IR 05000440/1989007

Insp Rept 50-440/89-07 on 890309-0605.Violations Noted.Major Areas Inspected:Licensee Action on Previous Insp Items, Refueling Activities,Operational Safety Verification,Maint Observation,Allegation Followup & Onsite Followup of Events

ML20245G128
Person / Time
Site:	Perry
Issue date:	06/21/1989
From:	Ring M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20245G118	List: IR 05000440/1989007 ML20245G112 ML20245G120
References
50-440-89-07, 50-440-89-7, NUDOCS 8906290033
Download: ML20245G128 (17)

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l U.S. NUCLEAR REGULATORY COMMISSION REGION III-Report No. 50-440/89007(DRP)

Docket No.-50-440 License No. NPF-58 Licensee: Cleveland Electric Illuminating Company Post Office Box 5000 Cleveland, OH 44101 Facility Name: Perry Nuclear Power Plant, Unit 1 Inspection At: Perry Site, Perry, Ohio Inspection Conducted: March 9 through June 5, 1989 Inspectors: P. L. Hiland G. F. O'Dwyer

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S. P. Ray J. W. McCormick-Barger B. S. Drouin R. D. Lanksbury i Approved By: -M. A. Ring, Chief /" < ~l/!57 Reactor Projects Secti n 3B Date

Inspection Summary Inspection on March 9 through June 5,1989 (Report No. 50-440/89007(DRP))

Areas Inspected: Routine, unannounced safety inspection by resident and regional inspectors of licensee action on previous inspection items; refueling activities; operational safety verification; maintenance observation; TI 2500/17,

" Improper Installation of Heat Shrinkable Tubing" (IEN 86-53); TI 2515/99,

" Power Oscillations in Boiling Water Reactors" (IEB 88-07); TI 2515/100,

" Proper Receipt, Storage, and Handling of Emergency Diesel Generator (EDG)

Fuel 011;" allegation followup; onsite followup of events; and two plant status meeting 'Results: Of the twelve areas inspected, three examples of one violation were identified in the area of onsite followup of events (Paragraph 8.b.3, 8. and8.b.8.). That violation concerned inadequate procedures. In addition, one " licensee-identified violation" for which a Notice of Violation was not issued was identified in the area of operational safety verification (Paragraph 5.b). The licensee-identified violation concerned an undetected error in design calculations for reactor water level instrument calibration data. All of the above items were receiving management attentio PDR ADOCK 05000440 '

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DETAILS 1. Persons Contacted Cleveland Electric Illuminating Company (CEI) I # xl. C. Phillips, President, C. # +xA. Kaplan, Vice President, Nuclear Group

1. +xM. D. Lyster, General Manager, Perry Plant Operations Department (PPOD)-

+xR. A. Stratman, Director, Nuclear Engineering Department (NED) ,

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+x V. K. Stead, Higaki,Director, Manager, Outage Nuclear Planning Support Section Department (PP00) )

(NSD L xW. R. Kanda, Manager, Instrumentation and Controls Section (PPTD)

+xS. F. Kensicki, Director, Perry Plant Technical Department (PPTD)

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

• +xR. A. Newkirk, Manager, Licensing and Compliance Section (NSD)

xK. Pech, Manager, Technical Section (PPTD)

+xE. Riley, Director, Nuclear Quality Assurance Department (NQAD)

• xG. R. Dunn, Compliance Engineer (NSD)

T. A. Boss, Supervisor, Quality Audit Unit (NQAD)

• D. J. Takacs, Manager, Mechanical Maintenance Quality Section (NQAD)

+ J. G. Cantlin, Refueling Planning Supervisor (PP00)

1. W. Coleman, Manager, Operations Quality Section (NQAD)

• xM. W. Gmyrek, Manager, Operations Section (PPOD) U. S. Nuclear Regulatory Commission xA. B. Davis, Regional Administrator, RIII

1. E. G. Greenman, Director, Division of Reactor Projects, RIII xC. J. Heltemes, Deputy Director, AEOD xR. L. Spessard, Director, Div. of Op. Assess., AE0D l xS. D. Rubin, Chief, Diagnostic Branch, AE0D I

1. G. M. Holahan, Director, DRP III/IV & V, NRR

1. M. J. Virgilio, Associate Director, DRP III & V, NRR

1. +xJ. N. Hannon, Director, Directorate III-3, NRR

1. +xT. G. Colburn, Project Manager, NRR

+ R. C. Knop, Chief, Projects Branch 3, RIII

+ M. A. Ring, Chief, Projects Section 3B, RIII l

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+xP. L. Hiland, Senior Resident Inspector, RIII

