IR 05000440/1987023

Insp Rept 50-440/87-23 on 871020-1230.Violations Noted. Major Areas Inspected:Previous Insp Items,Ie Bulletins, 10CFR21 Repts,Regional Ofc Request,Operational Safety, Nonroutine Events,Lers,Physical Security & Maint

ML20196A643
Person / Time
Site:	Perry
Issue date:	02/02/1988
From:	Knop R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20196A624	List: IR 05000440/1987023 IR 07100020/2012030 ML20196A620
References
50-440-87-23, IEB-87-002, IEB-87-2, IEIN-87-050, IEIN-87-50, NUDOCS 8802050112
Download: ML20196A643 (18)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION III

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Report No. 50-440/87023(ORP)

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Docket No. 50-440/87023 License No. NPF-58 Licensee:

Cleveland Electric Illuminating Company Post Office Box 5000 Cleveland, OH 44101 i

Facility Name: Perry Nuclear Power Plant, Unit 1

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Inspection At: Perry Site, Perry, OH Inspection Conducted: October 20, 1987 through December 30, 1987

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Inspectors:

K. A. Connaughton G. F. O'Dwyer ih.I'N Approved By:

R.C. knop, Chief-byg h C/2/ 8[f Rector Projects Section IB Date

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Inspection Summary Inspection in October 20, 1987 through December 30, 1987 (Report No.

50-440/87023(DRP))

Areas Inspected: Routine unannounced inspection by resident inspectors of previous inspection items, IE Bulletins, 10 CFR Part 21 Reports, Regional Office Requests, operational safety, nonroutine events, Licensee Event Reports, cold weather preparations, startup testing, maintenance, surveillance testing, physical security, radiological controls, containment closeout, and

onsite review comittee meetings.

Results: Of the 15 areas inspected, one violation was identified in one area:

(RCIC system inoperable when reactor pressure increased above 150 psig -

Paragraph 6); and one violation was identified in a second area (failure to take technical specification required actions for inoperable intermediate i

range neutron monitoring instrumentation - Paragraph 8). Additionally, three t

violations were identified in the second area; however, in accordance with 10 i

CFR 2, Appendix C,Section V.A., a Notice of Violation was not issued (RCIC j

suction logic overridden wuthout declaring RCIC inoperable - Paragraph 8; failure to take required actions for diesel generator fuel oil out-of

j specification - Paragraph 8, and; failure to verify operability of offsite j

power sources within required timeframe - Paragraph 8).

During this j

inspection period, a decline in the frequency of reportable events was noted, t

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Two events in November, 1987, and two events in December, 1987 required

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submittal of Licensee Event Reports, i

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4 S002050112 900202

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PDR ADOCK 05000440

PDR l

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ep DETAILS

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Persons Contacted

1. Alvin Kaplan, Vice President, Nuclear Group C. M. Shuster, Director, Nuclear Engineering Department (NED)

B..D. Walrath, Manager, Engineering Projects Support Section (NED)

D. R. Green, Manager, Electrical Design Section (NED)

K. R. Pech, Manager Mechanical Design Section (NED)

1. • M. D. Lyster, General Manager, Perry Plant Operations Department (PP00)

R. A. Stratman, Manager, Operations Section (PP00)

1. M. Cohen, Manager, Maintenance Section (PP0D)

V. K. Higaki, Manager, Outage Planning Section (PP00)

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

S. F. Kensicki, Technical Superintendant (PPTD) (PPTD)

L. L. Vanderhorst, Radiation Protection Section

1. E.M.Buzzelli, Manager,LicensingandComplianceSection(PPTD)

R. A. Newkirk, Manager, Technical Section (PPTD)

• H. Hegrat, Licensing and Compliance Section (PPTD)

1. E.Riley, Director,NuclearQuality)AssuranceDepartment(NQAD)

T. A. Boss Quality Audit Unit (NQAD W. E. Coleman, Manager, Operations Quality Section (NQAD)

D. J. Takas, Manager, Maintenance and Modification Quality (NQAD)

• Denotes those attending the exit meeting held on December 30, 1987.

1. Denotes those attending November 19, 1987 management meeting.

2.

Licensee Action on Previous Inspection Findings (92701, 92702)

a.

(Closed)OpenItem(440/86018-03(DRP)):

Upgrade material control and accountability procedures to inventory all items containing SNM.

The inspector reviewed Plant Administrative Procedures (PAP)-0802,

"Control of Special Nuclear Material," Revision 1, dated August 11, 1986 and PAP-1302, "Nuclear Instrumentation Receipt, Handling, Storage, and Shipment," Revision 0, dated August 11, 1986. The inspector verified that PAP-802 had been revised to specif nuclear instrumentation detectors (SRMs IRMs, and LPRMs) y that contain SNM and, as such, must be controlled and accounted for. The procedure further specified the use of checklists to document the locations of these items from the time of initial receipt until the time the items are shipped offsite for disposal. Semi-annual physical inventories of SNM utilizing a centralized accounting system with double-entry bookkeeping was established for nuclear instrumentation detectors containing SNM.

