IR 05000440/1990018

Insp Rept 50-440/90-18 on 900730-0919.No Violations Noted. Major Areas Inspected:Monthly Surveillance Observation, Monthly Maint Observations,Operational Safety Verification & Onsite Followup of Events

ML20058D220
Person / Time
Site:	Perry
Issue date:	09/19/1990
From:	Lanksbury R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20058D216	List: IR 05000440/1990018 ML20058D208 ML20058D217
References
50-440-90-18, NUDOCS 9011050412
Download: ML20058D220 (17)

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U.S. NUCLEAR REGULATORY COMMISSION

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REGION III

Report No. 50-440/90-18(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 Inspection At:

Perry Site, Perry, Ohio

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Inspection Conducted: July 30 through September 19, 1990 Inspectors:

P. L. Hiland G. F. O'Dwyer-

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Approved By:

R'. D'. Lanksbury, Chief OCT 191990

' Reactor Projects Section 3B Date Inspection Summary-

-Inspectio'n on July 30 through September 19. 1990 (Report Nc. 50-440/90-18(DRP))

Areas Inspected:

Routine, unannounced safety inspection by. resident inspectors

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of licensee action on previous inspection items; monthly surveillance observation;

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monthly maintenance observations; operational safety verification; onsite followup of events; and-plant status meeting.

Results: Of the'six areas. inspected, one violation was identified.: The

.. violation was: identified ^1n the. area of event' followup (paragraph-6.b.(3)) and

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concerned lthe licensee's failure to' report'a non-emergency event within four i

. hours astrequired by 10 CFR 50.72). Although-the violation was. identified by the licensee, repetitive occurrences indicated that past corrective actions-were not adequate-to prevent recurrence.

In addition,_two unresolved items-

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were ident_ified during this report period in the area of event: followup.

First, the licensee failed to maintain'a flowmeter instrument calibrated (paragraph 6.b.(1)), The licensee concluded that calibration was not'

required.

Second, the' licensee had reported an unexpected Engineered Safety Feature actuation due to identification of closed containment isolation valves'

(paragraph 6~b.(7)). However,' initial investigation indicates that the subject

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valves had been: properly closed in accordance with a planned _ evolution. The violation and unresolved items were receiving appropriate licensee attention at.the'close of the report period.

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9011050412 901019 PDR ADOCK 05000440

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For;this report-period, the area of plant operations =was considered a: strength

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- based on theLinspectors' observations of routine plant evolutions, the 64-September 7: planned' plant shutdown, and the operator's response to events.

- The area-of maintenance.and surveillance activities were considered adequate.

However,-some. weaknesses in the proper performance of surveillance valve and-

electrica1Llineups were noted.-

n-In general,-the. inspectors found the area of security to be a strength based F

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on routine observations. In addition, the area of-radiological ' controls was

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considered adequate and the inspectors noted-improvements-in-health physics =

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practices as the' refuel outage commenced, bci. -. t'

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DETAILS 1.

Persons Contacted

Cleveland Electric Illuminating Company (CEI)

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1. M. ' Lyster, Vice President, Nuclear-Perry

1. R. Stratman, General Manager, Perry Nuclear Power Plant (PNPP)

1. • M. Gmyreck, Operations Manager (PNPP)

1. M. Cohen, Manager Maintenance Department (PNPP)

1. S. Kensicki, Director, Perry Nuclear Engineering Department (PNED)-

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1. F. Stead, Director, Perry Nuclear. Support Department (PNSD)

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1. • R. Newkirk, Manager, Licensing and Compliance Section (PNSD)

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1. • E. Riley, Director, Perry Nuclear Assurance Department (PNAD)

• W. Coleman, Manager, Perry Nuclear Assurance Department (PNAD)

1. A. Okorn, Shift Supervisor (PNPP)

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U. S. Nuclear Regulatory Commission

1. K. Rogers, Commissioner

-# W. Forney, Deputy Director, Division of Reactor Projects, RIII

1. • P. H11and, Senior Resident Inspector, RIII

1. • G. O'Dwyer, Resident Inspector, RIII

1. Denotes those attending the management meeting held on. August 7, 1990.

• ~ Denotes those attending the exit meeting held on September 19, 1990, t

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Licensee Action on Previous Inspection Findings (92701)(92702)

o (Closed)' Unresolved Item (440/88020-02(DRP)):

Determination of whether an adequate safety evaluation was performed to determine if an unreviewed safety question existed as-a result of a design change proposed in response to Engineering Design Deficiency Report (EDDR)-252.

