicians performing the replacement work, the on-duty unit supervisor (SRO) authorized replacement and entered the Limiting Conditions for Operation (LCO)
for Technical Specifications 3.1.3.3 and 3.1.3.5 which required the plant to be in HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. At 11:08 p.m. on January 29, replacement work commenced.
At about 1:00 a.m. on January 30, following shif t turnover, the on-duty unit supervisor recognized that not all of the Action statements in the applicable LCOs were complied with.
Specifically, Technical Specification 3.1.3.3, Action statement a.2.a required inserting at least one control rod at least one notch to verify a control rod drive pump was operating.
Since this Action statement could not be performed due to the inability to insert or withdraw control rods, the on-duty Unit Supervisor entered the provision of Technical Specification 3.0.3.
That Technical Specification
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o required that within one hour action shall be initiated to place the unit in an OPERATIONAL CONDITION in which the Specification does not apply and at least STAR 1)P within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
At about 2:00 a.m. on January 30, repairs were completed and the RCIS was restored to its normal configuration.
No actual power reduction was commenced during the three hour time period the plant operated under the provisions of Technical Specification 3.0.3.
For this event, the inspectors reviewed completed Work Order 91-725, licensee Condition Report 91-023, and control room logs.
In addition, the inspectors discussed the event with plant personnel including the maintenance technicians, unit supervisor (SRO), and shif t supervisor (SRO) on duty at the time of event occurrence.
The inspectors noted that plant personnel were aware of the system impact during the RCIS maintenance activity.
However, the determination of Action statement compliance was an acknowledged personnel error based on the assumption the the "Otherwise" statement-following Action Statement a.2.b was also applicable to Action statement a.2.a.
Failure of the licensee to " initiate action" within one hour, to place the unit in an operational condition for which Technical Specification 3.1.3.3 did not apply, is a Violation of Technical Specification 3.0.3 (NCV 50-440/91003-09(DRP)).
The licensee's immediate corrective actions as documented in Condition Report 91-023, were to initiate actions to commence a plant shutdown and expedited repairs to RCIS.
Since this violation met the criteria specified in 10 CFR Part 2, Appendix C, Section V.G, a Notice of Violation was not issued; and, this issue is considered closed, h.
Hydrogen Recombiner On January 29, 1991, during a plant walkdown, a Region 111 Chief Examiner questioned the standby condition of the Division I hydrogen recombiner.
At the time of that observation, the Region Ill Chief-Examiner was informed that surveillance testing was just completed and the observed temperature indication (1200 F) at the control panel was the actual temperature as the recombiner cooled down. On February 12, 1991, the same Region III Chief Examiner observed that the Division 1 hydrogen recombiner still indicated a high
. temperature (1200 F) at the control panel, When questioned again
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by the Region III Chief Examiner, the licensee identified that the electrical supply breaker (EF1812) was open and the temperature meter was in fact in its failed position.
Immediate corrective actions by the licensee was to close the supply breaker which placed the Division 1 hydrogen recombiner in its normal standby condition, In addition, licensee Condition Report 91-039 was initiated to document the licensee's investigation and long term corrective actions for this event.
The inspectors noted that System Operating Instruction S01-M51/56,
" Combustible Gas Control System and Hydrogen Igniters," Revision 5, step 4.5.2, provided the following instructions:
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" Place the PWR OUT SW in ON and verify the red status light on the control switch plate is energized.
If red light is not ON, verify EF1812(EF1012) closed (Emphasis Added] and check the integrity of f uses T1 and F2 in IM51-S001(IM51-S002)."
Based on the explicit instructions to verify feeder breaker EF1812 closed, the licensee's determination that the Division 1 hydrogen recombiner was an operable component during the time period the feeder breaker was open appeared reasonable.
Electrical Lineup instruction (ELI)-R23, "480 Volt Load Centers,"
Revision 3, identified in paragraph 4 that the " required position" of feeder breaker EF1B12 was closed.
System Operating Instruction 501-M51/M56 identified in step 6.3 the actions required to
" shutdown" a hydrogen recombiner which left feeder breaker EF1812 in the closed position.
10 CFR Part 50, Appendix B, Criteria V, requires in part that activities affecting quality be accomplished in accordance with prescribed procedures.
Perry Administrative Procedure (PAP)-0205,
" Operability of Plant Systems," Revision 6 Section 6.1.2, states in part that 'l.... Prior to declaring a system or component operable, the US shall review the following items:
1.
System configuration should be in the Stu:4 R adiness or Secured status as applicable."
Contrary to the above, on January 29, 1991, the Division 1 containment hydrogen recombiner was returned to service, after review by the Unit Supervisor, with feeder breaker EFIB12 open.