DOE /NRC Fonns 741 and

742 were required to be completed for reporting of offsite

shipments and for material balance reporting, respectively. Based

upon the forgoing and consultation with NRC Region III material I

control and accountability inspection personnel, the inspector has

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no further concerns regarding this matter.

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b.

(Closed)OpenItem(440/86023-04(DRP)): Evaluation of the adequacy of plant statusing systems.

This item was identified during initial facility operation under the low power operating license (0perating License NPF-45).

The inspectors questioned whether or not the various licensee programs for tracking plant equipment status could be effectively utilized by operating personnel.

The item remained open pending inspector review of licensee experience during power ascension testing.

Inspector observations during the power ascenssion test program and subsequent commercial operation have determined that utilizing existing programs, including shift relief and turnover procedures, operating personnel were generally able to obtain and communicate comprehensive knowledge of plant system status. Having gained familiarity with the licensee's various programs, operators could readily access the various data bases to detennine the status of plant equipment on a system, train, or component level, when required. The inspector has no further concerns regarding this matter, c.

(Closed) Violation (440/87012-02(DRP)):

Failure to provide appropriate installation drawings for the installation of main steam isolation valve (MSIV) pilot solenoid power supply wiring. The t

inspector reviewed the licensee's response letter dated October 8

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1987. The response letter stated that a design change had been

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implemented to correct installation drawings and to revise the MSIY i

pilot solenoid power supply wiring to achieve conformance with the Perry FSAR and approved final design. These actions were previously verified during an inspection documented in NRC inspection report i

440/87019. The inspection included review of the revised installation drawings and field inspection of the revised MSIV pilot

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solenoid power supply wiring. The licensee's response letter also stated that a review of General Electric (GE) design drawings against Gilbert Associates Inc. (GAI) drawings had been conducted to

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determine whether similar design drawing transposition errors had

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occurred.

The results of the licensee's review were previously submitted to the NRC by letter dated June 30, 1987. The inspector i

reviewed the June 30, 1987 letter to determine whether the

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identified discrepancies between GE and GAI drawings were of

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significance. Based upon the nature of each identified discrepancy,

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the inspector agreed with the licensee's conclusion that none of the discrepancies affected wiring, power supply assignment, separation

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or system / component function. The discrepancies involved i

differences between conventions used by GE and GAI for schematic i

fonnat (e.g. drawing notes, instructions).

Based upon the forgoing,

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the inspector is satisfied that the MSIV wiring problem was satisfactorily resolved and that the drawing error which precipitated i

the problem was an isolated occurrence.

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(Closed)OpenItem(440/87012-04(DRP)): Review the events described inLicenseeEventReports(LERs) 86044, 86050, 86071, and 86072 to

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detennine what information was available to operators concerning MSIV pilot solenoid status and whether or not the MSIV miswiring

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(i.e. both pilot solenoids on each MSIV powered from a single RPS i

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• e bus) should have been recognized.

Each of these LERs described events involving the deenergization of a single RPS bus. With the MSIVs miswired, loss of a single RPS bus would have caused 4 of the 8 HSIVs to close. Additionally, both of the pilot solenoid status lights for each of the four affected MSIVs would have extinguished.

Licensee review of the events described in these LERS determined that at the time of each event, the MSIVs were already closed.

Operators would therefore not have received indication of a change in MSIV status. Since the MSIV, were known to be closed, operators had no reason to observe the,110t solenoid status lights following RPS bus deenergization.

Thr MSIY status lights were located on a back panel. Based upon the forgoing, the licensee concluded that operating personnel would not have been expected to recognize the MSIV wiring error as a result of these events. The inspector concurred with this determination. As a result of another event involving an unexpected RHR system isolation during surveillance testing, the licensee instituted corrective actions to ensure that unusual equipment actuations, such as unexpected MSIV closures, are identified. Records generated from the Emergency Response Information System were required to be obtained, if relevant, following potentially reportable events.

This administrative requirement should result in the identification of abnormal equipment behavior when it first occurrs.

3.

Inspection and Enforcement Bulletin (IEB) Followup / TI 2500/26(25026)

(0 pen) IE Bulletin 440/87002-BB:

"Fastener Testing to Determine Conformance with Applicable Material Specifications." During this inspection, the inspector participated in the selection of fastener samples to be tested in accordance with the requirements of the subject IEB.

Following the recommendation concerning sample composition, the licensee proposed to select fasteners according to material and mechanical properties based upon an estimated degree of usage within the plant.

Utilizing the proposed sampling plan, the inspector randomly selected fasteners with the specified material and mechanical properties from spare parts inventory. The inspector accompanied licensee personnel and witnessed the removal of all but 2 sample specimens from their respective warehouse locations.

