IR 05000440/1989026
| ML20005D834 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 12/15/1989 |
| From: | Ring M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20005D832 | List: |
| References | |
| 50-440-89-26, NUDOCS 9001020039 | |
| Download: ML20005D834 (20) | |
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I V. S. NUCLEAR REGULATORY COMMISSION
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REGION III
Report No. 50-440/89026(DRP)
Docket No. 50-440 License No. NPF-58 Licensee:
Cleveland Electric Illuminating Company Post Office Box 5000 Cleveland, OH 44101 Facility Name:
Perry Nuclear Power Plant, Unit 1 Inspection At:
Perry Site, Perry, Ohio Inspection Conducted:
October 12 through November 21, 1989
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Inspectors:
P. L. Hiland G. F. O'Dwyer B. Drouin h.
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Approved By:
M. A. Ring, hief ReactorProjectsSection3B Date Inspection Summary Inspection on October 12 through November 21, 1989(Report No. 50-440/89026(DRP))
Areas Inspected:
Routine, unannounced safety inspection by resident inspectors of licensee action on previous inspection items; licensee event report followup; monthly surveillance observation; monthly maintenance observations; operational
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safety verification; onsite followup of events; and monthly plant status meeting.
I Results: Of the seven areas inspected, one deviation was identified in the j
area of operational safety verification (paragraph 6.b.(5)). One non-cited violation was identified involving a missed fuel oil surveillance
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(paragraph 3.g).
That deviation concerned the licensee's stated commitment in i
the USAR to provide backup Seismic Category I cooling water to the fuel pool heat exchangers from the Unit 2 emergency closed cooling water system prior to Unit I refueling.
Further, the present backup Seismic Category I cooling water supply from Unit 1 emergency service water was not able to be placed in service by remote-manual operation from the control room and performance of that system lineup would require draining of the selected emergency service water loop, thereby disabling other safety functions.
Licensee management was aware of the identified deviation and was addressing corrective action at the close of the inspection report.
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DETAILS 1.
Persons Contacted a.
Cleveland Electric Illuminating Company (CEI)
- A. Kaplan, Vice President, Nuclear Group
- M. Lyster, General Manager, Perry Plant Operations Department (PPOD)
- D. Cobb, Supervisor, Plant Operations, PPOD j
"W. Coleman, Manager, Operations Quality Section, Nuclear Quality Assurance Department (NQAD)
- G. Dunn, Compliance Engineer, Nuclear Service Department (NSU)
i M. Gmyrek, Manager, Operations Section, PPOD j
- H. Hegrat, Compliance Engineer, NSD
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- S. Kensicki,. Director, Perry Plant Technical Department (PPTD)
- T. Hogan, Compliance Engineer, NSD
- D. Igyarto, Manager, Training Department, NSD
- R. Newkirk, Manager, Licensing and Compliance Section, NSD
- K. Pech, Manager, Technical Section, PPTD i
- J. Pelcic, Quality Engineer, NQAD
- R. Stratman, Director, Nuclear Engineering Department (NED)
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- R. Tadych, Manager, Mechanical Design, NED
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- D. Takacs, Manager, Mechanical Maintenance Quality Section, NQAD l
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U. S. Nuclear Regulatory Commission
- P. Hiland, Senior _ Resident Inspector, RIII B. Drouin, Project Inspector, RIII
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- G. O'Dwyer, Resident Inspector, RIII
- C. Paperiello, Deputy Regional Administrator, RIII
- M. Clausen, Acting Deputy Director-DRP, RIII
- R. Knop, Chief, DRP Branch 3, RIII
- M. Ring, Chief DRP Section 3B, RIII
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- H. Miller, Director DRS, RIII
- E. Weiss, Acting Chief Operations Branch, RIII l
- Denotes those attending the management meeting held on October 26, 1989.
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- Denotes those attending the exit meeting held on November 21, 1989.
2.
LicenseeActiononPreviousInspectionFindings(92701,9270D
a.
(Closed) Open Item (440/88012-07(DRP):
Change out of radiation
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monitor sample flow instrument during troubleshooting.
This optn item concerned whether or not Work Order (WO) 88-5863, which authorized troubleshooting and repair activities, permitted the installation of a new differential pressure switch in the drywell atmosphere radiation monitor with a range different from
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that originally employed to provide sample flow indication and alarm functions. The inspector determined that the switch was replaced adequately in accordance with the vendor manual and Field Change Requests (FCRs) 10231 and 10260.
The documentation of WO 88-5863 was made clear and this item is closed, b.
(Closed) Open Item (440/89022-05(DRP):
Performance Standards for Nonlicensed Operators.
As detailed in Sections 3.2.2 and 3.2.8 of the Perry Diagnostic Evaluation Team (DET) Report dated May 1989, adequate performance standards for nonlicensed operators had not been established.
The licensee responded to this item in letter PY-CEI/NRR-1043L, Section 2.1.2.2, dated July 29, 1989.
That response detailed the licensee's plan to develop and implement performance standards for nonlicensed operators.
During this report period, the inspectors reviewed completed actions by the licensee that pertained to this item.
Following a licensee evaluation of past program weaknesses based on input from both licensed and nonlicensed operators, the licensee established minimum requirements for nonlicensed operators during the conduct of plant equipment rounds.
