IR 05000440/1987016

Insp Rept 50-440/87-16 on 870813-1019.Violation Noted.Major Areas Inspected:Esfs,Operational Safety,Nonroutine Events, Lers,Startup Testing,Nrc Regional Ofc Requests,Surveillance Testing & Maint Activities

ML20237F150
Person / Time
Site:	Perry
Issue date:	12/09/1987
From:	Knop R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20237F133	List: IR 05000440/1987016 ML20237F131 ML20237F144
References
50-440-87-16, IEIN-87-004, IEIN-87-012, IEIN-87-12, IEIN-87-4, NUDOCS 8712290395
Download: ML20237F150 (21)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION III

Report No. 50-440/87016(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, Oh Inspection Conducted: August 13 through October 19, 1987 Inspectors: K.'A. Connaughton G. F. O'Dwyer S. D. Eick Approved By: R. C n p, O- 7~W Reactor Projects Section IB Date

. Inspection Summary Inspection in August 13, 1987 through October 19,'1987 (Report N /87016(DRP)) -

Areas Inspected: Routine unannounced inspection by resident inspectors of previous inspection items,- engineered safety features, operational safety, nonroutine events, Licensee Event Reports,'startup testing, NRC' Regional Office requests, surveillance testing, maintenance activities, onsite review committee activities, seismic monitoring instrumentation, scram discharge volume capability, and allegation Results: Of the 13 areas inspected, no violations or deviations were

, identified in 11' areas; two violations were identified in one area: (failure to provide required instructions for sequencing MSIV rework activities -

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Paragraph Sa; failure to provide adequate instructions for periodic feedwater pump turbine stop valve testing - Paragraph 5b). Additionally, three violations were identified in the remaining area; however, in accordance with

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10 CFR 2, Appendix C, Section V.A, a Notice of Violation was not issued (failure to maintain secondary containment integrity during an activity with potential for draining the reactor vessel - Paragtaph 6; two failures'to perform technical specification-required surveillance tests - Paragraph 6).

On October 15, 1987 a meeting between NRC Region III and licensee management

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l . "s was conducted to review plant status and licensee perfor. nan::a, At the close of the inspection period the licensee had completed Test Condition 6 startup testing and was preparing to perform the 100-hour warranty run. The warranty run was satisfactorily completed on October 24, 198 q t

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% i DETAILS I Persons Contacted M. R. Edelman, Vice President, Nuclear Group

1. A. Kaplan, Vice President, Nuclear Operations Division

1. C. M. Shuster, Manager, Nuclear Engineering Department (NED)

• B. D. Walrath, General Supervising Engineer, (NED)

1. • M. D. Lyster, Manager, Perry Plant Operations Department (PPOD)

1. D. J. Takas, General Supervisor, Maintenance Section (PP00)

1. • R. A. Stratman, General Supervising Engineer, Operations Section, (PP0D)

• G. R. Anderson, Unit Lead Engineer (PP0D)

• D. A. Graneto, Maintenance Supervisor (PP00)

1. • F. R. Stead, Manager, Perry Plant Technical Department (PPTD)

1. W. R. Kanda, General Supervising Engi2eer, Technical Section (PPTD)

L. L. Vanderhorst, Radiation Protection Section (PPTD)

1. • E. M. Buzzelli, General Supervising Engineer, Licensing and Compliance Section (PPTD)

• B. S. Ferrell, Operations Engineer, (PPTD)

1. • G. A. Dunn, Compliance Engineer, (PPTD)

1. • S. J. Wojton, General Supervising Engineer (PPTD)

1. • R. A. Newkirk, General Supervising Engineer (PPTD)

• V. J. Concel, Mechanical Unit Lead (PPTD)

1. • E. Riley, Manager, Nuclear Quality Assurance Department (NQAD)

1. • V. K. Higaki, General Supervising Engineer (NQAD)

1. • W. E. Coleman, General Supervising Engineer (NQAD)

• Denotes those attending the exit meeting held on October 19, 198 # Denotes those attending the October 15, 1987, management meetin . Licensee Action on Previous Inspection Findings (92701) (Closed) Unresolved Item (440/86020-03(DRS)): Normal and abnormal operational modes of Off-Gas System should be evaluated for a charcogiadsorberbedignitiontemperaturepossiblyaslowas150 C (307.4 F). The inspector reviewed the FSAR, the System Description Instruction Manual, the appropriate (VLI-64), and P& ids, the the System Operating Valve Lineup (501-N64), Revision Instruction 3, for the Off-Gas System. Normaloperatfonmaintainsprocessflow entering the adsorbers at approximately 0 F. Only one operational mode allows warmer air into the charcoal adsorber beds; the Charcoal Vault Defrost mod Inresponsetothetheinspegtor'sconcern,the licensee reduced the admission temperature to 200 F in step 7.4.15.e. of S01-N64, Revision 3. The inspector interviewed the responsible system engineer (RSE) tn assure that proper consideration would be made of the ignition temperature if anyone in the future requested an increase in the admission temperature. The RSE indicated that he and personnel in the Nuclear Engineering Department (that would consider such a request) were cognizant of

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the concern and that the actual ignition temperature tests of the t currently installed charcoal were in the off gas system files which 0 would be transferred to anyone who might become the offgas system RSE in the future. The inspector has no further concerns regarding