1. • xG. F. O'Dwyer, Resident Inspector, RIII xDenotes those attending the April 24, 1989 DET exit meetin + Denotes those attending the April 25, 1989 plant status meetin *N notes those attending the exit meeting held on May 9, 198 L. notes those attending the May 31, 1989 plant status meetin ,

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2. Lic'ensee Action on Previous Inspection Findings (92701, 92702)

l (Closed) Open Item (441/86002-01): Inability of the VAX System to Activate _the Emergency Paging Syste This same item for Unit- 1(440/86004-01) was closed in Inspection:

Report Nos. 440/86009; 441/86003, Paragraph 2, and should have been closed for Unit 2 at that time. This item is therefore close (Closed) Open Item 641/86002-02): Some Security Personnel-were not'

Trained in Site Evacuction and Accountability Procedure This same item for Unit 1-(440/86004-02) was closed in Inspection Report Nos. 440/86009; 441/86003, Paragraph 2, and should have been closed for Unit 2 at that time. This item is therefore close (Closed)Open-Item (441/86004-01): Ambiguous Guidance for Determining Emergency Condition Level This same item for Unit 1 (440/86019-01) was closed in Inspectico Report Nos. 440/87010;_441/87002, Paragraph * and should have been closed for Unit 2 at that time. This iten. . 4erefore close (Closed) Open Item.(441/86004-02): Incorpotetion of Semiannual Activation of Emergency Call-out Procedures into Emergency-Preparedness Plan and Drill Progra This same item for Unit 1 (440/86019-02) was closed in Inspection Report Nos. 440/87010;_441/87002, Paragraph 2, and should have been closed for Unit 2 at that time. This item is therefore close ~

No violations or deviations were identifie . Inspection and Enforcement Bulletin (IEB) Followup (92701) (Closed) IE Bulletin 79-18 (441/79018-BB): Audibility Problems Encountered on Evacuation of Personnel from High-Noise Area This item was still being followed for Unit 1 but was not applicable for Unit 2 unless/until construction of the unit resumes. If Unit 2 is constructed, the item will be reviewed as part of the normal NRC Near Term Operating License inspection program. This item is therefore closed for Unit (Closed) IE Infonnation Notice 86-53 (TI 2500/17): Improper Installation of Heat Shrinkable Tubin This Information Notice was previously discussed in Inspection Report 50-440/86028, Paragraph 4.b. During this inspection period the inspectors reviewed the licensee's procedures for installation of heat shrinkable (Raychem) tubing on electrical splices and inspected several applications of Raychem splices in the fiel _ _ - - _ - - _ _ - - _ _ _ - _ _ _ _ - _ _ - .

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The procedures used by the licensee to install Raychem splices are -

contained in Generic Electrical ~ Instruction.GEI-0007, " Instructions for Cable / Wire Terminations." The procedure has been updated to contain the latest Raychem product information and contains. specific and detailed steps to insure that the splices are installed in I

accordance with all Raychem recommendations. Acceptance criteria includes verification of proper length, flow of adhesive, smooth and glossy appearance, lack of blistering, and~ verification. that the tubing was not installed.over braided jacket material. . Installation instructions also included details and calculation for selecting'the proper size tubing and shims. Instructions included' specifications of minimum bend radius based 'on Raychem recommendations and instructions not to flex or bend the splice until the tubing had cooled after shrinkin Field inspections of representative Raychem splices revealed no improper installations. Discussions with licensee representatives-and regional inspectors indicated that improper-Raychem installation has not been a problem at' Perry. This. item is close ~ (Closed) IE Bulletin 88-07 (TI 2515/99): Power Oscillations in Boiling Water Reactor During the inspection period, the inspectors reviewed the licersee's response to'IE Bulletin 88-07 and Supplement 1 in accordance with Temporary Instruction 2515/99. In addition to interviews with plant operators and training personnel, the-following documents were examined:

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CEIC Letter PY-CEI/NRR-0907 L dated September 12, 1988 CECI Letter PY-CEI/NRR-0933.L dated November 1, 1988 CEIC Letter PY-CEI/NRR-0947 L dated December 2,1988 CECI Letter PY-CEI/NRR-0968 L dated Feb'ruary 15, 1989 Off Nomal Instruction ONI-B33-1, " Reactor Recirculation. Flow Control Malfunction"

- Off Normal . Instruction ONI-B33-2, " Loss of One or Both Recirculation Pumps" i

Off Normal Instruction ONI-P41, " Loss of Service Water" Off Normal Instruction ONI-C51, " Unexplained Change in Reactor Power or Reactivity" Various lesson plans in Operator Training Series OT-3035, 3046, R 3058, and 3059