The selected fasteners were sent to a local laboratory for testing in accordance with the subject IEB.

Additional inspection activity relative to IEB 87-02 will be performed following completion of fastener testing and receipt of the licensee's documented response.

4.

10 CFR Part 21 Report Followup (92701)

(0 pen) 10 CFR Part 21 Report (440/87002-PP):

General Electric HFA relays with latching mechanisms.

By letter dated November 12, 1987, General Electric reported a potential defect involving HFA auxiliary relays (models HFA151B, HFA1548, and HFA154E) with insufficient latch engagement.

Depending upon the application, improper unlatching of the relay could involve a safety hazard.

The inspector detennined through discussions with licensee personnel that the licensee had received

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General Electric Service Advice letter (SAL) Number 190.1 which described the reportable condition and specified actions to be taken to detennine if the condition affected individual relays. As of the close of this inspection, licensee review of GE SAL 190.1 was ongoing. The inspector will perform additional reviews of licensee actions relative to the subject 10 CFR 21 report during a future inspection.

5.

Inspection in Response to Regional Office Requests (92701)

a.

Ambient Temperature Monitoring During an NRC inspection at an operating reactor facility, excessive ambient temperatures were noted in areas containing safety related electrical equipment. The inspectors were requested to determine what actions, if any, the licensee has taken to monitor temperatures in such areas based upon equipment performance limitations and whether or not appropriate limits have been established.

During this inspection period, the licensee completed the startup test program and acquisition of baselira ambient temperature data.

During the startup test program, three areas of concern were identified; the drywell, the steam tunnel, and the diesel generator building. The drywell and steam tunnel temperatures were evaluated for impact on equipment environmental qualifications and technical specification changes were obtained. The diesel generator building remained under evaluation at the time of this inspection.

The inspector was informed by licensee personnel that an ongoing plant area temperature monitoring program will be developed based upon baseline data acquired during startup testing. The program will include periodic monitoring of ambient temperature conditions in all Environmental Zones identified on Plant Environmental Conditions design drawings. Discrepancies between actual ambient temperatures and those assumed in the design process will be evaluated for impact on equipment qualification and corrective actions will be initiated, where necessary, to ensure that equipment remains environmentally qualified.

Pending inspector review of the above described program, this matter remains an open item (440/87023-01(DRP)).

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IE Information Notice (IEN) 87-50, "Potential LOCA at High-And Low-q Pressure Interfaces From Fire Damage."

The subject IEN described a set of circumstances in which a loss-of-coolant accident could be introduced as a result of a postulated fire in the control room or cable spreading room.

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circumstances involved a hot short resulting in the inadvertant opening of a high pressure to low pressure system interface isolation valve, exposing the low pressure system to pressures in excess of design.

During a NRC fire protection re-review at Washington Public Power Supply System's Washington Nuclear Project Number 2 (WNP-2), the staff became aware of a bypass line around the check valve installed in the RHR system discharge line.

The bypass

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line contained a manual motor-operated isolation valve which was used for warming the RHR discharge line prior to placing the RHR system in service. Under the postulated circumstances, the spurious opening of this isolation valve could result in overpressurization of the RHR system low pressure piping. The subject IEN identified

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the Perry Nuclear Power Plant as having a similar design and recommended that the licensee review the matter to determine appropriate actions to prevent the postulated scenario (i.e.

removing power from the isolation valve motor operator during nomal plant operations).

Licensee review of IEN 87-50 disclosed that the reference to the Perry Nuclear Power Plant was in error. The~ Perry design does not include a bypass line around any of the Emergency Core Cooling System injection check valves. The-postulated scenario was, therefore, not applicable to Perry, Unit 1.

The inspector reviewed

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controlled piping and instrument diagrams for the Perry Emergency Core Cooling Systems, including RHR, and determined that the

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licensee's conclusion regarding the IEN was correct. The inspector has no further concerns regarding this matter.

6.

Operational Safety Verification (71707)

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 components.

Tours of the intermediate, auxiliary, reactor, and turbine buildings were conducted to observe plant equipment conditions including potential fire i

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 j

in accordance with the station security plan.

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The inspector observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection controls. During this

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g inspection period, the inspectors walked down the accessible portions of the High Pressure Core Spray System to verify operability.

j These reviews and observations were conducted to verify that facility l

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operations were in conformance with the requirements established under i

technical specifications, 10 CFR, and administrative procedures.

3 On November 13, 1987, during a reactor startup, operating personnel

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increased reactor pressure above 150 psig with the Reactor Core Isolation

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Cooling (RCIC) system inoperable. Earlier, with reactor pressure established at 60 psig, and in accordance with Integrated Operating

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Instruction (101)-1, "Cold Startup," Step 4.6.2, operators comenced I

warmup of the RCIC steam piping. However, contrary to this same

procedural step, the RCIC system was not placed in standby readiness at i

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that time. The operations Shift Supervisor informed the operating crew that the RCIC system need not be placed in standby readiness until sometime within the 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> following an increase in reactor pressure above 150 psig. Apparently, the Shift Supervisor had confused the technical specification requirements for RCIC system operability with reactor pressure greater than 150 psig and the requirement to demonstrate operability by surveillance testing within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of exceeding a reactor pressure of 150 psig.