- this matte (Closed) Open item (440/86020-05(DRS)): GEN-M-21 generated instructions for augmented quality system testing did not get Test l Procedure Review Committee (TPRC) review before implementation. The f inspector reviewed a memorandum dated December 17, 1986 from the l

t Records Clerk of the Nuclear Test Section (NTS) to the Lead Test

{ Engineer of NTS which documented that Generic Procedure GEN-M-021 had been cancelled and requested the return of all controlled copies to NTS Records. The Records Clerk informed the inspector that all controlled copies were returned. The inspector also reviewed all of the other Work Orders (W0s), as listed below, that used GEN-M-021 to

, write work instructions and found them adequate:

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i 850013273 850011684 850011615 850011529 850011526 850011690 850011689 850011607 850011531 850011530 850011534 850011527 The inspector has no further concerns regarding this matte . Engineered Safety Feature (ESF) Walkdown (71710)

During this inspection period, the inspector performed a detailed walkdown of train "A" and common components of the Control Room Emergency Recirculation M25/26 Syste The system walkdown was conducted using Valve Lineup Instruction (VLI)-M25/26, Revision 4. Prior to conducting the walkdown, the inspector verified VLI-M25/26 against controlled Piping and Instrumentation Diagrams (P& ids) for the system. No significant discrepancies were identified as a result of this verificatio During the system walkdown, the inspector directly observed equipment conditions to verify that hangers and supports were made up properly; appropriate levels of cleanliness were being maintained; piping insulation, heaters, and air circulation systems were installed and operational; valves in the system were installed in accordance with applicable P& ids and did not exhibit gross packing leakage, bent stems, missing handwheels, or improper labeling; and, that major system components were properly labeled and exhibited no leakage. The inspector verified that instrumentation associated with the system was properly installed, functioning, and that significant process parameter values were consistent with normal expected values. By direct visual observation or observation of remote position indication, the inspector

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verified that dampers and vanes in the system flow path were in the

. correct positions as required by VLI-M25/26; that where required, power was available to the dampers; valves required to be locked in posisiton were locked; and, that pipe caps and blank flanges were installed as require No violations or deviations were identifie . Operational Safety Verification (71707, 71709, 71881)

The inspectors observed 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 tag-out records and verified tracking of Limiting Conditions for Operation associated with affected component Tours of the intermediate, auxiliary, reactor, and turbine buildings were conducted to observe plant equipment 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 accordance with the station security pla The inspector observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection control These reviews and observations were conducted to verify that facility l operations were in conformance with the requirements established under technical specifications, 10 CFR, and administrative procedure No violations or deviations were identifie . Onsite Followup of Non-Routine Events at Operating Power Reactors (93702) Feedwater Transient and Reactor Scram on September 9, 1987 At approximately 8:33 P.M., on September 9, 1987, the reactor scrammed from 60% power due to high reactor vessel water level.(high .!

level 8 - 219 inches above the top of the active fuel) following a '

feedwater transient. At the time of the event, the "A" and "B" reactor feedwater pumps were in service and being controlled by the master level controller. The feedwater transient was initiated when operators attempted to perform for the first time, a test of the "A" reactor feedwater pump turbine low pressure stop valve. The test involved stroking the valve partially closed and then open. In the future the test was to be performed on a weekly basis to prevent the buildup of foreign material on the valve stem which could inhibit the ability of the valve to provide feed pump turbine overspeed protectio . - - _ _ _ _ _ _ _ _ _ _-

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Immediately after the valve began to stroke, feedwater demand signals to both reactor.feedwater pumps increased to' maximum, I causing both pumps to provide maximum flow. Within approximately

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10 seconds, reactor vessel water level reached the high level 8 setpoint; scramming the reactor, tripping the main and feedwater pump turbines, and engaging an autostart inhibit interlock in the motor driven _feedwater pump control logi In the following 21 seconds, reactor water level decreased to the low level 2 setpoint (129.8 inches above the top of the active fuel) causing the high pressure core spray (HPCS) and the reactor core isolation cooling (RCIC) systems to autostart and provide water to the reactor vesse The minimum water level achieved was 129 inches above the top of the active fuel. Water level was restored by HPCS, RCIC, and the motor-driven feedwater pump to the high level 8 setpoin Approximately 3 minutes after HPCS and RCIC initiation. Operators reset the motor-driven feedwater pump trip logic and began using the motor-driven feedwater pump for reactor vessel water level control on th startup level controlle The HPCS and RCIC systems were restored to standby readines The licensee declared an Unusual Event at 8:36 P.M. due to the HPCS initiation and injection into the reactor vessel. The licensee secured from the unusual event at 9:12 P.M. following completion of followup notifications required by the licensee's emergency pla The foregoing event description was developed by the. inspector during initial onsite followup activities which began approximately one-half' hour following the reactor scram. Subsequently, the inspector verified the above chronology by review of the licensee's Post-Scram Restart Report, dated September 10, 1987. In the report, the licensee noted that the "A" emergency service water pump was manually started'by operators to support RCIC system operatio Investigation by the licensee disclosed that the autostart logic for the "A" emergency service water pump required that an RCIC system initiation signal be present for '20 seconds or greater. During the '

event, reactor water level did not remain below the level 2 RCIC initiation setpoint for a long enough period of time to cause the