Failure of the licensee to properly accomplish the restoration lineup is a Violation (50-440/91003-10(ORP)).
In addition to the above Violation, the inspectors noted several weaknesses.
First, upon initial questioning by the NRC Chief Examiner on January 29, the licensee failed to identify the incorrect electrical lineup.
Second, for over two weeks shiftly rounds through the Division 1 switchgear room failed to note the extinguished " power available" light on the Division 1 hydrogen recombiner control panel, the open breaker EF1812, or the recombiner temperatere meter indication of 1200 F.
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Control Rod Drif t On February 1, 1991, while operating at 100 percent reactor power, Control Rod 18-47 was observed " drifting" in with no insert signal.
In response to a rod drift alarm and a rod control and information out-of-service alarm, control room operators noted that Control Rod 18-47 had drif ted from position 48 (full out) to position 32.
Immediate actions included inserting Control Rod 18-47 to position 30, since an adjacent control rod was also at position 32; and, the reactor engineer was notified of the rod drift. While completing
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the immediate actions, Control Rod 18-47 again drifted in from position 30 to position 14. At that point the unit supervisor (SRO)
directed the full insertion of Control Rod 18-47 to position 00.
As documented in licensee Condition Report 91-029, the cause for
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this event was moisture intrusion into the hydraulic control unit (HCU) junction box for Control Rod 18-47.
The moisture source was from a " plugged" drain line in the containment ventilation system that allowed condensed water to back-up and spill onto the affected junction box. The transponder circuit board within the HCV junction box, when wetted, responded to a periodic circuit test signal by inserting the control rod.
The drain line was cleaned out and the affected transponder circuit board was replaced. The inspectors noted the actions taken were prompt and in accordance with Technical Specifications.
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10 CFR Part 21 Notification on Hydraulic Snubbers On February 1, 1991, the licensee notified the NRC, Region III, of a condition determined to be reportable under the provisions of 10 CFR Part 21.
Following the initial verbal notification made on February 1, licensee letter PY-CEI/NRR-1303L, dated February 4, 1991, detailed the reported condition. As stated in that letter, the licensee identified improper sealant material used in several
"E-Systems" hydraulic snubbers installed at Perry.
The improper sealant was determined to be Nitrile rather than the designed Ethylene Propylene Diene Monomer (EPDM) saalant.
The licensee further stated that a engineering evaluation concluded the Nitrile sealant material would perform the intended safety f unction through at least the next operating cycle.
Corrective action included replacement of some seals (9 of 53) with the EPDM sealant.
In addition, replacement of the seals in the remaining population was to be performed in the third refueling outage.
k.
Standby Liquid Control Operability Based on concerns identified at other Boiling Water Reactors, the inspectors requested the licensee to evaluate past test data
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obtained during start-up testing on the standby liquid control system (SLC). During a planned test at Quad Cities Unit 2, that licensee identified an operability concern when the SLC pump under test began to cavitate apparently due to loss of its net positive suction head. The problem identified at the Quad Cities facility had the potential to be generic to Perry since it incorporates' a sirgilar SLC system.
The inspectors requested the licensee to verify that previous test performances confirmed the capability of SLC to cperate over the range of permitted liquid control tank temperature and level.
In addition, the inspectors requested the licensee to evaluate the potential for suction anomalies due to the physical arrangement.
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In response to the inspectors request, the licensee reviewed start-up test information and confirmed testing was performed at 110 degrees F and at pump design flow.
The acceptance criteria for the initial start-up testing required SLC pumps to not cavitate when taking suction from the storage tank with storage tank level at
" tank zero" and water temperature at 110 degrees F.
At the close of this report period, the licensee had received and was evaluating NRC Information Notice (IN)91-12, dated February 15, 1991. That notice provided the details of the potential loss of net positive suction head as discussed above.
No deviations were identified.
One violation was identified for which a
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Notice of Violation was issued and one additional violation was identified for which a Notice of Violation was not issued.
8.
Onsite Followup of Events at Operating Power Reactors (93702}
a.
General The inspectors performed onsite followup activities for events which occurred during the inspection period.
Followup inspection included one or more of the following:
reviews of operating logs, procedures, and condition reports; direct observation of licensee actions; and interviews of licensee personnel.
For each event, the inspectors reviewed one or more of the following:
the sequence of actions; the functioning of safety systems required by plant conditions; licensee actions to verify consistency with plant
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procedures and license conditions; and verification of the nature of the event. Additionally, in some cases, the inspectors verified that licensee investigation had identified root causes of equipment malfunctions and/or personnel errors and were taking or had taken appropriate corrective actions.