Those minimum standards were incorporated into Operations Administrative Procedure (OAP)-1702, via TC-3 to Revision 7 dated September 18, 1989. The established standards included expected performance in the use of safety equipment and apparel; radiological control practices; monitoring of local annunciator panels; monitoring of pumps, motors, turbines, HVAC and the generator exciter; and monitoring of electrical switchgear.
Training of nonlicensed operators to the established standards was conducted in accordance with training lesson plans OT-3022-31 and OT-3022-07, " Plant Equipment Rounds."
In addition to training nonlicensed operators, training was conducted for the licensed supervising operators.
In order to assure the minimum performance standards were being accomplished, the licensee established and implemented a routine performance evaluation checklist.
The inspectors reviewed completed checklists that documented nonlicensed operator performance to the established standards based on field observations by operations department supervisors.
The inspector noted that the licensee had taken steps to implement a program to improve nonlicensed operator performance.
The completed review of past program weaknesses, establishment of performance standards, training of both nonlicensed and licensed supervisory personnel, and the continued monitoring of personnel performance to the established standards indicated an adequate level of operations management involvement to improve the performance of nonlicensed operator rounds.
This item is closed.
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c.
(Closed) Unresolved Item (440/89022-11(DRP):
Post Maintenance Testing of Standby Liquid Control (SLC) System.
As detailed in Section 3.3.7 of the Perry Diagnostic Evaluation Team (DET) Report dated May 1989, the planned post maintenance test for SLC valve F001A under Work Order 89-922 did not include a pipe flush af ter valve stroking.
Since this piping was not heat traced, the potential existed for sodium pentaborate to precipitate out of solution and potentially render the system inoperable.
The inspectors considered the planned post maintenance test to be inadequate.
The licensee responded to this item in letter PY-CEI/NRR-1043L, Section 2.1.3.7, dated July 29, 1989.
That response stated that administrative controls were in place during the performance of work order 89-922 that would have assured proper post maintenance testing prior to declaring the tested system operable.
This item remained unresolved pending the inspectors review of the licensee's administrative controls.
During this report period, the inspectors reviewed Perry Administrative Procedure (PAP)-0905, " Work Order Process," Revision 9, dated December 19, 1988, to determine if adequate administrative controls existed to assure the proper performance of post maintenance testing as stated in the licensee's July 29 response to the DET report.
That administrative procedure contained the required planning instructions for inclusion of post-maintenance testing in paragraphs 6.2.3.16, 6.2.4.7, and 6.2.6.
Specifically, paragraph 6.2.6 required the maintenance planner to consult the responsible system engineer for all retest requirements.
The licensee's response stated that the system flush requirements had been incorporated into an earlier revisinn to Work Order 89-922; however, the inspectors noted after review of the completed work order that system flushing instructions were not included until Revision 3 of the work order, which was subsequent to the DET inspectort original observation.
The licensee stated that their July 29 response was based on verbal information from the system engineer and that an actual review of the earlier work order revision was not performed.
The inspector noted that Revision 0 through Revision 2 contained post-maintenance test instructions for valve stroking (Sections 5.1.1.4 and 5.1.1.5 of SVI-C41-T2001) which were a subset of the final properly performed post maintenance test (i.e. Sections 5.1.1 Step 1 through Step 12 of SVI-C41-T2001).
The performance of post maintenance testing was controlled by PAP-0905, paragraph 6.5.
As detailed in that instruction, the unit supervisor (SRO) approved the post maintenance test after completion of the work effort but prior to actual post maintenance testing.
In addition, as detailed in paragraph 6.6, completed work orders, including completed post maintenance testing activities, were reviewed by the nuclear quality assurance department (NQAD) and accepted by the unit supervisor (SRO).
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The-licensee's July 29 response stated that the SLC system would not have been declared OPERABLE until the work order review was completed.
However, the inspectors noted that the " system engineer" review of the completed work order was not a prerequisite for acceptance of the completed work package by the unit supervisor.
The inspectors further noted that Work Order 89-922 was accepted by the unit supervisor and the SLC system was declared OPERABLE on February 17, 1989.
The system engineer review of completed Work Order 89-922 was performed on February 21, 1989.
As discussed above, the licensee's administrative procedure for control of work orders contained several checkpoints to assure the adequacy of post maintenance testing.
Those checkpoints detailed in PAP-0905 included:
(1) paragraph 6.2.3.16, required the maintenance planner to determine the need for a post maintenance test based on the work performed; (2) paragraph 6.2.6, required the maintenance planner to consult with the system engineer to determine post maintenance test requirements; (3) paragraph 6.5.1, required the review and approval of the planned post maintenance test after work completion, but prior to test performance, by the unit supervisor (SRO); (4) PAP-0905, paragraph 6.6.2, required a review by nuclear quality assurance department of the completed work order inspection reports; (5) paragraph 6.6.3, required the unit supervisor (SRO) to ensure all required post maintenance tests were completed; and (6) paragraph 6.6.4, required the system engineer to perform a technical review of the completed work package.
After review of Work Order 89-922 and discussions with cognizant licensee personnel, the inspectors concluded that the inadequate post maintenance test instructions that were contained in Revision 0 through 2 of the work order resulted from inadequate communications between the maintenance planner and the system engineer. However, the inspectors noted that the required approval to perform the post maintenance test was not yet obtained prior to the DET inspectors initial observations.