Based upon inspector interviews with operations management personnel, operators questioned the Shift Supervisor as to the accuracy of his recollection of technical specification requiremer.ts. Despite this questioning and without further consultation of technical specifications, the Shift Supervisor insisted that the RCIC systen need not be operable prior to exceeding 150 psig reactor pressure. Subsequently, with reactor pressure at approximately 180 psig, while reviewing main control board indications, the Unit Supervisor observed that the RCIC system was in secured status. The Unit Supervisor and Shift Supervisor then consulted technical specifications and determined that an error had been made. Operators were instructed to reouce reactor pressure to below 150.psig and to place the RCIC system in standby readiness. Conformance with technical specification requirments was achieved approximately 45 minutes after the violation had first occurred. The violation was documented via a Condition Report for licensee followup and corrective action.

Corrective actions taken by the licensee included disciplinary action against the Shift Supervisor and formal training of all licensed operators in the sequence of events which led to the violation.

Entry into operational condition 2 with reactor pressure greater than 150 psig and with the RCIC system inoperable is contrary to Perry Unit 1 technical specification 3.7.3 and is a violation (440/87023-02(DRP)).

7.

Onsite Followup of Non-Routine Events at Operating Power Reactors (93702)

a.

October 27, 1987 Reactor Scram and Unusual Event Due to loss of Feedwater and Low Reactor Vessel Water Level On October 27, 1987, at approximately 6:37 a.m., a reactor scram

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from 51% power occurred due to a loss of feedwater and low reactor vessel water level. The loss of feedwater was initiated when 4.6 kV electrical bus L12 was deenergized for approximately 4 seconds due to a switching error by a licensed operator. Deenergization of bus L12 resulted in tripping of the hot surge tank low level reactor feedwater booster pump trip logic, tripping of the reactor feedwater booster pumps, tripping of the A and B reactor feedwater pumps, and approximately 10 seconds later a reactor scram due to low reactor water level. Reactor water level continued to decrease and approximately 12 seconds following the scram, reactor water level reached the High Pressure Core Spray (HPCS) and Reactor Core Isolation Cooling (RCIC) systems initiation setpoint. Within the following 3 minutes HPCS, RCIC, and the motor-driven feedwater pump restored reactor vessel water level to the high level 8 HPCS and RCIC trip setpoints.

The HPCS and RCIC systems were returned to

standby readiness and operators established automatic reactor water level control utilizing the motor-driven feedwater pump and startup I

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level controller. Since the HPCS and RCIC systems had auto-initiated and injected water to the reactor vessel, the

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licensee declared an Unusual Event and following followup notification required by the licensee's energency plan, the Unusual

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Event was terminated at 7:20 a.m.

The inspector was informed of the event by electronic pager while

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enroute to the site and arrived on site at approximately 7:00 a.m.

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Through initial discussions with plant opertions and supervisory

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personnel, the inspector established that the event had been i

initiated by the electrical switching error. By review of

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indications in the control room, the inspector determined that the

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plant had been stabilized in hot shutdown. Based upon subsequent interviews with licensee personnel and inspector review of the licensee's Post-Scram Restart Report 1-87-13, the inspector established the forgoing event chronology and the following discussion concerning the electrical switching error, Just prior to the scram, operators were in the process of transferring house electrical loads from the startup transformer

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to the auxiliary transformer. The operator closed the auxiliary

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transformer to bus L11 supply breaker causing the startup

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transformer to Lil supply breaker to automatically trip completing the transfer.

The operator than attempted to manipulate the control

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t switch for the startup transformer to bus L11 supply breaker so that the control switch status flag would indicate the actual breaker

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position (tripped).

The operator inadvertantly manipulated the i

startup transformer to L12 supply breaker control switch instead of

the startup transformer to L11 supply breaker control switch,

deenergizing bus L12.

Four seconds later the switching error was

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corrected by reclosing the startup transformer to bus L12 supply i

breaker.

Inspector review of the switching error disclosed that the operator

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involved was knowledgeable in the performance of the switching operation and that adequate procedures were available and in use for the activity.

Based upon these facts and the operator's record of a

performance, including actions taken following the switching error, the inspector determined that the error was non-systematic in nature and not indicative of the operator's routinely demonstrated levels of knowledge, skills, and abilities.

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No violations or deviations were identified.

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October 29 and November 3,1987 Main Steam Isolation Valve (MSIV)

Pilot Valve Failures l

Following these events, an Augmented Inspection Team (AIT) was

established by the NRC Region III office to perform an indepth

review of the events to establish detailed event descriptions and

root causes.