Details of the events and licensee corrective actions noted during the inspector's followup are provided in paragraph b. below, b.
Details (1) Loss of Control Complex Chill Water System On January 11, 1991, at about 5:30 a.m., while the reactor was at 100 percent power, both trains of the control complex chill water system were declared inoperable. At the time of event occurrence, Train-B of the control complex chill water system
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had been removed from service for planned corrective maintenance (low refrigerant).
During operator rounds, a burned-out light bulb was noted on Train-A and a replacement bulb was inserted. When the rep b emeiic oulb was installed, the control >ower circuit for Train-A blew a fuse making.
Train-A inoperable.
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With both trains of control complex chill water systems j
declared inoperable, the licensee entered the provisions of Technical Specification 3.0.3 which required action to be taken
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within one hour to place the plant in an Operational Condition for which the applicable Technical Specification (3.7.2) did not apply.
In parallel with the action required by Technical Specification 3.0.3, plant operators started to restore Train-B of the contrcl complex chill water system.
Train-B was declared operable at 6:2S a.m. and Technical Specification 3.0.3 was ex'ted.
Subsequently, repairs were made to Train-A of the contral complex chillers by replacing the fuse in the control circuit. The licensee informed the NRC Operations Center of this event via th Emergency Notification System (ENS) at about 7:30 a.m. on January 11, 1991.
Subsequent to the above ENS notification, the licensee completed their investigation into this event cccurrence as documented in Condition Report 91-009. The licensee deterniined that contrary to the verbai report made on January 11, a safety system failure had not actually occurred.
The basis for this determination was documented in licensee memorandum D. Mackovjak to H. Hegrat dated January 22, 1991, which noted that the control complex "B" chiller was in " retest" at the time of "A" chiller failure.
Since the "B" chiller was supplying all required loads during the " retest" activity ard was capable of performing the safety system function, no safety system failure occurred.
In addition, the licensee determined that an event report was not required.
The inspectors i
concluded that the licensee's determinations were reasonable.
(2) Loss of Feedwater System / Main Turbine Trip System On January 20, 1991, at 6:00 a.m., while the reactor was at 100 percent power, control power for feedwater and turbine automatic trip circuits was deenergized. While conducting Periodic Test Instruction (PTI)-N27-FM1, " Reactor Feedpump Turbine Stop Valve Test," on the "A" turbine, a fuse blew in the power supply circuit for turbine valve position indication.
That power supply also provided pcwer to trip relays designed to actuate on a high reactor water level (level-8). Technical Specification 3.3.9, Action statement C, did not provide for the loss of three channels in a trip system for reactor feedpump turbine-A, main turbine, and motor driven feedpump; therefore, g
the licensee entered the provisions of Technical Specification 3.0.3 which required that action be initiated within one hour to place the unit in an OPERATIONAL CONDITION for which Technical Specification 3.3.9-1, item 2, did not apply.
In parallel with making preparations for a plant shutdown, the licensee initiated troubleshooting to identify the cause for the loss of power, tripped the "A" reactor feedpump turbine, and started the motor-driven feedpump in parallel with the "B" feedpump turbine. With the "A" reactor feedpump turbine tripped, the blown fuse was successfully replaced, restoring electrical power to the trip logic for the feedwater system / main turbine trip system.
The provisions of Technical
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Specification 3, 3 were exited at about 10:00 a.m.
Reactor power had been reduced during the event te about 80 percent to allow motor-driven and turbine-driven feedpump parallel operation.
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The licensee initiated Condition Report 91-016 to document the event and immediate corrective actions es stated above.
In addition, a " Management Preliminary Report" was written that documented the cause for the event to be a " shorted" reset lamp in the "A" reactor feedpump control circuit.
The licensee took additional corrective action by implementing a design change (DCP 91-22) that added a fuse block for the high reactor water level trip circuits which would electrically separate that power supply from future failures in the feedoump control circuit.
The root cause for the reset lamp f411ure was being evaluated by the licensee's engineering department.
The inspectors noted that the licensee's response to this event was in accordance with plant Technical Specifications. The licensee reported this event to the NRC Operations Center via the ENS at about 11:00 a.m. on January 20, 1991.
(3) Division 1 and_3_ Emergency Core Cooling Systems (ECCS)
Declared Inoperable On February 2,1991, at about 4:30 a.m., while the reactor was at 100 percent power, the Division 3 high pressure core spray (HpCS) system was declared inoperable. At the time of event
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occurrence, the licensee had completed a planned surveillance test that identified a high pump differential pressure in the
" required action" range.
In accordance with plant administrative controls the HPCS system was declared inoperable while an engineering evaluation of test data was performed.