"A" emergency service water pump to automatically start. To address this matter, the licensee initiated a design change to revise the emergency service water pump start logic to seal in the initiation signal. In the interim, operating procedures prescribed appropriate operator actions for manually initiating the emergency service water pum The inspector reviewed the test instruction in use at the time of the event (Periodic Test Instruction N27-P0001, " Reactor Feedpump Turbine Stop Valve Test," Revision 1, dated April 24,1987). The inspector determined from this review that the periodic test instruction was inadequate in that it failed to require placing the feedwater pump turbine under test in manual control. With the feedwater pump in manual control, stroking of the associated low pressure stop valve would not have resulted in the feedwater l

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transient which initiated this even Stroking of the low pressure stop valve with the associated feedwater pump being. controlled by

- the master level controller resulted in a feedwater pump trip input signal to the master level controller and a boosted. feedwater pump

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demand signal to both operating feedwater pump Failure to provide adequate instructions for the performance of the periodic test resulted in this event and is considered a violation of 10 CFR 50,. Appendix B, Criterion V, and the PNPP Quality Assurance Plan, Section 5 (440/87016-01(DRP)). Decoupling of Main Steam Line Isolation Valve from Actuator and Excessive Main Steam Line Isolation Valve Leakage At 2:12 P.M., on September 22, 1987, while operating at 81% power, l the licensee performed partial stroke testing of the inboard main steam isolation v'alve (MSIV) 1821-F0228 and outboard MSIV IB21-F0028B (both on the B main steam line). Valve position indication, indicated that each valve returned to the full open position at the conclusion of each stroke test. Several minutes after the test, operators noted that reactor pressure had increased from approximately 988 psig to approximately 1015 psig and that steam flow in the B main steam line had decreased to Operators reduced reactor power to 75% and, following a determination that the disk of inboard MSIV 1821-F0022B had decoupled from the actuator and traveled to the closed position during its stroke test, cutboard MSIV 1821-F00288 was secured in the closed position in accordance with technical specification 3.6.4. At 5:25 P.M. the licensee commenced an orderly reacto.'

shutdown to investigate and correct the cause of the valve / actuator decouplin Licensee investigation following the reactor shutdown disclosed that a locknut which secured the threaded valve stem to the threaded actuator coupling had become sufficiently loose to allow the valve stem to rotate out of the coupling. Based upon this finding, the licensee recoupled the MSIV and actuator and secured the locknut properly. Additionally, the licensee inspected the remaining MSIVs, verified / secured the stem coupling locknuts, and independently verified that the locknuts were, in fact, secured. Disassembly and inspection of MSIV IB21-F0228, and the valve internals were found to be intac Following the forgoing corrective actions the licensee performed a local leak rate test of the B main steam line on September 29, 1987, with unacceptable results. The licensee determined that the failed i local leak rate test was due to excessive leakage from outboard MSIV

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1821-F0288. MSIV 1821-F0288 was disassembled and blue-checks of the valve seating surfaces was performed. These examinations disclosed a lack of contact between the valve poppet and seat over certain areas of the valve seating surface. Further evaluations determined

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that the lack of contact was due to irregularities in the valve seating surface. The licensee performed an investigation to determine the root cause of the valve seating surface irregularities and to review maintenance work histories for all MSIVs to establish

, whether or not other MSIVs were subject to the same proble In July and August of 1987, the licensee performed rework on six of the eight MSIVs due to local leak rate test failures, including MSIV 1B21-F028B. A review of rework documentation for the MSIVs disclosed that MSIV 1821-F028B was subject to a unique series of

events which ultimately lead to the existence of the valve seating i surface irregularities and resultant excessive leakage. During the MSIV rework activities, the lapping tool initially utilized to lap outboard MSIV 1821-F028B experienced a bearing failure which ,

resulted in lapping of the 1B21-F028B valve seat on a different plane than originally established. The lapping tool had earlier been used on valve 1821-F028C to perform only minor lapping with no evidence of substandard tool performance. The tool was subsequently used on valve 1821-F028A, however, its use was discontinued when it became obvious that the tool was malfunctionin The licensee procured the services of Power Cutting Incorporated (PCI) to machine the valve seats on MSIVs 1821-F028A and 1821-F0288.

l- Valve 1821-F028C was reworked, utilizing a properly functioning lapping tool similar to that which had experienced a bearing failure. The same tool was utilized to perform a final lapping and blue check examination of valve IB21-F028A following grinding by PCI. Valve 1821-F028B did not receive a final lapping following the grinding by PC The inspector reviewed Work Order No.87-733 which authorized and

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directed the rework activity on valve 1821-F028B. As written, the associated job traveller (step-by-step instruction) did not acknowledge that the rework was to include grinding of the valve seat by PCI, nor did it specify where in the work sequence the grinding operation was to be performed. The job traveller did specify, however, that prior to reassembly the valve seat was to.be final lapped utilizing the lapping tool originally specified and that this final lapping procedure was to include the application of a blue dye over the entire valve seating surface. Removal of the <

blue dye from the entire seating surface during the final lapping operation was to provide assurance of valve seating surface regularit Since this final lapping operation was not performed on valve 1821-F0288, seating surface irregularities which later resulted in excessive leakage went undetecte The inspector reviewed Plant Administrative Procedure (PAP)-905,