The Senior Resident Inspector was assigned to the AIT

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and participated in the followup inspection activities. The results of the AIT inspection are documented in NRC Inspection Report i

50-440/87024.

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November 29, 1987 Main Steam Isolation Valve (MSIV) Pilot Valve

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As a result of this event, the AIT which investigated the events

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j discussed in the preceding sub-paragraph was again dispatched to

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the site to perform an indepth investigation of this event. The

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Resident Inspector participated in this AIT inspection.

The results of this AIT inspection will documented in NRC Inspection Report 50-440/87027.

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Licensee Event Reports Followup (92700)

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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, and corrective action to prevent recurrence had been accomplished in accordance with technical specifications.

LER 87029-LL RCIC Suction Valves Logic Overridden

LER 87033-LL Inadequate Procedure Results in Both Trsins of Standby

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Liquid Control Being Inoperable During Performance of a Surveillance Instruction LER 87035-LL System Vibration Results in Failure of a Condensate Orain Line and the Subsequent Initiation of a Manual Reactor Scram LER 87038-LL Failure to Notify Control Room of Out of Specification Diesel Generator Fuel Oil Sample Results in Technical

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Specification Violation

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LER 87044-LL Transmitter Sensing Line Pressure Anomalies Result in

Reactor Core Isolation Cooling System Isolations J

LER 87045-LL Manual Scram Due to a Generator Bushing Failure and

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Resultant Increased Hydrogen Concentration in the Generator Neutral Bushing Compartment i

LER 87046-LL Placement of Air Sampler Near a Leak Detection Temperature

Sensor Results in a Reactor Water Cleanup Isolation

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LER 87047-LL Misinterpretation of Technical Specification Action Time j

Intervals Result in Technical Specification Violation J

j LER 87048-LL Procedural Deficiency During Startup Results in Open

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Containment Isolation Valves During Plant Operation j

Causing Technical Specification Violation I

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LER 87051-LL Failed Local Leak Rate Tests Result in Exceeding Allowable Primary Containment Leakage Rates for Main Steam Lines A, B and D LER 87051-1L Failed Local Leak Rate Tests Result in Exceeding Allowable Primary Containment Leakage Rates for Main Steam Lines A, B and D LER 87052-LL Operators Fail to Follow Technical Specification Required Action with Multiple Intermediate Range Monitors Inoperable LER 87054-LL Suppression Pool Swell Deflectors Required by Design Were Not Installed for Six Limitorque Operators LER 87055-LL Failed Average Power Range Monitor Page Flow Card Results in Reactor Protection System Actuation LER 87056-LL Containment Isolation Valve Inadvertently Shut Due to Surveillance Instruction Requiring Lead Lifted at Wrong Terminal LER 87057-LL Deficient Change to Surveillance Instruction Results in

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Reactor Protection System Actuation During Scram Discharge Volume Sensing Line Flush

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LER 87059-LL Reactor Water Cleanup Containment Isolation Oue to Indicated High Differential Flow While Attempting to Bring r

the A Filter /Demineralizer in Service LER 87029 documented an event which occurred May 1,1987, when licensee operating personnel overrode the suppression pool high level / CST low

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level interlock after the RCIC suction automatically shifted from the CST to the suppression pool due to increasing suppression pool level caused by containment venting. After overriding the interlock, operators shifted the RCIC suction back to the condensate storage tank. This i

action was performed to protect the RCIC water leg pump which does not have a suction flow path while RCIC suction is aligned to the suppression pool. During the next shift turnover, the oncoming shift identified that

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the RCIC suction logic had been overriden and that technical l

specification 3.3.5 for RCIC system actuation instrumentation had been violated.

Following this discovery, the RCIC system was declared inoperable and approximately 40 minutes later, after suppression level had been restored, the RCIC suction interlock was returned to normal s ta tus.

In order to prevent recurrence, operators involved with the event were counseled on the requirements of technical specifications and appropriate actions to be taken when a Limiting Condition for Operations is exceeded. Additionally, an enginee. ng design change request was initiated which will allow RCIC to be in standby readiness and remain operable following a suction transfer.

Specifically, the water leg pump will be provided a suction path when the RCIC suction is aligned to the suppression pocl.

Failure to declare the RCIC system inoperable after

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overriding the RCIC suction logic for greater than one hour is contrary to Perry Unit 1 technical specification 3.3.5 and is a violation (440/87023-03(DRP)). This violation meets the test of 10 CFR 2, Appendix

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C,Section V.A; consequently, no Notice of Violation will be issued and this matter is considered closed.

LER 87038 resulted from licensee failure to take technical specification required actions upon discovery that the Division 3 diesel generator fuel oil was out of specification due to insoluble impurities.