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The inspector determined that the required actions of Bulletin 88-07

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had been completed and properly reported. Lesson plans for SR0/R0/STA retraining cycles 16 and 17 had incorporated lessons learned from the LaSalle event and actions to be taken with regard to operations in various sections of the power-to-flow curve. Lesson plans for replacement license classes had not yet been revised but commitments were in place to insure they were updated before the next replacement license class was to start. .The simulator was not able to simulate a flow induced power oscillation of the type seen at LaSalle, but instructors were able to demonstrate a similar effect by the use of a pressure regulator malfunction. The bid specifications for a new simulator were to include the requirements for simulating the oscillation A review of Off Normal Instructions confirmed.that procedures were in place to prohibit intentional operation in the shaded area of the power-to-flow ma Procedures also required the operators to manually scram the plant if both recirculation pumps were lost while '

operating with the reactor mode switch in RUN, if core flow was less than 48 Mlbm/ hour with the rod line above the 100% rod line, if APRM peak to peak oscillations exceeded 10%, or if periodic LPRM UPSCALE or LPRM D0WNSCALE annunciators were received indicating out of phase oscillations not observable on APRM The inspectors interviewed various SR0s and R0s concerning their knowledge of the procedures. All the individuals interviewed had been briefed on the LaSalle event and were knowledgeable of the procedures to avoid power oscillations, d. (Closed) TI 2515/100, " Proper Receipt, Storage, and Handling of Emergency Diesel Generator (EDG) Fuel 011."

The inspectors performed a review of the licensee's program for i receipt, storage, and handling of EDG fuel oil. This inspection verified that the licensee routinely determines the quality of stored fuel oil and the condition of the fuel oil storage and transfer system. The inspectors reviewed the licensee's Technical Specification (TS) and Updated Safety Analysis Report (USAR)

requirements for the fuel oil system and reviewed related surveillance procedures to determine if the licensee's surveillance program meets its regulatory commitment This review indicated that the licensee's fuel oil storage program complies with its regulatory commitments and appears to meet the NRC requirements identified in Regulatory Guide 1.137, " Fuel-oil Systems for Standby Diesel Generators," including the applicable fuel oil testing requirement Recently, the licensee reported an event (LER 89-01) where all three EDGs were inoperable during power operations. After the licensee

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had declared two of the.EDGs inoperable (Division 1 was out-of-service for planned maintenance, and Division 3 was out-of-service for L

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15 minutes while performing prestart checks for a surveillance

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required by TSs), Division 2 EDG was declared inoperable due to unsatisfactory results from a fuel oil storage tank sample analyse The unsatisfactory results (high concentration of insolubles) were'

believed to be due to fuel oil aging, possibly accelerated by the-recent addition of new fuel oil to the storage tank. The fuel oil had been in the storage tank for approximately four years. The licensee-added a dispersant agent to the fuel oil to correct the immediate problem. To prevent recurrence, the licensee will continue its quarterly sampling of the fuel storage tanks and periodically replace the fuel oi No violations or deviations were identifie . Review of Allegation (99014)

'(Closed) Allegation (RIII-89-A-0031). Qualifications of contractors involved in the removal of the Reactor Pressure Vessel (RPV) hea Allegation:

On March 1,1989, an alleger telephoned Region III with information that a crew of Bechtel Power Company employees, assigned to remove "the dome,"

was not trained for the task. A regular crew was assigned to the task and that crew had received specific training for removing the dome. Over the past' weekend the regular crew worked an excessive amount of hours training for the task and could not be scheduled to work on Sunday (February 26,1989). However, the work continued in order to meet the outage schedule and an untrained group of workers was assigned to the task of removing the dome. Unlike the original workers, the replacement workers had not received the required 3-4 day training course for the job. The caller thought the replacement workers may have also been assigned to do repairs to the pipes below the dome, but that work had not yet begu Review:

A Region III inspector reviewed the allegation onsite the week of March 27-31, 1989. On March 29, 1989, the Plant General Manager was infomed of the general nature of the allegation. The inspector detemined through interviews and document reviews that the incident in question involved the removal of the Reactor Pressure Vessel (RPV)

head on February 27, 198 The inspector established that three outage operations required the removal and lifting of " dome" like structures. The drywell head, the A review of pa drywell head insulation frame and the RPV head. training records identifi contractors (boilermaker, journeyman), who participated in the RPV head