Since there existed several additional checkpoints in the work order process to assure the adequacy of post maintenance testing, the licensee's conclusion that the inadequate post maintenance test instruction would have been self identified, appeared reasonable.
In addition to the above, the inspectors reviewed Perry Plant Technical Department (PPTD) Plant Engineering Guidelines (PEG)-002,
" Technical Reviews," and PEG-106, " Post Maintenance Testing." The purpose of that review was to determine the method used by system engineers to select appropriate post maintenance test requirements.
The inspectors noted that those guidelines contained adequate instructions for the system engineer to establish appropriate post maintenance test activities.
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Based on review of administrative controls in place at the time of the DET inspectors identifying the subject inadequate post maintenance testing instruction, the inspectors-concluded that the licensee's established work order process cortained appropriate checks and additional reviews that would have identified the inadequacy.
Further, the inspectors concluded that adequate instructions existed to allow the system engineer to determine appropriate post maintenance testing and to perform technical review of completed work orders.
This item is closed.
d.
[ Closed)OpenItem(440/89022-13(DRP)):
Guidance For Abnormal or Erratic Valve Actions During Testing.
As detailed in Section 3.4.1 of the Perry Diagnostic Evaluation Team (DET) Report, the DET inspectors noted that written guidance or criteria did not exist which would define erratic or abnormal valve action.
The licensee responded to this item in letter PY-CEI/NRR-1043L, Section 2.1.4.2.(5), dated July 29, 1989.
As stated in that response, the licensee revised Perry Administrative Procedure (PAP)-1101, " Inservice Testing of Pumps and Valves," to provide guidelines for erratic or abnormal valve operation.
Section 6.4.3.4 of that procedure included a clarifying note, as stated in the licensee's July 29 response which defined erratic or abnormal valve operation. This item is closed, c.
(0 pen) Open Item (440/89022-20(DRP)):
Contractor Support.
As detailed in Section 3.6.1.3 of the Perry Diagnostic Evaluation Team (DET) Report dated May 1989, the licensee relied heavily on contractor support within selected areas of the Plant Technical Department and the Nuclear Engineering Department.
The DET expressed concern that a rapid reduction in contractor support could adversely impact the licensee's ability to accomplish engineering support tasks.
The licensee initially responded to that concern in letter PY-CEI/NRR-1043L, Section 2.1.6.2, dated July 29, 1989.
The licensee submitted an additional response to the subject item in letter PY-CEI/NRR-1071L dated October 11, 1989.
As stated in the licensee's initial response, a detailed five year plan for engineering support was being developed.
Specific elements of that plan, provided in the licensee's additional response, included consideration of permanent plant positions for selected contractor personnel, use of their career opportunities program, and recognition of the need to maintain some contractor staff until a sufficient turnover to permanent personnel can be achieved. This item will remain open pending the inspectors review of the licensee's five year plan for engineering support.
No violations or deviations were identified.
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3.
Licensee Event Report Followup (92700)
Through direct observations, discussions with licensee personnel, and review of records, the following event reports were reviewed to determine that reportability requirements were fulfilled, immediate corrective action was accomplished in accordance with Technical Specifications, and corrective action to prevent recurrence had been accomplished, a.
(Closed) LER 86059-00 and 86059-01:
Replacement of a pressure gauge on an air receiver tank resulted in the Division 3 Emergency Diesel Generator (EDG) being rendered inoperable.
In LER 86059-00 the licensee determined that maintenance personnel did not realize (personnel error) both air receiver tanks were required for Division 3 EDG to remain in an operable status and one air tank was isolated to replace an air pressure gauge. Tne licensee issued Technical Specification Position Statement (TSPS)
No. 003 in December 1986 in an attempt to clarify the number of Division 3 air receiver tanks necessary for operability. The licensee also determined that the installation of an isolation valve on the gauge would allow gauge changeout without affecting Division 3 EDG operability (Design Change Package (DCP)86-342).
After further review the licensee determined that TSPS-003 only described the air pressure required (210 psig) for each tank to be operable and did not indicate both tanks were required for Division 3 to be operable.
TSPS-063 was issued June 29, 1989, stating that Divisions 1 and 2 required one tank and Division 3 required two tanks to have an operable air start system. The licensee also determined that DCP 86-342 was no longer required since personnel error and not equipment failure caused Division 3 to be rendered inoperable.
The installation of isolation valves on the pressure gauges may occur at some future date to facilitate maintenance on the gauges. LER 86059-01 reflected the licensee's root cause (personnel error) and final corrective action (TSPS-063).
The inspector reviewed records and interviewed CEI licensing staff and determined that corrective action was appropriate.
A review of records indicated no similar events had occurred.
This LER is closed.
b.
(Closed) LER 86083-00:
An unexpected reactor protection system (RPS) actuation occurred during the performance of an inservice inspection instruction (ISI) due to the inaccessibility (testability)
of electronic test points.
ISI-B21-T1300-1, " Reactor Coolant System Leakage Pressure Test," required the reactor vessel high pressure relay contacts to be jumpered out.
During the installation of the jumperafusewasblown.
The licensee determined that the physical configuration of the relay terminals complicated jumper installation due to inaccessibility.
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l The confined location created the potential for inadvertent grounding of the circuit during jumper installation.