The. concern of EDDn.-252 was that under some operating conditions the temperature-activated flow control valves for; Control Complex Chillers "A" and "B" reduced the Emergency Closed Cooling (ECC) System flow through each Chiller to a

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rate-that did not satisfy the ECC system restart permissive flow switch e

and would not allow the chillers to automatically restart after a Loss of Offsite Power (LOOP) or a Loss of Coolant Accident (LOCA) as required

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by the Updated Safety Analysis Report (USAR), Section 9.4.9.5.1.a.

The initial response to EDDR-252 was revised.(revision 2) such that the

design of the Control Complex' Chillers to restart automatically after a LOCA or LOOP event was maintained.

The ECC system restart permissive flow switches for the Control Complex Chillers were set at 723 gallons

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per minute (gpm) which was below the normal flow rate through each chiller of about 1200 gpm.

Section 4.1.6 of System Operating Instruction

. (S01)-P47, Revision 4, " Control Complex Chilled Water System," directed operating personnel to manually position the temperature control valves at a -stationary position to maintain a constant 1200 gpm through each

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chiller.

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At the close of this inspection period, Engineering Design Change Request (EDCR) 88-0288 had been written and proposed to:

replace the motor-operated, temperature-activated flow control valves with manual butterfly valves;

'de-terminate wiring and abandon in place; and remove the temperature controllers from the control room panel.

The licensee. identified the commitment to maintain adequate flow through the Control Complex Chillers (to ensure automatic restart after a LOCA or LOOP) in their commitment tracking system (Perry Regulatory Information Management System) as commitment LO1044.

501-P47 and Perry Round Instruction (PRI)

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Equipment Rounds" required that the ECC system flow through the chillers be maintained above 1000 gpm and both procedures stated that they satisfied commitment LO1044.

Step 6.7 of Perry Administrative Procedure (PAP)-0507, revision 8,_" Preparation, Review and Approval of Instructions," required that all commitments satisfied by instructions be incorporated into any new revisions.

Steps 6.2.2.2 and 6.4.1.8.a of PAP-0522, revision 4,

" Temporary Changes to Instructions," required that all commitments satisfied by instructions be incorporated into any temporary changes

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to instructions. These measures provided configuration control so that changes to the ECC system flow would not be made without consideration of the commitment. Based on the actions taken by the licensee as discussed above, this unresolved item is closed.

No violations or deviations were identified.

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3.

Monthly Surveillance Observation (61726)

For the surveillance activities listed below the inspectors verified one or more.of the'following:

testing was: performed in accordance with

procedures; test instrumentation was calibrated; limiting conditions for l

operation _were met; removal and restoration of the affected components ~

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were properly' accomplished; 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.

Surveillance Test No.

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SVI-B13-T0004, revision 4

" Reactivity Anomaly Calculation During Mode 1" SVI-C11-T1003, revision 5

" Control Rod Exercise" SVI-G50-T5266, revision 2

" Liquid Radwaste Release i

Permit"

SVI-E32-T5402-N, revision 4

" Main Steam Line Isolation i

Valve Leakage Control System.

i Inboard Pressure Channel E

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Calibration for 1E32-N051E" No violations or deviations were identified.

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Monthly Maintenance Observation (62703)

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Station maintenance activities of safety-related systems and components listed below were observed / reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides, industry codes i

or standards, and in conformance with technical specifications, j

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The following items were considered during this review:

the limiting

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conditions for operation were met while cc9ponents or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were

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inspected as applicable; functional testing and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and, fire prevention controls l

were implemented,

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Work requests were reviewed to determine status of outstanding jobs and to assure that priority was assigned to safety-related equipment l

maintenance which may affect system performance.

Thm following specific maintenance activities were observed:

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Work Order (WO)

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.i 90-3570 Replaced the calibration board, amplifier board,

and the 0-rings for the high pressure core spray.

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flow transmitter, IE22N056.

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90-3275-Replaced the local power range monitor (LPRM)

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' logic card for detector 24-41-A.

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l 90-3421 Obtained a chiller lubricating oil' sample,

]D corrected the chiller lubricating'. oil level, and reduced a refrigerant leak from an upper plug on the inspection cover for the

"C'.' control complex chiller, OP4/B001C.