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. # rem' oval but had.not-received the training that other RFCI contractors detailed to Bechtel-KWU. Alliance (BKA)= for the RPV head: removal had receive Interviews on March 29, 1989, with the BKA Perry Project Manager, the licensee's contract services section representative and the lead planner for the maintenance section's planning unit determined that no specialized training was required for the removal of the'RPV head. The RPV head lift was classified as " heavy load" however, and came under the purview of Maintenance Administrative Procedure (MAP) 1301, Revision 1,-

entitled " Control of Heavy Loads," effective August 4,1986. MAP 1301-required a briefing of all participants involved in the RPV head'11f The inspector verified through document review and interviews that the briefing occurred on February 27, 1989 and included the required personne The licensee /BKA provided familiarization training to contractors who would be utilizing the BIACH tensioners to' detension RPV head studs as an efficient operating practice. The BIACH familiarization training was not

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required by any plant procedure. The inspector verified the absence of a training requirement through interview and review of Perry General Mechanical Instruction (GMI) - 0063, Revision 1, entitled, " Installation and Removal of the Reactor Pressure Vessel Head," effective January 23, 198 A review of pay records identified the four millwrights involved in

.detensioning the RPV head studs on February 26-27, 1989. A review of training. records revealed the millwrights received BRIACH familiarization training on February 16, 198 An interview with BKA Project Manager disclosed that the five RFCI boilermakers who were not part of the planned RPV head removal operation were included to assist and/or relieve other craft personnel who had received BKA outage training. The BKA Project Manager stated that the five RFCI boilermakers without the preoutage BKA training were needed because preoutage trained craft per ;onnel involved in the RPV head removal operation had been working an extended shift on February;27, 1989. Although the RPV head removal went smoothly, the operation began later in the shift than planned necessitating an extended shif The BKA Project Manager stated there was no problem substituting RFCI l

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millwrights for preoutage trained personnel because there was no required training necessary for the RPV head removal and they were only given tasks which were applicable to their craft. The RFCI millwrights were not employed in detensioning the RPV head studs or in the heavy load lift

. Cre An interview with one the five millwrights on March 30, 1989, confirmed that he and the other four millwrights did not detension RPV head studs or participate in the heavy load lift on February 27, 1989. The millwright informed the NRC inspector that he and the other RFCI

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mi1~1 wrights hauled tools up and down to aersonnel working on the RPV head, yellow bagged tools and connected loses. All tasks performed by the five mi11 wrights while they augmented the scheduled RPV head removal crew were within their craft specialties and required no specialized trainin The. millwright also stated the RFCI training which craft personnel receive upon arrival at the Perry site was similar to: the pre-outage training provided by BKA to the scheduled RPV head removal crew. The mi11 wright informed the NRC inspector that he (millwright) and the other four RFCI craft personnel's augmentation to the BKA RPV head removal operation as of the interview (6.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> on February 27.1989)

was the only occasion where they (mi11 wrights without preoutage training)

supported BKA refueling outage. operations. The inspector's review of BKA overtime records substantiated the mi11 wrights clai !

On March 29, 1989, the NRC inspector contacted the licensee's Contract Service Section (CSS) to-determine whether BKA could substitute RFCI craft people to work refueling outage contract work in lieu of BKA preoutage trained craft personnel. The CSS representative stated the refueling outage contracts required specialized training for certain personnel only, i.e., fuel' handling, fuel bridge, maintenance of specialized equipment. No other training was required by contrac Conclusion The allegation was partially substantiated in that five RFCI mi11 wrights who had not received BKA preoutage training worked with other craft l personnel who.had received preoutage training on February 27, 1989, when the RPV head was removed. The BKA preoutage training was not required by licensee procedure to conduct the RPV head removal operations and the five RFCI mi11 wrights were only involved in peripheral support tasks for which they had more training and experience than necessary. There was no safety significance to the allegation. The Plant General Manager and the Compliance Engineering lead were informed of the inspector's conclusion, on March 31, 198 No violations or deviations were identifie . Operational Safety Verification (71707, 71710)

The inspectors observed control room operations, reviewed applicable !

logs, and conducted discussions with control room operators during the 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 i 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 observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection controls.

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i The'se reviews and observations were conducted to verify that facility

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operations were in conformance with the requirements of Plant Technical Specifications, 10 CFR, and administrative procedure .