" Work Order Process," to determine if Work Order No.87-733 had been prepared in accordance with the subject PAP. PAP-905, step 6.2. required that the job traveller specify those instances when an interface with other organizations or suppliers is necessary and how that interface is accomplished. Contrary to this requirement, the

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job traveller associated with Work Order 87-733 did not specify that interface with Power Cutting Incorporated was required nor did it specify how the interface was to be accomplished. The job traveller did not, therefore, sequence work activities such that final lapping of the 1821-F028B valve seat was to be performed following grinding of the valve seat by PCI and prior to reassembly of the valve (as originally specified). This rendered the job traveller inadequate for ensuring the detection and correction of valve seating surface irregularities which remained following the PCI grinding operatio Failure to provide an adequate instruction for the sequencing of MSIV rework activities is contrary to PAP-905, Section 5 of the PNPP Quality Assurance Plan and 10 CFR 50, Appendix B, Criterion V and is a violation (440/87016-02)(DRP).

6. Licensee Event Reports Followup (92700)

Through direct observations, discussions with licensee personnel, and review of records, the following event reports were reviewed to determine that deportability requirements were fulfilled, immediate corrective action was accomplished, and corrective action to prevent recurrence had been accomplished in accordance with technical specification LER 86040-1L Misunderstanding of Technical Specification Results in Missed Action and MSL Isolation LER 86076-LL Personnel Error Results in Loss of Secondary Containment Integrity LER 86076-IL Personnel Error Results in Loss of Secondary Containment Integrity LER 86088-LL Equipment Testability Deficiency Results in RHR Shutdown Cooling Isolation LER 87006-LL Leak Detection Design Problem Results in RCIC Isolation and Inoperable RCIC System LER 87016-LL Equipment Testability Deficiency Results in Partial Balance of Plant Isolation LER 87021-LL Reactor Vessel Level Fluctuation Due to SRV Blowdown Causes RPS Actuation LER 87022-LL Design Change Deficiencies Result in Diesel Generator Ventilation System Autostarts j LER 87023-LL RPS Manual Actuation Due to Loss of Reactor Coolant Inventory LER 87024-LL IRM Electrical Noise Spikes Result in RPS Actuation I

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LER 87025-LL Loose Ground Connection Results in RHR Shutdown Cooling

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LER 87026-LL RWCU High Differential Flow Isolation Due to Flow

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Indication Inaccuracy LER 87027-LL Loss of Main Condenser Vacuum Results in Manual Reactor Shutdown LER 87027-1L Loss of Main Condenser Vacuum Results in Manual Reactor Shutdown LER 87028-LL Design Review Oversight Results in Potential for Loss of a Single Loop of RHR LER 87030-LL Malfunction of Flow Control Valve Results in Loss of Feedwater and Manual Reactor Scram LER 87031-LL Failure to Test LOCA Relay Contacts Results in Technical Specification Violation LER 87032-LL Momentary Division 1 Leak Detection Power Loss Results in RWCU Isolation LER 87036-LL Rod Pattern Controller Surveillance Missed During Reactor Startup Results in Technical Specification Violation LER 87037-LL Failure of Motor Driven Feedwater Pump Controller Results in Reactor Scram LER 87039-LL Unexpected Isolation on a Main Steam Drain Line Inboard Isolation Valve (B21-F016) Due to NSSSS Isolation Signal LER 870402LL Leak Detection Design Problem Results in Inoperable Reactor Core Isolation Cooling System LER 87041-LL Plant Operator Unintentionally Depressed a Radiation Monitor Trip-Test Button Resulting in the Backup Hydrogen Purge System Isolating LER 86040-1L provided supplemental information concerning events originally documented in LER 86040-LL. Inspector review and closecut of LER 86040-LL was previously documented in NRC Inspection Report 440/86025. The supplemental information included a description of the steamline differential pressure transmitter failure mechanism and an update on the status of corrective actions to preve't future similar occurrences involving any instrument channels rec deed by plant technical specifications. At the time of this LER submitta: licensee had completed the development of an Instrument Failure Response Manual to assist operators in determining what actions'are required to be take upon discovery of an inoperable instrument channel in order to comply with technical specification _ - _ _ _ - _ _ _ _ _ _ _ _ _

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LERs 8607.6-LL and 86076-1L both documented an event involving a loss of secondary containment integrity while the facility was in cold shutdown and maintenance was.being performed on a control rod drive mechanism

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(CRDM). A portion of the CRDM maintenance activity, approximately twenty minutes in duration, was considered to be an activity with potential for

' draining the reactor vessel. The event occurred due to miscommunication between operations and security personnel concerning secondary containment access control requirements during the CRDM maintenance-activity. Upon discovery, secondary containment integrity was restore Corrective actions to prevent recurrence included detailed training of operations and security personnel concerning plant conditions requiring secondary containment integrity and revision of administrative procedures to require that security personnel obtain written authorization from operations personnel prior to posting open any secondary containment access portal. Failure to maintain secondary containment integrity during the performance of activities with the potentici for draining the reactor vessel-is a violation of Perry, Unit 1 Technical Specification 3.6.6.1(440/87016-03(DRP)). This violation meets the tests of 10 CFR 2, Appendix.C,Section V.A; consequently, no Nutice of Violation will be issued, and this matter is condidered close LER 87031 documented a failure to test certain relay contacts associate with the Division 3 diesel generator air compressor electrical isolation logic'due to an omission in the applicable surveillance test instructio The instruction deficiency was identified during a detailed review to verify that all technical specification-required logic system functional