On May 27, 1987, the results of a non-routine Division 3 diesel generator fuel oil chemical analysis indicated the level of insolubles to be above technical specification limits. Licensee chemistry personnel failed to inform operations personnel of the out-of-specification condition and instead initiated actions to obtain an additional fuel oil sample and to perform

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a similar chemical analysis. On May 29, 1987, approximately 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> later, the results of the second analysis confirmed that the diesel fuel oil was out of specification due to insolubles. Operations personnel were then notified of the condition and the Division 3 diesel generator was declared inoperable. Required technical specification actions were then taken.

Following the addition of fuel oil additive and recirculation of the fuel oil storage tank contents, on May 30, 1987 an additional fuel oil sample was taken.

On June 1, 1987, chemical analysis results were received which indicated that the level of insolubles in the fuel oil were well within specification.

Tne Division 3 diesel generator was then declared operable. Licensee evaluation determined that over the time frame in which the Division 3 generator fuel oil was out of specification, the Division 3 diesel generator would have been able to perform its intended functicn had it been required.

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recurrence, the individuals involved were counseled on the need to promptly report abnormal conditions or events that are known or suspected to be in violation of applicable specifications or procedures to

operations personnel. Additionally, chemistry unit personnel were

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trained with regard to the sequence of events resulting in this LER.

Failure to take technical specification required actions for out of specification Division 3 diesel generator fuel oil is contrary to technical specification 3.8.1.1 and is a violation (440/87023-04(DRp)).

This violation meets the tests of 10 CFR 2, Appendix C, Section V.A; E

consequently, no Notice of Violation will be issued and this matter is

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considered closed, i

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LER 87047 resulted from a misinterpretation of technical specifications

by operating personnel concerning the time limits placed upon surveillances required by technical specification action statements.

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On July 2,1987, the Division 2 diesel generator was declared inoperable for planned maintenance. Within the following hour, offsite electrical power sources were verified to be operable as required by technical specifications.

These verifications which were to be performed again in the following 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> were not performed until 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and 54 minutes

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later. A subsequent performance of the surveillance was also completed in excess of the allowable 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. Licensee investigation of this event disclosed that licensed operators believed that the allowable extension of surveillance intervals provided by technical specification 4.0.2

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applied to the surveillance time idravel specified in technical specifi-cation action statements requirW taa perfornunce of surveillances.

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The licensee detentdmd that tnis W5 6 canmn miwnderstanding among operating perso:ina) and that neither en.tnf og nor procedural ; controls adequately a$ dressed this ntust4n. A a m ult of the licensea's investigatico. Sweral corrective actions were teen to pnvent recurrence. A Eanagecent 0?nd.tive was issued to operating persennel discussing the appl!cability of tuhhi ai 3pecificatior 4.0.2.

Operating S

Administrative Pmcedven era revhed to previde for adequate trading of periodic surveiTlances requirtti by technic 41 specificatkn action

statements. Failure to Wr$fy the operability of effsite electrical power sources at least once per 8 bors fouowieg !.wperabWty of thw i

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Division 2 diesel cereratar is contrary to technical specification 3.8.1.1 and is a violation (440/3702b05(DP.P)). This violation meets

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the tests of 10 CFR 2 Ipundis C,Section V.A; consweently, no Notice of Violation will be ht.ved and thb matt,er h considefed closed.

LER 87048 reported an event involving the nispositioning of inanual containment isolation valves it. the fire protection water supply to containment. The event was reviewed durin9 an inspection documented in NRC Inspection Repsrt (40/87012(DRP).

The event resulted in a violation of technical specification requirertents for conuinment integrity and

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resulted in the issuaece of Severity levol IV Noti:e of Violation

(440/87012-06(DRP)). ticensee corrective setiers to address this event and the resultant Notice of Violation will be revined dwing a future inspection.

LER 87052 reported three similar events occurrfi\\g en July 3, 4, and 5, 1987 in which less than a minimum number of operable intennecibte range

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neutron monitoring s,ysten thannels were operable for o period of time greater than one tour whhout the inoperable channels or the Affected

trip systers being placed in a tripped condition H required by Technical

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Specification 3.3.1.

On April 2$ and May 15, 1987 IRM channels B and G, respectively, were declared inoperable due to detector failure.

Subsequently, on July 3, 1987, IRM channel A was rendered inoperable for calibration for a period of approximately 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br />. This resulted in

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there being leu than the mininum number of required Division 1 IRM

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operable channels. Subsequently, on July 4, 1987, IRM channel D was similiarif rendered inoperable resulting in less than the required

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ainimum number of operable Division 2 IRM channels for a period of

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approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. On July 5, 1987, IRM channel C was bypassed in order to install test and measuring equipment to monitor channel behavior and remained inoperable for a period of approximately 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />.