With the HPCS system declared inoperable, another surveillance test being performed on emergency closed caoling (ECC) Train-A identified a high differential pressure in the " required action" range for ECC Train-A.
Again, in accordance with plant administrative controls ECC Train-A was declared inoperable while an engineering evaluation of test data was performed.
Since ECC Train-A provided a cooling support function, plant operators declared the supported equipment inoperable including the Division 1 low pressure coolant injection (RHR-A), reactor core isolation cooling (RCIC), and low pressure core spray (LPCS).
At 5:45 a.m. with both Division 1 and Division 3 of the ECCS inoperable, the licensee entered the provisions of Technical Specification 3.0.3.
As noted above, the licensee was performing an engineering evaluation of test data.
That evaluation continued in parallel with preparation to commence a plant shutdown.
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At about 9:00 a.m. the licensee completed evaluating the test l
data collected from the HPCS surveillance test.
As documented in the HPCs " Pump / Valve Record of Corrective Action" dated February 2,1991, the as-found condition was determined to be acceptable.
As permitted by American Society of Mechanical Engineers ( ASME),Section XI, the licensee revised HPCS reference values based on the specific and historical pump test data.
The HPCS system was declared operable and Technical Specification 3.0.3 was exited.
Following calibration of test instruments used for ECC Train-A, as permitted by ASME Section XI, the surveillance test on that system was reperformed.
The results of that test were acceptable and ECC Train-A and the supported Division 1 components were declared operable.
Subsequent review of this event by the I
licensee concluded that both Division 1 and 3 ECCS were in fact
" operable" during the event; therefore, the licensee concluded that the event was not reportable under 10 CFR 50.73.
The inspectors noted that the licensee's evaluation was reasonable and the engineering evaluations performed supported the continuous " operability" determination.
The licensee informed the NRC Operations Center of this ennt t
via the ENS at about 8:00 a.m. on February 2, 1991.
The licensee notified the NRC Operations Center upon declaring HPCS operable and exiting the provisions of Technical Specification
3.0.3.
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(4) Reactor Water Cleanup Isolation
On February 2, '1991, at about 12:30 p.m., while operating at 100 percent reactor power, an unexpected automatic isolation of the reactor water cleanup (RWCU) system occurred. At the time of event occurrence, plant operators were removing RWCU Filter-A from service in accordance with the system operating instruction.
The licensee identified the cause for this event to be
personnel error and an inadequate procedure. While making the i
system manipulation, the operator assigned the task opened the RWCU bypass valve too far allowing system flow to exceed the
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instrument limit. Once an accurate differential flow could not be measured, an artificial flow signal was generated resulting
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in the automatic system isolation.
Once system isolation occurred, plant operators verified an actual RWCU system leak had not occurred and restored the system to service.
The licensee's planned corrective actions included revising the system operating instruction to limit the use of the bypass valve during similar system operations and training of this event was to be provided to licensed operators.
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The licensee informed the NRC Operations Center of this event via the ENS at about 2:30 p.m. on February 2, 1991.
(5) Automatic Start of Engineered Safety Feature (ESF) Ventilation On February 9, 1991, at about 8:00 p.m., and again on February 10, at about 7:00 a.m., while operating at 96 percent and 90 percent reactor power, respectively, Train-A of the annulus exhaust gas treatment system (AEGTS) unexpectedly started. At the time of each event occurrence, Train-B of the AEGTS was operating and Train-A was in standby.
For each event, plant operators verified the standby train was not required and returned that train to a standby condition.
The licensee determined the cause for this event was a component failure due to a differential pressure transmitter setpoint found to have " drifted" low.
The instrument that had
" drifted" low was calibrated and,ts calibration frequency was changed from 6 months to 3 months. The licensee was evaluating the root-cause for the greater than anticipated instrument drift.
The licensee informed the NRC Operations Center of these events via the ENS at about 11:45 p.m. on February 9 and at aLout 9:30 a.m. on February 10, 1991, respectively.
(6) Reported Degradation of High Pressure Core Spray Previously, the licensee reported on October 24, 1990, the apparent loss of containment integrity due to a weld
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" indication" that was identified during inservice inspection.
At the time of discovery, the reactor plant was in Operational Condition 5, " Refueling." As documented in licensee _ Condition Report 90-346, dated October 13, 1990, further analysis of the identified " indication" allowed a use-as-is disposition. The inspectors reviewed the licensee's justification which evaluated the " indication" in accordance with ASME,Section XI, Paragraph IWB 3514.2. Based on the analysis performed, the inspectors concluded that the licensee's use-as-is disposition i
was supported by examination data and was in accordance with
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Based on the use-as-is disposition, the licensee concluded that no degradation in containment integrity existed and a licensee event report was not required.