The licensee
improved the connection lugs to the terminals of the relays involved.
The licensee also reviewed all other ISIS and periodic test
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instructions (PTIs) for the identification and modiiication of similar terminals.
Priority of modification went to surveillances with the most frequent periodicity (i.e., weekly / monthly / quarterly).
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inspector verified through document reviews that all surveillance
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instructions (SVIs), PTIs and ISIS were analyzed for applicability.
The modifications included the design and installation of circuit test cards, sliding link connections and test lug additions.
The RPS
and average power range monitor (APRM) test connection modifications
had been completed and modification of the emergency core cooling
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system connections was on going.
The inspector observed some of the test connection modifications contained in control room panels.
The modifications appeared to eliminate errors due to poor connections or cramped working spaces.
A document review substantiated that there
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had been no subsequent errors due to cramped operating spaces after
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the modifications had been completed.
This LER is closed.
c.
(Closed) LER 87014-00:
An inadequate restoration sequence due to
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poor work package (procedural error) on a level transmitter resulted in a pressure transient in reactor vessel level instrumentation causing high pressure core spray (HPCS) initiation.
The licensee determined that pressure transients in reactor vessel level
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instrumentation had more impact on the HPCS and redundant reactivity
control system (RRCS) than other emergency shutdown systems because
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HPCS and RRCS used only two instrumentation reference legs while
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other systems had four reference legs.
The licensee revised all
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surveillance instructions (SVIs) to include a caution statement when
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being performed in Modes 1 and 2.
All work orders were revised to include the precaution and all SVIs and repetitive tasks were i
rescheduled to be performed only in Modes 3, 4 and 5 since a r
spurious HPCS initiation could result in a serious transient in l
Mode 1.
All applicable SVIs and repetitive tasks were rescheduled
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and revised as required as verified by the inspector.
A modification i
to HPCS and RRCS completed during Refueling Outage 1 provided other reference leg taps to mitigate any future spurious pressure transient sensed by the reactor vessel level instrumentation.
The inspector verified through a review of condition reports that licensee corrective action precluded other pressure transients while restoring level
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transmitters to service.
This LER is closed.
d.
(Closed) LER 87031-00 and 87031-01:
Relay contacts associated with l
loss of coolant accident (LOCA) HPCS initiation which would isolate individual non-class 1E loads from Division 3 were not verified by inservice inspection (ISI) program.
The licensee identified this deficiency while performing corrective action, " yellow line drawing" reviews, for LER 86052.
Surveillance Instruction (SVI)-E22-T1192 was revised on July 9,1987, to include the subject relay contacts
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i in the ISI program.
The review of all SV!s for similar problems was completed in January 1988 and identified no other lechnical Specification violations. The inspector conducted a document review and determined that no other condition reports had been initiated due to relay contacts being omitted from the ISI program.
The inspectors noted that the licensee's failure to perform the above described testing was previously identified as a Violation (440/87016-04(DRP)) of Technical Specification 4.3.3.2 for which a Notice of Violation was not issued in accordance with the provisions of 10 CFR 2 (ref. IR 440/87016, Paragraph 6).
This LER is closed.
e.
(Closed) LER 88015-00:
Unexpected bypass valve (BPV) opening during reactor startup due To a procedural deficiency resulted in a reactor scram (Level 3).
The licentee reported in LER 88015-00 that System Operating Instruction (501)-B21 would be revised.
That revision would assure that the pressure regulation set point would be raised to 200-400 psig above steam line pressure prior to opening main steam line isolation valves (MSIVs) to preclude automatic BPV opening. Other corrective actions included changing the color code indication of the BPV opening on the control room display system from white to amber and to brief operators on the event.
The inspector verified through document reviews and interviews the following corrective actions were completed:
Temporary Change Notice (TCN)-4 to 501-B21, Revision 4 effective April 30, 1988, required the appropriate manipulation of the pressure regulation set point; the BPV opening indication color was changed to amber on December 14, 1988; and operator training included a discussion of LER 88015-00.
The inspector noted that there had been no other reactor scrams due to a BPV opening during startup.
This LER is closed, f.
(Closed) LER 88017-00 and 88017-01:
A blown fuse in the reactor protection system (RP5) during a surveillance caused a scram of Group 3 control rods (8) which resulted in reactor vessel low level (Level 3) full scram.
LER 88017-00 stated that the fuse was sent to the vendor for failure analysis and corrective action would then be formulated.
The vendor determined that the fuse failed from an overload condition although further monitoring and analysis conducted by the licensee from July 1988 to September 1988 could not identify any overload condition in the specific circuit to the Group 3 scram solenoid valves.
The licensee changed the 15 amp fuses to 20 amp fuses in the eight Group 3 scram solenoid valve circuits. Design Change Package (DCP)89-027 was approved February 28, 1989.
The eight 20 amp fuses were installed by September 1989 and there were no subsequent blown fuses due to overload conditions on any of the scram solenoid valve circuits.
This LER is closed, g.
(Closed) LER 88031-00:
Personnel errors resulted in missed surveillance on Division 2 and 3 fuel oil storage tanks.
Miscommunication and a deficient surveillance instruction (SVI)
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review resulted'in full credit being taken for a partial SVI on the F
Division I fuel tank and causing the Division 2 and 3 fuel tank SVIs
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to be 53 days late.