. testing within the scope of the instruction was adequately performe This review was a part of the last phase of a verification program for all surveillance test instructions utilized to perform this type of testing. Upon discovery, actions were immediately initiated to perform the required testing. Testing was satisfactorily accomplished within approximately six hours of discovery and the instruction was revised to prevent recurrenc Failure to perform the above described testing is contrary to Perry, Unit 1 Technical Specification 4.3.3.2 and is a violation (440/87016-04(DRP)). This violation meets.the tests of 10 CFR 2, Appendix C, Section V.A; consequently, no Notice of Violation will be issued, and this matter is considered close LER 87036.resulted from a failure to verify operability of the rod pattern control system sequence constraints following withdrawl of the first control rod or gang during a reactor startup on May 25, 1987 due to personnel. The error was discovered after withdrawl of 12 control rods j and the surveillance was immediately performed with satisfactory result The rod pattern control system sequence constraints and procedural controls were in effect and adhered to during the control rod-withdrawal The cperator involved was given remedial training on the need for detailed procedural adherence. Failure to verify operability of the rod pattern control system following the withdrawl of the first control rod is contrary to Perry, Unit 1 Technical Specification 4.1.4.2 and is a

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violation (440/87016-05(DRP)). 'This violation meets the tests of

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10 CFR 2, Appendix C, Section V.A; consequently, no Notice of Violation will be issued, and this matter is considered close ;

7. Startup Test Witnessing and Observation (72302)

On September 8, 1987, the inspector witnessed various portions of Startup Test Instruction (STI)-C91-013, Revision 3, " Process Computer," section 8.7, " Dynamic System Test Case (DSTC) - Plant Sensor Checks." On October 18, 1987 the inspector witnessed various portions of Startup Test Instruction (STI)-B33-30A, Revision 2, "One Recirculation Pump Trip and Restart," section Th'e inspector verified for each test activity that: appropriate revisions was in use by the test crew members; the test crews of the test procedures'were adequately staffed and knowledgeable; all test prerequisites and initial conditions for each test section were signed-off in the procedures; permanent plant equipment was used to record test data; test crew actions were correct and timely during test performance, and; coordination and communications were sufficien All data was collected for final analysis by licensee test personne Limiting Conditions of Operation (LCOs) required by Technical Specifications (TS) were met. The inspector concurred with the licensee's preliminary evaluations of test results. The inspector observed that levei 1 acceptance criteria for each test had been me From the inspector's analysis of the preliminary, non-definitive "Real Time" plots it appeared that all of the level 2 Acceptance Criteria had also been satisfied. Final determination will be made in the future when more accurate historical plots are developed from computer archived dat No violations or deviations were identifie . Followup on Regional Requests (92701) Safety Relief Valves Since Fall of 1986, the licensee had routinely experienced suppression pool temperature and water level increases due to Safety Relief Valve (SRV) leakage. At the time of this inspection, 18 of 19 SRVs were weeping based on SRV tailpipe temperature readings of about 250 F with the nineteenth SRV tailpipe at 175 F. The Residual Heat Removal (RHR) system in the suppression pool cooling mode and the Suppression Pool Cleanup System (SPCU)

were being used to control suppression pool water temperature and level with RHR suppression pool cooling mode used almost exclusivel Inspector concerns resulting from this matter included the amount of operating time the RHR "A" and "B" pumps were experiencing, the attention and extra duties required of the operators to maintain suppression pool temperature and level, and the possibility of further. degradation of the SRVs (i.e. more leakage). The inspector

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reviewed'the licensee's evaluation of the SRV leakage and alternative actions to address these concerns (e.g. SRV repair /

replacement and/or alternative non-ECCS system (s) to accomplish suppression pool cooling).

It was during preoperational, hot functional testing _that the licensee first noted that installed SRVs (manufactured by Dikkers)

were leaking. With this knowledge, the licensee sent 19 spare (Unit 2) SRVs to General Electric (G.E.) San Jose for inspection /

reconditioning in preparation for a full change out of the SRVs when testing was completed. G.E. examined the spare SRVs with no major hardware anomalies noted and sent the valves back to Perr All 19 SRVs were subsequently replaced and the original leaking SRVs were sent to G.E. for the. same type of inspection. Only one valve was concluded to be' damaged (bent stem) and that SRV was sent to Wyle Labs for repair. At the time of this inspection the remainder of the originally installed SRVs were being reconditioned and will be sent back to Perry for use as spare When the licensee experienced SRV leakage in the Fall of 1986, a letter from G.E., dated October 29, 1986, stated that from a technical point'of view, leakage of SP.Vs at operating BWRs was not uncommon and G.E. attributed the leakage to foreign material in the seat area, not seat damage. G.E. also stated that an increase in the leakage rate was not expected not was there any significant potential for valve seat damage due to this leakage. The inspector's review of the Dikkers valve manuals revealed the same conclusion Efforts to determine the SRV contribution to the observed suppression pool inventory increases included heat input calculations done on a daily basis. Also, the licensee was trending suppression pool temperature, suppression pool level, and average in leakage data in graphical form,. Since September 4, 1987, inleakage has ranged from 2.6 GPM to 17.3 GPM. These values were based on the assumption that all suppression pool inventory changes were due to SRV leakage. Over that same time period, the percentage of time spent in suppression pool cooling on a day to day basis ranged from 4.2% to 60.4% with the overall average being 32%. This usage of RHR for suppression pool cooling appeared to be excessive and inappropriate for long term us The licensee evaluated all other ingressing lines to the suppression pool as possible contributors to the suppression pool inventory changes and checked for leaking valves. The licensee did not identify another source of water to the suppression pool. The trended data did not indicate other possible contributors to the pool changes such as start-up testin To further address this matter, the licensee intended to:

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< (1) Replace all 19 SRV's with inspected / reconditioned spare .(2) Possibly, concurrent with SRV changeout, implement a design  !

change that would eliminate placing RHR in suppression pool  !

cooling mode; therefore, reducing the operating time of RH An auxiliary system to replace RHR suppression pool cooling is currently the subject of an Engineering Design Change Request (EDCR)

No. 87-0633. The proposed design change would add a heat exchanger to the SPCU system and a separate return path to the suppression pool using a spare containment penetration. The EDCR was w # rgoing engineering review, and no other details concerning the exact design configuration were yet availabl Further evaluation is needed in order to determine the long term safety and operational significance of the Dikkers SRV leakag This matter is considered an open item (440/87016-06(DRP)). Review of Potential For Inadvertent Draining of tr Containment Upper Pools Based upon a review of an occurrence at the River Bend nuclear pow 2r facility involving an inadvertent reduction in containment upper pool water level it was determined that a potential existed for reducing water level to the extent that fuel stored in the upper pool could be partially uncovered. The inspector was requested to review facility design features and operating procedures to determine whether or not a similar potential existed at Perr The inspector reviewed controlled piping and instrumentation diagrams for the Fuel Pool Cleanup system, associated Valve Lineup Instructions, System Operating Instructions, and Perry FSAR section 9.1.2.2.1.. Based upon this review, the inspector determined that differences in facility design and operating procedures precluded the type of event postulated for the River Bend facility. The lowest elevation for fuel pool cleanup system piping which could affect upper pool water level was 2'3" above the top of fuel assemblies stored in the upper pool fuel storage racks. This piping was provided with syphon breakers consisting of 1" lines which terminated a few inches below the normal upper pool water leve There were no anticipated evolutions which would have required disabling of the syphon breakers. According to licensee personnel, upper pool draining operations including those involving the fuel storage area, would be accomplished with a temporary procedure, perhaps requiring the use of a portable submersible pump. 1he inspector has no further concerns regarding this matte IE Information Notice (IEN) Followup '

(1) (Closed) IEN 87-04, " Diesel Generator Fails Test Because of Degraded Fuel." The inspector reviewed the licensee's response file for the subject IEN and determined that system operating

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instructions for the Perry diesel generators required that prior to the addition of new fuel to the fuel oil storage tanks, licensee chemistry personnel were required to add a biocide to inhibit bacteriological growth. Additionally, the

. inspector determined that periodic inspection and cleaning of the diesel fuel oil strainers was specified and accomplished as a part of routine diesel generator surveillance test procedures. Differential pressure instrumentation and alarms were provided to alert operators that the strainers had become ,

fouled. Under those circumstances, the operator could place redundant strainers in service and remove the fouled strainer from service in order to accomplish inspection'and cleaning activitie Based upon the forgoing, the inspector has no further concerns regarding this matte (2) (Closed) IEN 87-12, " Reliability of Non-Safety Related Breaker During an ATWS." The inspector reviewed the licensee's response file, Perry FSAR section 7.2.2.3, and Supplement 4 of the Perry Safety Evaluation Report (NUREG 0887). Based upon this review, the inspector determined that the Perry design did not utilize the Low Frequency Motor-Generator (LFMG) field breaker to accomplish the ATWS recirculation pump trip (RPT)

function. Instead, the trip function is accomplished by tripping three 13.8 kV recirculation pump fast speed supply breakers arranged in series and tripping the LFMG supply and output breakers. The licensee determined, however, that the breaker failure mechanisms described in the subject IEN, which involved General Electric AKF-2-25 type breakers, were applicable to all General Electric AKF series breakers. As a result, the licensee adopted the recommendations of General Electric for periodocially cycling the LFMG field breakers as well as breaker disassembly, cleaning, and relubricatio These items'were scheduled to be fully implemented by the end of January 1988. Based upon the forgoing, the inspector has no further concerns regarding this matte No violations or deviations were identifie . Monthly Surveillance (SVI) Observation (61726)

The inspector observed various portions of the following technical specification-required surveillance tests:

SVI Description C51-T0028-D APRM Flow Biased Signal Channel D Calibration for 1 C51-K605D C51-T0027-D APRM D Trips Channel Functional C11-T5376-A SDV Water Float Switch Level High Channel A Functional / Calibration for IC11-N013A i

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For each test activity the inspector verified that testing was performed in accordance with procedures, that test instrumentation was calibrated, i that limiting conditions for operation were met, that removal and J l restoration of the affected components were accomplished, that test results conformed with technical specifications and procedure requirements and were reviewed by personnel other than the individuals directing the test, and that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personne No violations or deviations were identifie . Monthly Maintenance Observation (62703)

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Station maintenance activities of safety related systems and components listed below were observed / reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides and industry codes or standards and in conformance with technical specification Work Order Description 87-7481 Troubleshooting and Repairing Intermediate Range Neutron Monitoring IRM "A" Drive (IC51-S001E)