The inspectors noted that the licensee's basis for not submitting a report in accordance with 10 CFR 50.73 was reasonable.
(7) Combined Leakage Rate Greater Than 0.60 La As previously documented in Inspection Report 50-440/90022, Paragraph 6.b.(3), the-licensee reported that excessive leakage
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past a containment ventilation isolation valve was identified during planned leak rate testing. At the time of that report the reactor plant was in Operational Condition 4, " Cold Shutdown," during the licensee's second refueling outage.
As documented in licensee Condition Report 90-407, the noted excess leakage was identified during a post-maintenance leak rate test. An acceptable local leak rate test had been performed on August 22, 1990, prior to any planned maintenance activity.
Following replacement of the isoiation valve av sator spring cartridge during the second refuel outage, the subject post-maintenance leak rate test was performed.
Subsequent to the reported leak rate failure, adjustments were mide on the containment ventilation isolation valve and a sicccessful leak rate test was performed on December 2, 1990, before the second refuel outage ended.
The licensee concluded that the verbal report made on November 22, 1990, was not required since an acceptable as-found leak rate was demonstrated on August 22, 1990, in addition, the leak rate failure reported on November 22, 1990, was identified during post-maintenance testing before the system was restored to service; therefore, no reportable leak rate in excess of allowable values existed through the containment ventilation isolation valve when that-system was required.
The inspectors concluded that the licensee's determination that no excess leakage was present and a report in accordance with 10 CFR 50.73 was not required was reasonable.
No deviations or violations were identified.
9.
plant Status Meeting (30702)
NRC Management met with CEI management on February 7,1991, at the NRC headquarters in Washington, in order to discuss:
the current status of monthly performance indicators; main steam isolation valve (MSIV) leakage corrective actions; Agastat relay replacement status; feedwater nozzle
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weld crack evaluation; recent personnel performance errors; and licensee performance during the seccnd refueling outage completed January 4, 1991.
Personnel in attendance at this meeting are identified by a "#" in Paragraph 1, The licensee presented improved quantification of previously reported MSIV leakage estimates which they documented on February 19, in LER_90-025, Revision 2.
The licensee proposed a tentative agenda for the feedwater nozzle wela crack evaluation meeting scheduled for February 21.
NRC management acknowledged the licensee's presentation and planned
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10. Commissioner Briefing and Site Tour (30702)
On February 25, 1991, NRC Commissioner James R. Curtiss visited the Perry plant.
During the visit, Commissionar Curtiss toured the facility observing plant conditions and on going plant operations.
In addition, Commissioner Curtiss observed a simulator scenario conducted at the Perry training center.
The licensee provided a briefing to Commissioner Curtiss that included recent plant performance, refuel outage performance, operations training and requalification program, maintenance program, and the self-assessment program.
Personnel attending the Commissioner Briefing are identified by a "+" in Paragraph 1.
11. Open Inspection Items Open inspection items are matters which have been discussed with the licensee, which will be reviewed further by the inspector, and which involve some action on the part of the NRC or licensee or both. One (1)
open inspection item disclosed during the inspection is discussed in Paragraph 6.
12.
Items For Which A " Notice Of Violation" Will Not Be Issued The NRC uses the Notice of Violation as a standard method for formalizing-the existence of a violation of a legally binding requirement.
However, because the NRC wants to encourage and support licensee initiative in the self-identification and correction of problems, the NRC will not generaliy issue a Notice of Violation for an issue that mu ts the tests of 10 CFR Part 2, Appendix C, Section V.G.
These tests are:
1) the issue was identified by the licensee; 2) the issue would be categorized as a Severity Level IV or V violation; 3) the issue was reported to the NRC, if required; 4) the issue will be corrected, including measures to prevent recurrence, within a reasonable time period; and 5) it was not an issue that could reasonably be expected to have been prevented by the licensee's corrective action for a previous violation.
Issues involving the failure to meet regulatory requirements, identified during the inspection, for which a Notice of Violation will not be issued are discussed in paragraphs 2, 4 and 7.
13.
Exit Interviews The inspector.; met i.ith the licensee representatives denoted in Paragraph 1 throughout the inspection period and on March 1, 1991. The inspector summarized the scope and results of the inspection and discussed the likely content of the inspection report.
The licensee did not indicate that any of_the information disclosed during the inspection could be considered proprietary in nature.
During the report period, the inspectors attended the following exit interviews:
Inspector Exit L de J. Hammer (Chief Examiner)
2/15/91 E. Rau (Chief Examiner)
1/21/91
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