The licensee determined that improved communications were necessary to preclude another late SVI.
The inspector determined through document review that Perry Administrative r
Procedure (PAP)-1105 was revised (Revision 5, effective October 31,
1988). which stressed communications and required that additional
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steps be included in all SVI reviews.
In addition, all plant staff
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involved in the conduct and review of SVIs reviewed the circumstances l
of LER 88031-00.
No subsequent SVIs have been late due to
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miscommunication.
Corrective actions appeared to be adequate.
Failure to perform the above described testing is contrary to Perry, Unit 1 Technical Specification 4.8.1.1.2.c and is a violation
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(440/89026-02(DRP)).
This violation meets the tests of 10 CFR 2
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Appendix C,Section V.G.1; consequently, no Notice of Violation will t
be issued, and this matter is considered closed.
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h.
(Closed) LER 88032-00:
Failure of a ball-valve and door seal resulted in inoperable containment airlock doors and momentary loss
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of containment integrity when a technician exited containment.
The licensee determined that a lack of preventive maintenance (PM)
contributed to the failure of the 3 way ball valve (3WBV) in the containment airlock door.
Corrective action stated in LER 88032-00 included the rebuild of remaining 3WBVs, implementation of a PM
program for 3WBVs and the training of operators to properly
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administer future similar problems.
The inspector verified through interviews and document reviews that the licensee completed the following actions:
The licensee forwarded the failed door seal to the vendor for analysis then reviewed all door seals in stock with vendor failure analysis data; the 3WBVs were rebuilt; repetitive tasks R-89-111 through 116 were developed and implemented for PMs on 3WBVs; and operators were briefed on the contents of LER 88032-00.
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past LERs, the 3WBV PMs were performed as scheduled, and tool kits i
with instructions were placed in the airlocks so that plant
personnel could extricate themselves from malfunctioning airlocks.
There had been no subsequent 3WBV failures.
Corrective action
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appeared to be appropriate.
This LER is closed.
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(Closed) LER 88033-00:
A failed leak detection (LD) transmitter caused Reactor Core Isolation Cooling (RCIC) system containment isolation.
The licensee replaced the transmitter (Rosemount) and forwarded the failed transmitter to the vendor for failure analysis as stated in LER 88033-00.
Further analysis by the licensee, BWR owners group, and the vendor resulted in the development of a 25 milliamp (ma) SVI that would identify Rosemount transmitters (models 1153 and 1154) which could fail through two known failure mechanisms.
All 1153 and 1154 transmitters installed or in stores were tested during Refueling Outage 1.
All SVIs were being revised to require the 25 ma calibration on 1153 and 1154 transmitters for three years.
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SVI revisions were to be completed by September 30, 1990.
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been no subsequent failures of 1153 and 1154 transmitters resulting I
in isolation. logic trips since the implementation of the 25 ma test, i
The licensee took extensive, timely and appropriate action.
This LER i
is closed.
i One violation for which a " Notice of Violation" was not issued was identified.
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4.
Monthly Surveillance Observation (61726)
f For the below listed surveillance activities the inspectors verified one
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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 components were properly accomplished; test results conformed with technical
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specifications and procedure requirements and were reviewed by personnel r
other than the individual directing the test; and that any deficiencies l
identified during the testing were properly reviewed and resolved by
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appropriate management personnel.
Surveillance Test No.
Activity l
SVI-R43-T1318, Revision 3
" Diesel Generator Start and Load, Division 2" SVI-R10-T5217,(Partial)
" Electrical Distribution System Energization Check" No violations or deviations were identified.
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5.
Monthly Maintenance Observation (62703)
Station maintenance activities of safety related systems and components listed below were observed / reviewed to ascertain that they were conducted r
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
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control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and fire prevention controls were implemented.
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f Workrequestswerereviewedtodeterminestatusofoutstandingjobs and to assure that priority was assigned to safety related equipment
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maintenance which may affect system performance.
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The following maintenance activities were observed / reviewed:
Work Order
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(WO) 89-6789, which was the replacement of the motor bearings for the i
"A" supply fan of the ventilation system that served the technical
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Support center and the emergency response information system (ERIS)
computer room; Repetitive Task R86-4214, which was breaker maintenance
for the Division 2 4160 volt bus; WO 89-6127, which was the calibration
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of the low pressure switch (IR44N0207A) for the right bank of the Diesel Generator starting air system; and WO 88-2285, which removed, rebuilt, l
and reinstalled the hydraulic actuator for the emergency service water
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pumphouse ventilation system recirculation damper IM32-F0508.
following completion of the above-mentioned maintenance, the inspectors t
verified that these systems had been returned to service properly.
No violations or deviations were identified.
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6.
Operational Safety Verification (71707)
a. General The inspectors observed control room operations, reviewed applicable
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logs, and conducted discussions with control room operators during this inspection period.
The inspectors verified the operability of selected emergency systems, reviewed tag-out records and verified tracking of Limiting Cc>nditions for Operation associated with
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affected components.
Tours of the intermediate, auxiliary, reactor,
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and turbine buildings were conducted to observe plant equipment l
conditions including potential fire hazards, fluid leaks, and
excessive vibrations, and to verify that maintenance requests had
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
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accordance with the station security plan.
l The inspector observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection controls.