86-15029 Reinstallation of the Fuel Handling Building Ventilation Exhaust Fan shaft 87-8669 Replacement of all three main line fuses for the motor on valve B21-F065A, "Feedwater Header Isolation Valve" 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; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and, fire provention controls were implemente No violations or deviations were identifie . Onsite Review Committee (40700)

The inspectors reviewed the minutes of the Plant Operations Review Committee (PORC) meetings No.87-163, 87-187,87-188, 87-190 through 87-201, and 87-203 through 87-217, conducted prior to and during the inspection period to verify conformance with PNPP procedures and regulatory requirements. These observations and examinations included PORC membership, quorum at PORC meetings, and PORC activitie No violations or deviations were identifie ._______ _ _-

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12. Periodic Inspection and Testing'of Seismic Monitoring Instrumentation (61726,62703)

During this inspection period, the inspector reviewed' licensee activities

. pertaining to seismic monitoring instrumentation preventive maintenance, surveillance testing and operability. The inspector reviewed applicable sections of the Perry . Technical Specifications-(TS) and Vendor manuals to become familiar with seismic monitoring instrumentation, maintenance, surveillance test, and operability requirements. The inspector reviewed the following Surveillance Test Instructions (SVIs) which implemented these requirements:

SVI N Title D51-T0278 Triaxial time-history accelerographs channel functional for D51-N101 and D51-N111 D51-T0279 Triaxial time-history accelerograph channel calibration for D51-N101 and D51-N111 D51-T0289-A Triaxial peak accelerographs channel calibration for D51-R120 (Reactor Recirculation Pump)

D51-T0289-B Triaxial peak accelerographs channel calibration for D51-R130 (HPCS Piping in Reactor Building)

D51-T0289-C Triaxial peak accelerographs channel calibration for D51-R140 (HPCS Pump Base Mat)

051-T0294 Triaxial seismic switch channel functional test for D51-N150 051-T0295 Triaxial seismic switch channel calibration for D51-N150 051-T0302 Seismic instruments channel check D51-T0304-A Triaxial response spectrum recorder channel calibration for D51-R160 (Reactor Building Foundation)

D51-T0304-B Triaxial response spectrum recorder channel calibration for D51-R170 (Reactor Recirculation Piping Support)

D51-T0304-C Triaxial response spectrum recorder channel calibration for D51-R180 (HPCS Pump Base Mat)

D51-T0304-D Triaxial response spectrum recorder channel calibration for D51-R190 (RCIC Pump Base Mat)

051-T5369 Triaxial time-history accelerographs seismic trigger channel functional test for D51-N100 and D51-N110 l

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051-T5370 Triaxial time-history accelerographs seismic trigger channel calibration for D51-N100 and D51-N110

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By reviewing the latest test results packages for each surveillance listed and the last five test results packages for SVI-D51-T302, the inspector determined that all test results documentation was maintained in accordance with the licensee's administrative program. By reviewing the Data Package Cover (DPC) Sheets for the last two surveillance for each surveillance listed and the last six DPC sheets for SVI-D51-T302 and the licensee's computerized surveillance schedule printout, the inspector found all the surveillance to have been performed in compliance with the frequency requirements of Technical Specification Based upon discussions with licensee technical personnel, the inspector determined that seismic monitoring instrumentation has been maintained in an operable status since issuance of the Perry, Unit 1 operating licensee on March 28, 1986, except for brief periods when surveillance testing was being performed. The inspector will continue to review seismic monitoring instrumentation surveillance test results during future inspection No violations or deviations were identifie . Allegation Followup (99014)

(0 pen) Allegation RlII-87-A-0112: Duct tape was used to repair a heater bay valve. The inspector determined that the heater bay building i contains no safety related valves. Based upon this fact and the lack of specificity within the allegation, no further inspector followup action was performed. The inspector noted, however, that on May 1, 1987 following a failure of hot surge tank level control valve IN21-F0230 due to ruptured air lines, operators unsuccessfully attempted to regain control of the valve by wrapping the air lines with tape. The valve, which was located in the heater bay building, drifted closed resulting in low hot surge tank water level, trips of the feedwater booster pumps, trips of the main feedwater pumps, and a reactor scram due to low reactor vessel water level. While this may have been the instance referred to by the alleger, under the exigent circumstances which existed, the attempted repair was entirely appropriat This portion of the allegation is considered close One other portion remains open and will be inspected late . Inspection of Licensee's Im) lamentation of Multiplant Action Item B-58, Scram Discharge Volume Capa)ility (TI 2515/90) (25590)

During this inspection period, between September 24 and September 28, 1987, the inspector performed a review of the Perry scram discharge volume design and testing as required by NRC Office of Inspection and Enforcement Temporary Instruction (TI) 2515/90, " Inspection of Licensee's Implementation of Multi-Plant Action Item B-58 Scram Discharge Volume Capability." Specific items considered in this review and inspector determinations relative to each of the items are discussed belo The inspector reviewed a calculation performed by the architect engineer for Perry to determine whether or not the scram discharge volume was adequately sized in compliance with the specifications of General Electric which required a minimum volume of 3.37 gallons per control

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rod drive. This calculation, Calculation C11-6, Revision 1, dated October 15, 1985, determined that the scram discharge volume accommodated j 3.99 gallons per control rod drive. Based on the inspector's review, the '

inspector was satisfied concerning the adequacy of the size of the scram discharge volum !