90-3448 through Replaced the pins connecting the valve disc

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90-3451 shafts to the-thrust' collars in Containment

. Isolation Valves:

IM14-F190,,IM14-F195; i

1M14-F200, and 1M14-F205, respecti.vely.

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' pins that were removed were inspected as part

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of the followup action:for a 10 CFR 21-i notification.made by Arizona Public Service

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i 89-6120 In accordance with Field Change Request (FCR)

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10328, drilled indentations into the guide vane linkage of control complex chiller "C",

OP47B001C, to prevent loss of function due to guide vane slippage.

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89-7794 Performed periodic valve maintenance on scram valves and replaced the scram solenoid pilot valve for Hydraulic Control Unit 34-03.

Regarding WO 89-7794, control rod 34-03 failed its initial scram time retest, was fully inserted, hydraulically disarmed, and declared inoperable. WO 90-3628 was initiated to troubleshoot this retest failure and included the following steps:

inspection of scram inlet and outlet valves (EP-126 and EP-127); and replacement of the scram pilot

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valve (EP-139). WO 90-3634 disassembled the suspect scram solenoid pilot valve to determine the root cause of the initial scram

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time test failure during retest.

WO 90-3647 removed the single rod

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insertion (SRI) switches and tested them. At the end of this inspection period the licensee had not determined the specific root cause and had sent the solenoid pilot valve to the vendor (Automatic Switch Company (ASCO)) for further analysis.

When the control rod failed its scram time test during the initial retest, it exhibited a delay to position 43 that had been previously noted for control rods failing their scram time tests due to problems in the solenoid pilot valve.

The licensee concluded that the most likely root cause had

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been a failure in the replacement solenoid pilot valve.

Following the corrective actions and analysis as stated above, the licensee successfully tested control rod 34-03 and declared it operable.

The inspectors found that the licensee's root cause analysis had been thorough and the conclusions appeared reasonable.

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No violations or deviations were identified, 5.

Operational Safety Verification (71707)

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General 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 tagout records, and verified tracking of Limiting Conditions for Operation (LCO) associated with affected components. Tours of the intermediate, auxilf ary, reactor,

- and turbine buildings were conducted to observe plant ec,uipment conditions including potential fire hazards, fluid leaks, and excessive vibrations, and to verify that maintenance requests had been initiated for cetain pieces of equipment in need of maintenance. The inspe M rs, by observation and direct interview, verified that the physicai acurity plan was being implemented in accordance with the station se urity plan.

• The inspectors observed plant housekeeping / cleanliness conditions

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and verified implementation of radiation protection controls.

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Single Control Rod Inoperable On August 8,1990, the scram inlet valve (EP-126) for control rod

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(CR) 10-19 failed to open when both Single Rod Insertion (SRI)

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switches were taken to the " test" position.

The hydraulic control unit (HCU) for CR 10-19 had been isolated for planned maintenance.

Preliminary investigation by the licensee concluded that:

(1) the root cause was the inlet scram valve spring had been set with the incorrect preload; (2) the ability of CR 10-19, or any other control rod, to scram had not been prevented; and (3) this incorrect preload had not been responsible for any previous problems with CR 10-19 or any other control rod.

The corrective actions were:

(1) set the proper preload on the inlet scram valve spring for CR 10-19 and; (2) request the Maintenance Section to proceduralize the proper spring preloading process in a General Maintenance Instruction (GMI).

On August 10, CR 10-19 was declared operable.

The inspectors found that the licensee's investigation was thorough and the corrective activ were appropriate, c.

Failure to Verify Liquid Release Flowpath On August 17,-1990, during the performance of Surveillance Instruction (SVI)-G50-T5266, revision 2, " Liquid Radwaste Release Permit,'.' plant personnel noted that the discharge flow was 160 gallons per. minute (gpm) with the discharge throttle valve, 1G50F153, 86 percent open. This was not in accordance with SVI-G50-T5266, which indicated that a discharge throttle valve

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position of 100 percent was necessary to achieve 160 gpm.

The surveillance instruction was terminated before any release was made and subsequent investigation found that a new discharge

.flowrate versus discharge' throttle valve position graph was not generated after the turbine in the flowmeter was replaced on July 9, 1990.