During the inspection period an NRC Diagnostic Evaluation Team performed l a detailed review of plant activities to provide infomation to senior '

NRC management to supplement Systematic Assessment of Licensee Performance (SALP) evaluation, NRC Performance Indicators, and other assessment data. The Team evaluated actions and involvement of licensee management and staff in safe plant operation, the effectiveness of j licensee safet

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root cause(s) ofy improvement programs, safety performance and the problem A licensee's determination detailed report of the of Team's findings was issued May 30, 198 On February 23, 1989, the licensee noticed heat induced damage to cables in three conduits in the upper region of the drywell. The cables were discolored and extremely brittle. On March 2, 1989, the licensee discovered that two mechanical snubbers in the same area of the drywell failed to stroke and had apparent heat damage. Further investigation determined that the grease in the snubbers had vaporized away. The licensee then conducted further inspections and determined that about 140 cables may have been damaged from excessive heat. Junction box and condulet sealing gaskets were also l affected. The cables were environmentally qualified for 195 degrees i and the snubbers were qualified for 300 degrees F. Temperatures of the components were believed to have been higher than their  ;

qualified temperatures for extended times, i The affected area was above the bioshield just outboard of the refueling bellows and below the horizontal bulkhead that forms the floor of the reactor refueling cavity under the drywell hea Thermocouple near the affected equipment had not shown excessive temperatures. The licensee believed that the damage may have been caused by direct component heatup due to radiative heat transfer from the exposed refueling bellows shroud.' Lack of adequate air circulation in the area may have also contribute The cables were used in multiple systems including leak detection, nuclear instrumentation (all ranges), standby liquid control, safety relief valves, and head vents. After an initial evaluation, the licensee decided to replace about half of the affected cables in accordance with Design Change Packages (DCPs) 89-63 (safety-related portion) and 89-63A (nonsafety-related portion). The licensee had not yet determined whether the operability of the systems had been affected so the condition was not reported to the NRC until the inspectors requested more information on April 6, 1989. The issue of deportability item regarding)this (50-440/89007-03(DRP) eventfurther pending is considered an unresolved NRC review-The licensee sent samples of the cables offsite for analysis to help determine the effect of the temperatures on the qualified lifetime

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• 3 of the components. The licensee also performed an engineerin evaluation to determine modifications:to the insulation in the affected area to prevent recurrence. DCP 89-62 was issued to

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install additional insulation. General Electric issued RICSI No. 41 to the other BWR-6/ Mark III Containment owners to alert -

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them to the potentia 1' proble On May 16, 1989, the licensee informed the NRC'via an-informational ENS call-of a previously undetected error ~1n the design calculations for reactor vessel level instrumentation' calibration data. The ,

licensee identified that three instruments,:1B21-N080B (level 3/8 trip),1821-1095B (Level 3 ADS permissive), and IC34-N004 (feedwater. control) had calibration data sheets that were' calculated based on the wrong penetration elevation. The -incorrect elevation used in the calibration calculations caused the instrument-indications to be about 2 inches higher than the actual level and

'therefore the various trips occurred about 2 inches lower than it was intended for.the trips to occur. The only safety-related trip-that was affected non-conservatively was~one channel out of four of the reactor water level 3 scram. Table 2.2.1-1 of the Technical Specifications required that the level 3 scram setpoint be greater than or equal to 177.7 inches above the top of active fuel with its allowablei value to be 177.1 inches above top of. active fuel. The error non-conservatively allowed the scram setpoint to be set so that one of the four channels would not actually trip until ~the water level was as low as 175.7 inches above the. top of activ fuel. This error existed for the entire first fuel cycle and therefore allowed the violation of Technical Specification 2. which ("with a reactor protection system instrumentation setpoint :less conservative than the value shown in the Allowable . Values column of Table 2.2.1.-1") required that the channel be declared inoperable, the trip system be placed in the tripped condition within one hour and the plant be placed in Hot Shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> until the channel is restored to OPERABLE status-with its setpoint adjusted consistent with the Trip Setpoint value. The licensee's assessment concluded that there was no significant degradation of plant safety due to this instrument error. This violation (440/89007-01(DRP))

Emeets the tests of 10 CFR 2, Appendix C, Section V.G; consequently no notice of violation will be issued and this matter is considered-close One : licensee-identified violation and one unresolved item were identified and no deviations were identifie . Monthly Surse111ance Observation (61726)

The NRC Diagnostic Evaluation Team reviewed several surveillance l instructions and the surveillance program during this inspection perio These reviews were documented in the Team's report which was issued May 30, 198 _ _ _ - _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ .

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No violations or deviations were identifie . Monthly Maintenance Observation (62703)

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 specifications.-

The followinc items were considered during this review: the limiting conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or calibrations were performed prior to returning components or systems to service; quality I control records were maintained; retivities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and, fire prevention controls were implemente Work requests were reviewed to determine status of outstanding jobs and i to assure that priority is assigned to safety related equipment maintenance which may affect system performanc Portions of the following maintenance activities were observed / reviewed: The inspectors observed portions of the work activities associated with the replacement of safety related cables that were damaged in the upper drywell because of insufficient refueling bellows insulation. The damaged cables were reported in LER 89-010. During the inspection, the inspector observed the work area, reviewed Work Orders (WO), WO890002833, Revision 1. " Splice Cables in IR33R391A, Neutron Monitoring," and WO 890002834, Revision 1, " Splice Cables in IR33R396A, Neutron Monitoring." Testing of the replaced cables was

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to be performed under W089000277 The inspectors observed portions of several in-drywell work activities associated with pipe support installations and the inspection and removal of foreign material (bailing wire and weld rod) in the Scram Discharge Volume (SDV) drain tank. The SDV work-activity resulted from the licensee's relatively slow draining of l the SDV drain tank. The licensee utilized radiography and optical boroscope equipment to identify the foreign material. The two inch ;

drain line was cut to remove the foreign items and subsequently i rewelded. Hydrostatic testing of the SDV system was required prior to return to servic In addition to the work observations identified above, the NRC Diagnost.ic Evaluation Team observed several maintenance activities during this inspection period including the replacement of relief valves on the Division I Emergency Diesel Generator starting air system, repair of the l

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die'sel generator ventilation vent louver seals, replacement of the reactor containment inner personnel airlock door seal, and the attempted repair of the main steam leak off valve. The results of the Diagnostic Evaluation Team's reviews were documented in a report issued May 30, 198 No violations of NRC requirements were identifie . Onsite Followup of Events at Operating Power Reactors (93702) General The inspectors performed onsite followup activities for events which occurred during the inspection period. Followup inspection included one or more of the following: reviews of operating logs, procedures, condition reports; direct observation of licensee actions; and interviews of licensee personnel. For each event, the inspectors reviewed one or more of the following: the sequence of actions; the functioning of safety systems required by plant conditions; licensee actions to verify consistency with plant procedures and license conditions; and verification of the nature of the even Additionally, in some cases, the inspectors verified that licensee investigation had identified root causes of equipment malfunctions and/or personnel errors and were taking or had taken appropriate i corrective actions. Details of the events and licensee corrective actions noted during the inspectors' followup are provided in paragraph b. belo Details (1) Technical Ino)erability of Emergency Service Water System Perry Unit 1 LENS 10. xxxxx]

On March 15, 1989, at approximately 3:45 p.m. the licensee declared Train B of the Emergency Service Water (ESW) System Inoperable. At the time, the A train of ESW was already inoperable because of scheduled maintenance. The B train of ESW provides cooling water for the Division II Emergency Diesel Generator, the B train of Residual Heat Removal.(RHR) heat ,

exchanger, and the Control Room Ventilation system emergency mode coolers. The licensee was in the process of performing surveillance test SVI-P45-T2002, "ESW pump B and Valve-Operability Test, "when it was determined that pump discharge '

pressure could not be lowered low enough to meet the surveillance requirements. Investigation by the licensee  ;

revealed that the pump discharge pressure gauge was out of calibration. The licensee recalibrates the gauge, successfully '

completed the surveillance, and at 7:35 p.m. declared the B train of ESW operable. The licensee made the required Emergency Notification System (ENS) Notification at 6:37 Throughout the event the B train of ESW was functional and i

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could have been used if needed. The licensee is currently in a maintenance / refueling outage and was using the B train of RHR for shutdown cooling. The licensee also suspended core alterations as required by.the Technical Specification <

(2) Suppression Pool Volume Design Calculation Error [ ENS No 15030]

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On March 16, 1989, at approximately 3:45 p.m. (CST), the licensee's Independent Safety Engineering Group (ISEG) reported that their review of the original Gilbert Associates (the i licensee's architect engineer) calculations of suppression pool volume appeared to not take into account the as-built thickness of the wier wall. Apparently two sets of drawings existed showing the wall thickness and the two sets of drawings showed a difference of 1/2." Initial calculations using the more conservative figure indicate that at the minimum suppression pool level of 18 ft. O in, the suppression pool volume would be 160 cubic feet less than the required 115,612 cubic ,

feet. The licensee is continuing to investigate this issue and j has indicated that when the suppression pool is required to be ?

operable they will maintain a minimum level of 18 ft. 1 i .