Surveillance test instructions utilized for the IRM calibrations on

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July 3 and 4, 1987 required that the reactor protection system be in a

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normal untripped condition. Operators believed that the calibration

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intervals for the IRMs would soon be exceeded and that performance of the calibrations took precedence over the technical specification

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requirements to trip the reactor protection system channels associated with the inoperable IRMs. Licensee investigation of these events

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detennined that the IRM calibrations with which the cperatorr were

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existing plant Operational Condition. As a result of these events, the l

a IRM calibration instructions were revised to provide clarification on the

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frequency and operational condition requirements for their perfomance, i

i The event on July 5, 1987, resulted from operator error in that the

operator failed to return IRM channel C to the normal configuration until

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i an oncoming crew noticed the IRM Division 1 bypass switch was bypassing

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channel C and that technical specification required actions had not been j

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taken. The involved operators were counseled by licensee supervisory

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personnel and all licensed operators were counseled to provide l

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information on the interpretation of technical specification requirements i

j associated with instrumentation.

Failure to trip inoperable IRM channels i

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for the associated reactor protection system trip systems with less than

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the minimum number of required operable channels within one hour is

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contrary to technical specification 3.3.1 and is a violation t

(440/87023-06(DRP)),

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l 9.

ColdWeatherPreparations(71714)

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The inspector reviewed the following Perry Plant Maintenance Infonnation r

l System (PPMIS) Repetitive Tasks which documented the inspection of piping I

insulation designed to prevent process, instrument, and sampling lines

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R85015548 R85015549 R85015550 R85015552

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R85015556 R85015557 R85015558 R85015559 i

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On November 4,1987, the inspector verified by direct visual observation

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that the following heat trace panels were in service:

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OR36P0003 1R36P0001 1R36P0004 1R36P0006

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i 1R36P0005 1R36P0008 1R36P0010 l

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The inspector visually examined insulation on heat traced pip ng and

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instrument lines associated with the ".,ondensate Storage Tank CST),the

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Emergency Service Water system, the Plant Vent Radiation Monitors, and

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the Post Accident Radiation Monitoring Systems.

On September 24, 1987,

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i the inspector discovered in the CST "moat" (the area between the CST and j

the CST retaining wall) 2 feet of rain water which covered the sensing l

l lines for the Reactor Core Isolation Cooling (RCIC) and the High Pressure l

Core Spray (HPCS) level instruments. Also submerged was the suction

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piping for the HPCS and RCIC pumps and a 2 foot portion of the test

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l return line for the RCIC and HPCS pumps. The submergence rendered the i

i sensing lines and the suction and return piping for the pumps susceptible

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)j On November 4, 1987, the inspector again noted the submergence and

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infomed the Responsible System Engineer (RSE) for heat tracing. The RSE

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informed operations personnel and on November 5,1987 the water in the

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moat was pumped out. WorkOrder(WO) 87-9441 Revision 1, was issued to replace all of the insulation, heat tracing, and terminal boxes that had been submerged. A temporary tent and heaters were installed to prevent j

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I freezing until heat tracing was repaired. The inspector will review licensee commitments and repairs during a future inspection.

This matter will be tracked as an unresolved item (440/87023-07(DRP)).

No violations or deviations were identified.

10. Startup Test Witnessing and Observation (72302)

On October 29, 1987, the inspector witnessed various portions of section 8.4, "Generator Load Rejection at High Power," of Startup Test Instruction (STI)-B21-027, Revision 3, "Turbine Trip and Generator Load Rejection."

On October 29, 1987, the inspector witnessed various portions of section

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8.2, "Void Response to Pressure Regulator Step Change," of Startup Test Instruction (STI)-J11-021, Revision 2 "Core Power - Void Mode Response."

On November 15, 1937, the inspector witnessed various portions of section 8.1, "Full Reactor Isolation," of Startup Test Instruction

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(STI)-B21-025B, Revision 2, "Full Reactor Isolation."

For each of these tests the following was observed:

The appropriate revision of the test procedure was available and in

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use by test crew members. The test crew was adequately staffed and

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knowledgeable. All test prerequisites and initial conditions were satisfied or waived in accordance with program requirements and reviewed as necessary.

Permanent plant equipment was used to record test data.

Testing vias performed as required by the procedure.

Test crew actions were correct and timely during test performance.

Coordiration and conmunications were sufficient. All required data was collected for

final analysis. Limiting Conditions of Operation (LCOs) specified in technical specifications were met.

11. Monthly Maintenance Observation (62703)

i During this inspection period the inspector observed / reviewed charcoal l

sample cannister removal from the control room emergency recirculation system HVAC adsorber plenum per Work Order 8709481 to ascertain that the j

activity was conducted in accordance with approved procedures, regulatory guides and industry codes or standards and in conformance with technical specifications.

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The following items were considered during this review:

the limiting conditions for operation were met while components were removed from service; approvals were obtained prior to initiating the work; activities

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were accomplished using approved procedures and were inspected as applicable; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and, confined i

space entry controls were implemented.

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Following completion of maintenance on the Charcoal Adsorber Plenum, the inspector vecified that these systems had been returned to service properly.

12. Monthly Surveillance Observation (61726)

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

SVI Description Date Observed P53-T9024 Drywell Personnel Airlock In Between November 12, 1987 Seal Test.