With regard to hydraulic coupling between the scram discharge volume and scram discharge instrument volume, the inspector verified that.the scram discharge' instrument volume was directly connected to the scram discharge L

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volume at the; low point of the scram discharge header piping. This verification was made by direct visual observatio By review of the Perry FSAR, Technical Specifications, and Electrical Design Drawings for the Reactor Protection System, the inspector confirmed that an automatic scram. function existed for high scram instrument volume water level. As described in the FSAR, system configuration provided diverse and redundant level instrumentation for the scram function associated with the scram discharge volume. Each of the four RPS channels A, B, C, and D were provided trip signals from both a float type level switch and an analog level transmitter. Trip signals from either of these devices would cause the respective RPS channel to trip. The RPS channels in turn, were arranged in a one out of two taken i twice logic such that tripping of RPS channels A or C and B or D would cause a reactor scra Based upon the RPS logic arrangement and the 1 assignment of level instruments to instrument taps provided directly on the scram discharge volume, the inspector determined that the scram function would not be disabled by a single failure, including the plugging of a single instrument tap. The instrument sensing line configuration and assignment of level instruments was verified by the inspector through direct visual observation. These observations were found to be consistent with piping and instrumentation diagram D-302-871, Revision M, dated September 9, 1987. Inspector review of this drawing also determined that the scram discharge volume vent and drain functions would not be adversely affected by other system interfaces. The vent and drain functions were provided with dedicated piping. Additionally, the

' drain lines which terminate in the suppression pool were provided-with vacuum breakers to preclude siphoning of water into the scram discharge volume. Redundant failsafe air operated valves were provided for isolation of the vent and drain piping following a scram. By direct visual observation, the inspector determined that scram discharge volume vent and drain valve position indication was provided in the control room as well as an alarm to alert operators to the presence of water in the scram discharge volume instrument volume. Alarm response instruction (ARI)-H13-P680-5, prescribed immediate and subsequent operator actions following receipt of the alarm. The inspector reviewed the below listed Surveillance Instructions (SVIs) associated with the scram discharge volume level detection instrumentation and vent and drain valves. The inspector verified that collectively, the procedures satisfied technical specification test requirements for the scram discharge volume level alarm and trip functions and vent and drain valve stroke time testin The level instrumentation test procedures were verified by the inspector to include appropriate steps for system restoration including independent verification. The SVI.s reviewed were as follows:

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SVI N Title C11-T0044-A Scram Discharge Volume Water Level High Channel A Functional For IC11-N601A

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C11-T0044-B Scram Discharge Volume Water Level High Channel B Functional For IC11-N601B C11-T0044-C Scram Discharge Volume Water Level High Channel C Functional For IC11-N601C C11-T0044-D Scram Discharge Volume Water Level High Channel D Functional For IC11-N601D C11-T0045-A Scram Discharge Volume Water Level High Channel A Calibration For IC11-N012A C11-T0045-B Scram Discharge Volume Water Level High Channel B Calibration For IC11-N012B C11-T0045-C Scram Discharge Volume Water Level High Channel C Calibration for IC11-N012C C11-T0045-D Scram Discharge Volume Water Level High Channel D Calibration for IC11-N0120 C11-T0245-A Scram Discharge Volume Level Water Level High Functional For IC11-N602A C11-T0245-B Scram Discharge Volume Level Water Level High Channel B Functional For IC11-N602B C11-T0246-A Scram Discharge Volume Water Level High Channel Calibration A For IC11-N017A C11-T0246-B Scram Discharge Volume Water Level High Channel Calibration B For IC11-N017B C11-T1001 Scram Discharge Volume Valve Verification C11-T2004 Scram Discharge Volume Vent and Drain Valves Operability Test C11-15376-A Scram Discharge Volume Water Float Switch Level High Channel A Functional / Calibration For IC11-N013A C11-T5376-B Scram Discharge Volume Water Float Switch Level High Channel B Functional / Calibration For 1C11-N013B C11-T5376-C Scram Discharge Volume Water Float Switch Level High Channel C Functional / Calibration For IC11-N013C

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C11-T5376-D Scram Discharge Volume Water Float Switch Level High Channel D Functional / Calibration For IC11-N0130 16. 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. Open inspection items disclosed during the inspection are discussed in Paragraph . 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 requiremen 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 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 the NRC, if required; (4) the violation will be corrected, including measures to prevent recurrence, within a reasonable time period; and (5)

it was not a violation that could reasonably be expected to have been prevented by the licensee's corrective action for a previous violatio Violations of regulatory requirements identified during the inspection for which a Notice of Violation will not be issued are discussed in Paragraph . Plant Status Management Meeting (30702)

On October 15, 1987, NRC management met with CEI management at the Perry site to discuss the current status of the plant and recent event These meetings are being held on a periodic (initially monthly) basi The meeting included discussions of: the status of the plant; recent Licensee Event Reports (LERs); corrective actions taken or planned to be taken to preclude repetition; and, the schedule for future evaluation . Exit Interviews (30703)

The inspectors met with the licensee representatives denoted in Paragraph ,

1 throughout the inspection period and on October 19, 1987. The I 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 natur m