These reviews and observations were conducted to verify that facility operations were in conformance with the requirements established under technical specifications, 10 CFR, and administrative procedures, b.
Details (1) On October 12, 1989, at about 2:30 a.m., a plant operator identified that the high pressure core spray (HPCS) waterleg
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pump was not running.
At the time of discovery the plant was operating at 100 percent power and a Division 1 planned
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maintenance outage was in progress.
The function of the HPCS
waterleg pump was to maintain system pressure to avoid i
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water-hammer in the event of a HPCS actuation.
By plant L
procedures, a loss of HPCS system pressure would require
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~ declaring the HPCS system inoperable because of the potential
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for water-hammer.
In addition, since Division 1 emergency core
cooling systems were already inoperable, loss of the HPCS would
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require a plant shutdown by Technical Specifications.
At the time the HPCS waterleg pump was discovered not running,
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L the HPCS low header pressure alarm was not actuated and plant
operators verified that adequate system pressure existed.
Plant operators performed a " fill and vent" verification of the
HPCS system and restarted the HPCS waterleg pump.
The licensee L
initiated Condition Report 89-362 to document the immediate corrective actions and to determine root cause identification for the waterleg pump being turned off.
While a final
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determination could not be established as to how the HPCS waterleg pump was turned off, the inspectors noted that the
h operations department supervision conducted a prompt and
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thorough investigation of this event.
Lessons learned from that
investigation were clearly promulgated to operations personnel
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by the senior operations coordinator in the Daily Instructions.
(2) On October 16, 1989, at 10:56 a.m., while the plant was operating at 100 percent power, the off gas building ventilation exhaust (OGBVE) gaseous alert alarm was received in the control room and operators noted a decrease in the off gas I
system flow rate of about 5 standard cubic feet per minute (scfm).
Operators entered Off Normal Instruction (ONI)-017,
"High Radiation Levels within the Plant (Unit 1)," dispatched i
plant operators to verify that system loop seals were filled and notified Health Physics.
Since the OGBVE alarm monitored
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ventilation flow from the off gas building and portions of the
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turbine and turbine power complex buildings, operators
evacuated nonessential personnel from those buildings.
At about 11:18 a.m., the OGBVE particulate alert (21,000 cpm)
and OGBVE iodine alert (5,000 cpm) were received in the control room.
At about 11:40 a.m., plant operators filled the four off gas system loop seals which were located on the 568' level of the turbine power complex.
Off gas process flow returned to normal.
Gaseous radiation levels on the OGVBE monitors declined but then increased whereupon the plant operators again
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refilled the four loop seals at 11:45 a.m. and radiation levels
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decreased.
During the entire event, no low level indications or alarms were received on the three off gas system loop seals that were instrumented.
At noon the gaseous radiation release
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appeared to be terminated when off gas process flow was isolated from dryer "B" (and therefore the uninstrumented loop
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seal for dryer chiller "B") and directed to dryer "A" (which was served by the uninstrumented loop seal for dryer chiller i
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"A").
Health physics grab samples confirmed elevated airborne
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radioactivity levels at the OGBVE monitors, in the turbine power
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complex (TPC), and in the turbine building which communicated i
with the TPC.
- Throughout the event, radiation levels in the off gas vent
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pipe (an effluent release point) remained below their alarm
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setpoints.
Samples drawn from the off gas vent pipe were
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analyzed to be well below the Technical Specification (TS)
limit.for gaseous effluent dose rate.
Whole body dose rate
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was calculated to be 0.0398 mrem /yr (TS limit:
500 mrem /yr)
i and skin dose was 0.0711 mrem /yr (TS limit:
3,000 mrem /yr).
The inspectors monitored licensee actions during the event from
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the control room.
Actions taken were in accordance with ONI-017 and it was exited at about 2:30 p.m.
Operators tagged the "B" dryer out of service.
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Since the event, the dryer logic was verified to be correct by i
Work Order (WO) 89-6266 which eliminated that likely cause of loop seal failure. WO 89-6304 was written to rework the loop seal drain valve (which included lapping and blue checking) and
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a Mechanical Foreign Item package (MFI 1-89-215) was initiated to cut the drain line and cap it so that leakage through the drain valve would be impossible.
Design Change Package (DCP)
,88-347 which would add level instrumentation for the loop seal was being planned for the second refueling outage.
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Additionally, the Nuclear Engineering (Department was preparing an engineering design change request EDCR) to add a control valve to isolate the loop on low level and add an alarm.
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(3) On October 25, 1989, the licensee identified that four Class-1 piping welds were excluded from the pre-service inspection
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requirements of the ASME Code,Section XI.
The subject welds were located in the reactor vessel vent and head spray line.
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The licensee initiated Condition Report 89-382 to document the identified discrepancy and to provide documentation of the corrective action.
The licensee proposed to use the shop examinations of the four welds in lieu of preservice inspection as allowed by the ASME Code.
The inspectors discussed the proposed resolution with a Region III specialist inspector during the report period.
The inspectors concluded that the licensee's proposed resolution was reasonable and would meet the requirements of the ASME Code.
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(4) Plant Housekeepino During this report period, the licensee initiated a housekeeping improvement program.
Improvements in the licensee's housekeeping program were implemented in Perry Administrative Procedure (PAP)-0204, Revision 5, effective October 30, 1989, " Housekeeping / Cleanliness Control Program,"
and were based on comments from industry peer groups.