(3) Engineered Safety Feature Actuation During Ground Isolation LENS No. 15255]

On April 8, 1989, the licensee notified the NRC via the ENS that they had received an unex,nected Reactor Core Isolation Cooling (RCIC) system initiation signal and auto start of the

"A" Emergency Service Water (ESW) pump while conducting ground isolation on DC bus ED-1-B in accordance with off-normal instruction ONI-R42-2, " Loss of DC Bus ED-1-B (Unit 1)." The plant was in a refueling outage with all fuel removed at the  :

time of the event. The operators immediately stopped the ESW pump. The isolation was apparently caused by a RCIC level 2 actuation signal being generated by opening DC circuit breaker ED1808-disconnect No. 5. Later during the same ground isolation, Division 2 Diesel Generator Room Cooling Fans M43-C001B and 2B

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unexpectedly auto started when circuit breakers No'. 7 and No. 8 l of ED1B06 were cycled. The licensee also reported that actuation in the ENS cal The licensee documented the event in Con.dition Report 89-14 The operators were using DNI-R42-2 to determine of the effects of cycling the breakers during the ground isolation. This procedure was determined to be inadequate in that it did not fully describe the effects of opening disconnect No. 5. The licensee does not have a detailed DC ground isolation procedure with precautions to be taken to prevent unexpected actuations of equipment. In the Condition Report the writer remarked that the relatively high ground (191 amps battery discharge rate)

encouraged them to try to find the ground in an expeditious

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manner. The inadequate procedure is considered an example-of a violation (50-440/89007-02a(DRP)).

(4) Reactor Scram Signal While Shutdown and Balance of Plant isolation LENS No. 15267)

On April 9,1989, the licensee informed the NRC via the ENS of a reactor scram and balance of plant (B0P) isolation even The reactor was shutdown and defueled at the time and all control rods ~were already fully inserted. Several valves stroked closed as a result of the B0P isolation. With the "B" Reactor Protection System (RPS) bus secured for an outage, the licensee was in the process of transferring the supply to the

"A" RPS bus from the alternate to normal supply. During the transfer, power was lost-to both buses long enough to cause the actuations. The licensee documented the event with Condition Report 89-146. The licensee was investigating whether the actuations were the result of an inadequate procedure for transferring RPS bus power supplies or operator erro (5) Inadvertent Actuation of Containment Isolation Valves LENS No. 15270J On April 10, 1989, the licensee reported to the NRC via the ENS that the plant had experienced the inadvertent isolation of three containment isolation valves during restoration from an .

electrical outage on April 9,1989. During the "B" RPS bus outage mentioned in the paragraph above, power had been removed from several containment isolation valves in order to prevent their actuation from the isolation signals that are generated by loss of the bus. During the restoration, the bus was reenergized, the isolation signals were reset, and the valves were repowered. Because of unrelated work being conducted on the Main Control Room (MCR) panel, the isolation signals for three valves could not be reset. The operators were not aware that the isolation signals didn't reset because the alarms and indicating matrix for them was out of service. The valves thus stroked shut when they were reenergized with no indication in the Control Roo The valves affected were G61-F150, G61-F165, and E12-F009 which were containment isolation valves for the drywell and containment floor drain sumps and component cooling system.

l The isolation of these valves was not noticed until the

! radwaste operators noted a high level in the drywell floor drain sump and high discharge pressure on the running sump pump. The licensee documented the event in Condition Report 89-148. The cause of the isolations was inadequate information on the part of the control room operators about the effect of the tagout on the MCR panel. There was no indication on the

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reset switches that they were not operable even though the reset circuit fuses were removed as part of the tagout. This issue is considered an unresolved item (50-440/87-007-04(DRP))

pending further NRC revie (6) Inadvertent actuation of Emergency Closed Cooling (ECC) Pump LENS No. 15363]

On April 17, 1989 at about 3:20 p.m. (EDT) while the plant was in operational condition 5, " Refueling," ECC pump "A" was discovered running and a Reactor Core Isolation Cooling (RCIC)

initiation signal was discovered locked in. At about 1:24 p.m.,

when breaker no. 5 on distribution panel E01B08 was opened, the operator noticed a blinking (cleared) " low discharge pressure alarm" annunciator for ECC Pump "A." The operators verified that ECC Pump "A" was operating properly. Many alarms were clearing at that time due to the downpowering of various optical isolators since distribution panel ED1B08 was being deenergized for an outage. At about 3:20 p.m. reactor operators realized that they had not started the pump, that it had automatically started for unknown reasons and that a RCIC initiation signal was locked in. On April 23, 1989, licensee personnel determined that the root cause of this event was that Off Normal Instruction (0NI)-R42-2 did not specify all the loads to be lost when deenergizing ED1B08 or that opening breaker no. 5 would deenergize optical isolator E12A-AT1 ON1-R42-2 also did not specify the results of those action Also determined was that operators on shift were unable to predict the results of the deenergization of an optical isolator. This issue is considered an example of a violation in that ONI-R42-2 was an inadequate procedure (440/89007-02b(DRP)). The licensee has since clarified their 50.72 reporting procedure to state that the ECC pumps at Perry are not essential safety feature actuations therefore no LER was issue (7) Partial ESF Actuation [ ENS No. 15400]