C11-T5376-D SDV Water Float Switch Level High December 29, 1987 Channel D Functional / Calibration for 1C11-N013D For both of these tests, the inspector verified that testing was performed accordance with procedures, that test instrumentation was calibrated, that limiting conditions for operation were met, that removal and 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 individual directing the test, and that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.

The inspector primarily observed those postions of Channel D testing per SVI-C11-5276-D which were performed locally at the scram discharge volume. Paragraph 9 of NRC Inspection Report 440/87016 documented the inspector's observations of those portions of similar Channel A testing per SVI-C11-5376-A that were performed in the Control Room.

13.

Physical Security Procedures For The Resident Inspector (71881)

During this inspection period, the inspectors observed / reviewed selected licensee activities for conformance with the approved physical security plan.

The inspectors reviewed security personnel staffing levels and verified that individuals authorized by the physical security plan to direct security activities were provided for each shift. The inspectors observed that access control measures, including search equipment,

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protected area and vital area barriers, and security door locking devices were operational and in use. The inspectors observed that personnel and packages entering the protected area were properly searched in accordance with licensee procedures.

The inspectors observed that persons granted access to the site were badged to indicate whether or not they had unescorted or escorted access authorization.

Finally, by direct observation the inspectors determined that the effectiveness of detection assessment aids was maintained by the absence of obstructions in the isolation zone, adequate illumination of the protected area and protected area barrier, and operable video surveillance equipment.

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No violations or deviations were identified, l

14. Radiological Protection Procedures For The Resident Inspector (71709)

Through discussions with licensee management, supervisory, and health physics personnel, and observation of licensee work planning activities, the inspectors determined that licensee personnel were aware of the ALARA program and that ALARA considerations were routinely considered in the planning of activities which involved occupational radiation exposure.

The inspectors also determined through monthly Plant Status Meetings such as the one described in Paragraph 17 of this report and review of the licensee's internally generated Monthly Performance Reports, that the status of meeting ALARA goals and objectives is periodically assessed and disseminated to affected plant personnel.

During the course of routine inspection activities conducted during this inspection period, the inspectors accessed plant areas requiring a radiation work permit (RWP). The inspectors reviewed the radiation work permits and verified that, in accordance with licensee procedures, the RWPs contained a description of activities authorized, radiation levels, contamination levels, protective clothing requirements, dosimetry requirements, health physics coverage requirements, expiration dates, and required review and approval signatures. The RWPs were determined to be current and readily available for employee review. Work activities observed by the inspectors were conducted in accordance with RWP requirements.

Inspector observation of personnel within the radiologically controlled area determined that personnel monitoring equipment was properly utilized and that dosimeter readings were recorded as required upon leaving the radiologically controlled area.

Personnel exiting the radiologically controlled area were observed to properly utilize personal contamination monitors. Posting of radiation areas, contaminated areas, and labeling of containers holding radioactive material was determined to be in conformance with NRC regulations and licensee procedures.

No violations or deviations were identified.

15.

Containment Closecut Inspection (61715)

On November 12 and 13, 1987 the inspector verified the proper positioning of the following isolation valves associated with containment penetrations:

Test Outboard Inboard Connections Isolation Isolation (Locked Shut Valves Valves and Capped)

Penetration P54-F726 P54-F727 P406 P11-F080 P11-F090 P111

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P43-F140 P43-F215 P311 P50-F150 P50-F140 P50-F571 P405 P43-F055 P43-F021 P310 P50-F060 P50-F539 P50-F570 P404 E51-F076

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P422 E51-F063 E12-F004B P402

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E22-F015 P401 E12-F004A P102 16. Onsite Review Committee (40700)

The inspectors reviewed the minutes of the Plant Operations Review Comittee (PORC) meetings No.87-218 through 87-220 conducted prior to and during the inspection period to verify conformance with PNPP procedures and regulatory requirements.

These observations and examirations included PORC membership, quorum at PORC meetings, and PORC activities.

17. Plant Status Meeting (30702)

On November 19, 1987, NRC management met with CEI management at the NRC Regional Offices to discuss the current status of the plant, recent events, and licensee initiatives to improve the quality of plant maintenance activities. These meetings are being held on a periodic (initially montMy) basis.

18. 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 l

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 rot a violation that could reasonably be expected to have been prevented by the licensee's corrective action for a previous violation.

i Violations of regulatory requirements identified during the inspection

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for which a Notice of Violation will not be issued are discussed in

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Paragraph 8.

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19. Unresolved Items

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Unresolved items are matters about which more information is required in order to ascertain whether it is an acceptable item, a violation or a-deviation. An unresolved item is identified in Paragraph 9.

20. 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. An open inspection item disclosed during the inspection is discussed in Paragraph 5.a.

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21. Exit Interviews (30703)

The inspectors met with the licensee representatives. denoted in Paragraph 1 throughout the inspection period and on December 30, 1987.

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.

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