The inspectors were briefed by cognizant licensee personnel on the changes to their existing program and the results that were anticipated.
Although it was too early in the implementation for the inspectors to note a dramatic change in overall plant housekeeping, the inspectors noted improved housekeeping in the fuel handling building, circulating water pump house, and the service water pump house. The inspectors acknowledged the licensee's stated housekeeping goals and will continue to monitor licensee performance in that area.
(5) Fuel Pool Cooling Heat Exchanger Backup Coolina Water During this report period, the inspectors performed a field walkdown of accessible portions of the fuel pool cooling and cleanup (FPCC), emergency closed cooling (ECC), and the emergency service water (ESW) systems.
The purpose of those field walkdowns was to verify system status and to inspect major components for leakage, proper lubrication, cooling water supply, and any condition that might prevent the fulfillment of system functional requirements.
In general, the inspectors noted that major components of the above systems were being maintained in goud working order.
However, the inspectors noted that the backup Seismic Category I, source of cooling water to the FPCC system was not the emergency closed cooling water system as indicated in Section 9.1.3 of the Perry Updated Safety Analysis Report (USAR).
As discussed in Section 9.2.2 of the Perry USAR, the Unit 2 emergency closed cooling system was designed to provide cooling water to the fuel pool heat exchangers following a design basis accident.
At the time of this report, the Unit 2 emergency closed cooling system was not functional and the backup Seismic Category I cooling water supply to the fuel pool heat exchangers was from the Unit 1 emergency service water system.
Section 9.2.2.3 of the Perry USAR discussed the use of the Unit 1 emergency service water system prior to operation of Perry Unit 2.
The use of Unit 1 emergency service water (ESW) in place of Unit 2 emergency closed cooling (ECC) water was to be facilitated by using installed Unit 2 ECC piping crossconnected
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via " spectacle-flanged" pipe to the Unit 1 EW system.
Detailed instructions to place that backup, Seismic Category 1, ESW system into the fuel pool cooling mode were contained in System Operating Instruction (501)-P45/49, " Emergency Service Water and Screen Wash Systems (Unit 1)," Revision 0, dated August 22, 1989.
The inspectors noted that the alignment instructions required the draining of the selected ISW system (A or B) in order to remove the installed blank flanges.
The staff's initial review of the Perry spent fuel pool cooling and cleanup system was documented in Section 9.1.3 of NUREG-0887, " Safety Evaluation Report Related To The Operation Of Perry Nuclear Power Plant, Units 1 and 2," dated May 1982.
The inspectors review of that SER and Supplements 1 through 10 did not identify a staff evaluation on the acceptability of continued use of the Unit 1 emergency service water system as the backup, Seismic Category I, source of cooling water to the fuel pool cooling system.
Of particular note by the inspectors was the staff's conclusion that the requirements of GDC-44,
" Cooling Water" were satisfied for the fuel pool cooling system by use of Unit 2 emergency closed cooling system.
The inspectors noted that in order to place an ESW system in the backup fuel pool cooling mode, the selected ESW loop was required to be drained; therefore, the associated ESW loop safety-related loads (e.g. emergency diesel, RHP, heat exchanger, and ECC heat exchanger) would not be capable of performing their safety functions.
Based on that system interdependence, the inspectors concluded that the current backup cooling method to the fuel pool cooling system would not be readily available under postulated accident scenarios.
Perry USAR, Revision 1 dated March 1989, Section 9.2.2,
" Emergency Closed Cooling System," stated that "The Unit 2 emergency closed cooling system will be available to provide fuel pool heat exchanger cooling water prior to Unit I refueling." Further, the USAR stated that:
"Any time after start of the emergency closed cooling system operation, cooling may be restored to the fuel pool heat exchangers by remote-manual action from the control room." As discussed above, contrary to these stated commitments, (1) the Unit 2 emergency closed cooling system was not available prior to Unit 1 refueling; and (2) the current backup Seismic Category I cooling water supply from the Unit 1 emergency service water system was not able to be placed in service by remote manual action from the control room.
The licensee's failure to provide a backup Seismic Category I cooling water supply from Unit 2 emergency closed cooling system capable of remote manual operation is a Deviation (440/89026-01(DRP)) from a commitment.
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i (6) Zebra Mussels During the report period, the licensee briefed the inspectors on planned testing to treat / control zebra mussels (Dreissena polymorpha) by chlorination.
Upon approval from the Ohio EPA, the licensee planned to conduct a trial test by continuously chlorinating the plant service water system for a period of two to three weeks in December 1989.
If successful, the licensee planned to perform treatinents in a similar manner during the months of August, September, and October when juvenile zebra mussels would be most susceptible to the chlorination treatment.
The inspectors acknowledged the licensee's plans and requested that a similar briefing be provided to Region III at the next management meeting conducted at the Perry site.
One deviation was identified as discussed above in paragraph 6.b.(5).
7.
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, condition reports; direct observetion 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 procedures and license conditions; and verification of the nature of the event.
Additionally in some cases, the inspectors verified that licensee investigatlon had identified root causes of equipment malfunctions and/or personnel errors and the licensee was taking or had taken appropriate corrective actions.