On April 21, 1989, at about 1:50 a.m. EDT, a partial " Loss Of Offsite Power (LOOP)" signal for Division I caused: (1) the cooling water flow to the P47A chiller to shift from Normal Closed Cooling System (ECC), 2)(System (NCC)

NCC to isolate to the from the Emergency Closed Cooling

"B" heat exchanger for the Fuel Pool Cooling and Cleanup (FPCC) System, (3) the Service Water (SW) Bypass Valve for the NCC heat exchanger to close, and (4) the Service Water Pump "B" Discharge Valve to cycle open and closed several times until its breaker was opened. The licensee has determined root cause of the partial LOOP signal to be personnel error in that a jumper was inadvertently jarred free while doing other work in the same l

cabinet. The licensee was investigating why the Discharge Valve

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had cycled excessively. The P47A chiller is necessary to i sustain operability of-the Emergency Recirculation and the  !

Normal Modes of the Control. Room Ventilation Syste The P47A chiller did not restart automatically when ECC flow was restored because the LOOP signal was only a partial on Following the event, the control room operators assessed the condition thoroughly in order to ensure the impact on all affected systems was fully understood and that no unexpected events had occurred. As a result, the operators chose to restore the NCC water supply to the P47A chiller before restarting it. The chiller was therefore out of service with no impact upon Control Room Ventilation System for about 55 minutes total. The licensee has decided that since the LOOP signal was only partial, that since only the four actiuns listed previously occurred and since all actions (such as Division 1 Emergency '

Diesel Generator or trip signal for P47A chiller) for a LOOP were not initiated there was no full unplanned Engineering Safety Feature actuation. Consequently, the 50.72 report of the licensee as April 21,1989,1:50 conservative and no EDTEvent Licensee was viewed Report by(LER) will be forthcomin (8) Unexpected Flooding of Drywell On April 25, 1989, at about 1:43 p.m. (EDT), while the plant was in the first refueling outage with all fuel assemblies removed from the core, control room operators received a report of water overflowing the suppression pool weir wall. They noted that the suppression pool level instrument confirmed this and that the Condensate Storage Tank (CST) level had also decreased by over 30,000 gallons. Plant Operators were dispatched to determine the source of the leakage. When the High Pressure Core Spray (HPCS) CST suction valve (E22-F001)

was shut the CST and suppression pool levels stopped changing).

The HPCS full flow test return line isolation valve (E22-F023 was checked and found opened because maintenance personnel were cycling it since about 10:30 a.m. to perform MOVATs testing in accordance with Work Order 88-9113. The associated Tag-Out 1-89-1449 was inadequate because it failed to ensure that the Hi Tank (CST) gh Pressure Core Spray (HPCS) Condensate Storages throughout the testing. At about 9:42 a.m. an unexpected Division III Diesel Generator start caused E22-F001 to open and therefore when E22-F023 was opened this established a drain path from the CST to the suppression pool. Plant operators observed about 12 inches of standing water in the drywell. The licensee assessed the affect that this ficading had on equipment in the drywell and decided that only one uninstalled snubber that was on the floor of the drywell needed to be replaced. The inadequate tagout is considered to be an example of a violation (50-440/89007-02c(DRP)).

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One' violation with three examples and an unresolved item were identified but'no deviations were noted.

l Plant Status Meetings (30702)

NRC management met with CEI management on April 25, 1989, at the Perry plant and on May 31, 1989, at the NRC Headquarters in Washington, in order to discuss the current status c,f the Refueling Outage, recent events, and licensee initiatives to improve the quality of plant operating and maintenance activities. These meetings are being held on a periodic t' initially monthly) basi . 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.G. These tests are: (1) the

• !Wtion 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 A violation of regulatory requirements identified during the inspection for which a Notice of Violation will not be issued is discussed in i Paragraph . Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities (92700)

On May 9, 1989, as requested by the memorandum of May 1, 1989, from the Director of Division of Reactor Projects, RIII, to all Senior Resident Inspectors; the inspectors briefed the licensee's Manager of Technical Section about the freeze plug failure at River Bend Nuclear Power Plant and the discovery by inspectors of a hydrogen tank fann located on the roof above the control room of a plant in Region . Exit Interviews (30703)

The inspectors met with the licensee representatives denoted in Paragraph 1. throughout the inspection period and on May 9,198 The inspectors 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 infonnation disclosed during the inspection could be considered proprietary in natur I 17 \

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