Details of the events and licensee corrective actions noted during the inspectors' followup are provided in Paragraph b. below, b.
Details (1) Service Water Chlorination System Operated Beyond Ohio EPA Time Limits At about 11:00 p.m. on October 25, 1989, the licensee identified that the plant's service water chlorination system had been operated for about nine hours on October 25.
The licensee's state EPA time limit for operation of the chlorination system was two hours per day.
The inspectors reviewed licensee letter PY-CEI/0 EPA-0091L, dated October 30, 1989, which reported the subject event to the Ohio EPA.
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stated in that report, the license limit of 0.5 mg/l of free available chlorides was not exceeded during the event based on samples taken at the service water discharge.
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't The licensee determined the cause for this event to be a
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combination of personnel error and a planned power outage that contributed to the event by preventing the dechlorination system from starting-Appropriate corrective action was identified and included training of plant technicians and supervisors on the chlorination and dechlorination systems.
In addition, the licensee was to review plant procedures to assure
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power cutages affecting those systems were identified.
In accordance with 10 CFR 50.72, the licensee reported this event to the NRC Operations center via the ENS at about 1:00 a.m.
on October 26, 1989.
The inspectors reviewed the licensee's root cause analysis for the event and the corrective action taken.
Of particular interest was the comparison between this event and l
an event that occurred on September 21, 1989, when the licensee L
experienced an excursion of pH values in the plant's discharge due to an over addition of sulfuric acid to the cooling tower basin.
The inspectors noted that the two events had similar root causes attributable to personnel error for failure to follow procedures.
However, the inspectors concluded that the two events were discrete occurrences that were not directly related.
In addition, in both events the personnel errors were
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in part due to equipment outages that contributed to a less than complete understanding of system operations.
The inspectors found the licensee's investigation, immediate corrective actions, and long term corrective action to be appropriate.
(2) Planned Loss of Power to the Emergency Offsite Facility j
At about 2:00 a.m. on November 4,1989, while operating at 100
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percent power, the licensee deenergized the power supply buss to the emergency offsite facility (EOF) in order to perform l
preventive maintenance.
The licensee discussed their planned actions with the inspectors and Region III management prior to
the outage.
The licensee indicated that key responders to an
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emergency plan activation were ware of the EOF outage and contingency plans were in p to activate the " backup" EOF.
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In accordance with the r irements of 10 CFR 50.72, the licensee notified the.
Operations Center of this planned buss outage via thefffS at about 2:00 a.m. on November 4,1989.
The planned mainteriance activity was completed and the E0F power supply restored on November 5, 1989.
(3) Unusual Event Declared Due to Fire Within The Protected Area On November 14, 1989, while operating at 100 percent power, the licensee declared an Unusual Event due to a small fire that
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lasted more than ten minutes.
While performing routine rounds,
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a licensee security officer detected a smoke odor in the
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The service building annex was located within the protected area about 20 feet from the plant service building and was used as a general office facility.
A member of the plant fire brigade was dispatched to.the service building annex to identify the location of the smoke odor.
At about 5:40 p.m. the licensee's full fire brigade was activated and the offsite Perry Township fire department was called for assistance.
At about 5:50 p.m. both the site fire brigade and the Perry Township fire department were at the scene of the smoke odor and began efforts to locate the source.
The source was found to be located beneath a stairwell and water was applied. At 6:24 p.m. the fire was declared out.
The shift supervisor properly declared an Unusual Event at 6:07 p.m. after initial efforts to locate and extinguish the source of the smoke odor-exceeded ten minutes.
The Unusual Event was terminated at 6:35 p.m.
The licensee notified the NRC Operations Center of this event via the ENS at about 6:30 p.m.
on November 14, 1989.
The inspectors reviewed the licensee's written summary of this event dated November 15, 1989.
That summary contained an accurate description of the licensee's response and was prepared in a timely manner.
No violations or deviations were identified.
8.
Plant Status Meetinas (30702)
NRC management met with CEI management on October 26, 1989, at the Region III Headquarters in Glen Ellyn, Illinois.
Those attending the meeting are deno N by a (#) in paragraph I of this report.
The purpose of that meeting was to discuss the operating performance of the plant, recent events, Quality Assurance Department reorganization, Refueling Outage Audit, and licensee progress on responding to items identified by the Diagnostic Evaluation Team.
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Region III management acknowledged the licensee's current plant status and progress made on recent events.
9.
Violations 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's initiatives for self-identification and correction of problems, the NRC will not generally issue a Notice of Violation for a violation that meets the tests of 10 CFR 2, Appendix C, Section V.A.
These tests are:
(1) the violation was identified by the licensee; (2) the violation would be categorized as Severity Level IV or V; (3) the violation was reported to
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I the NRC, if required; (4) the violation will be corrected, including measures to prevent recurrence, within a reasontble time period; and (5) it was not a violation that could reasonably be expected to hLve been prevented by the licensee's corrective action for a previous violation.
Violations of regulatory requirements identified during the inspection for which a Notice of Violation will not be issued are discussed in paragraph 3.g.
10.
Exit Interviews (30703)
The inspectors met with the licensee representatives denoted in paragraph 1 throughout the inspection period and on November 21, 1989.
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.
The following exit interviews by RIII specialist inspectors were attended during the report period.
Inspector Exit Date J. House November 3, 1989 i
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