. Liquid Radwaste Release Permit 90-115L was issued af ter the turbine

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replacement and it was found that'the throttle valve had been pasitioned at 83 percent open and the correct flowrate of.160 gpm had been achieved.

The licensee initiated Condition Report 90-203

o document their investigation of the failure to upgrade the SVI-following the hly 9 turbine replacement.

Th9 licensee identified that, with the liquid radwaste discharge flowe t y inoperable, the position-of the discharge throttle valve was not independently verified as -required by Technical Specification-

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Table 3.3.7.9-1, 3.a.1, Action 112. The licensee issued Licensee Event ' Report (LER)90-019, dated September 14, 1990, which detailed the above event. The inspectors'will review the licensee's root cause evaluation and corrective actions detailed in LER 90-019.

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The results of that review will be documented in a subsequent inspection report.

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Unaerestimation of Liquid Radwaste Disenarges During the investigation of Condition Report 90-203 discussed above, the licensee identified that liquid radwaste flowmeters installed between April 7,1987, and July 8,1990, had been calibrated incorrectly; therefore, the quantities of liquid discharges had been underestimated. Apparently engineering personnel failed to calculate calibration factors specific to the flowmeters installed

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between April 1987 and July 1990 and instead used the calibration factor calculated specifically for a flowneter installed in 1986.

The proper calibration factor was calculated for the flowmeter installed on July 8, 1990.

The licensi-determined that the maximum error appeared to be about 20 percent aonconservative.

The following is a listing of the liquid doses (in mrem) that had been previously calculated for the years in question:

Total Body Organ

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1986 3.54e-5 2.31e-5 1987 1.06e-4 3.55e-4 1988 1.52e-3 4.87e-3 1989 4.67e-2 8.18e-2 1990 3.00e-2 4.30e-2 (through 6/30/90)

If the above doses were increased by'20 percent, the Technical Specification dose limits of 3 mrem / year total body and 10 mrem / year i

organ would not have been exceeded.

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The licensee initiated Condition Report 90-205 to document their-investigation of this event.

The licensee issued LER 90-019 on-September'14, 1990, which detailed the above event.

The-inspectors will review the licensee's root.cause evaluation and corrective-

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actions detailed-in LER 90-019.

The results of that review will be documented in a subsequent inspection report.

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Isolation Valve Degradation f

On August 23, 1990, licensee personnel noted that elevated readings on a flowmeter and a pipe temperature meter indicated that there was seat leakage past the containment isolation valve and the

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maintenance isolation valve on the Inboard Main Steam Isolation Valve (MSIV) Leakage Control System drain line for the "B" main

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steam line.

Since these valves were motor-operated, Contro1~ Room Operators initially opened and closed the valves ~1n an attempt to obtain a tighter seal; however, the leakage was not reduced.

Licensee personnel considered the containment isolation function of these valves operable because they believed the total leakage through the "B" Main Steam Line was below the Technical

Specification 3.6.1.2.c limit of 25 standard' cubic feet per hour (scfh) at 11.31 psig, for the'following reasons:

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t (1) The pipe temperature indicator on the pipe had remained

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approximately constant (between 160 and 180 degress Fahrenheit)

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over the course of the morning.

The flow was onsctle for about 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> during the same time period. The licensee

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concluded that a leak of 40 scfh equated to a temperature of about 160 degrees.

(2) The last measured leakage for steamline "B" was 9.66 scfh at 11.31 psig. This allowed a leakage increase of 15.34 scfh

before exceeding the Technical Specification limit.

The licensee determined in Field Change Request 6227 that a leakage of 125 scfh at 920 psig corresponded to a leakage of 3 scfh at 11.31 psig. The licensee assumed negligible difference due to the reactor pressure being at 1020 psig and calculated by ratio that the leakage through the containment isolation valve must be 639 scfh before the Technical Specification limit would be exceeded.

(3) There had been no increase in the reading on the radiation monitor that was measuring the Reactor Building Annulus which

was where the leakage was being routed.

The licensee reasoned that-if the flow had increased by a factor of over 15 to go from 40 to 639 scfh then there would have been a significant

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readings.

The licensee concluded that since there was a lack of change in the above mentioned instruments during the periods when the flow indicator was unscale (less than or equal to

'40 scfh) and offscale, then it was reasonable to assume that the leakage had not increased to 15 times the full scale value.

The subject valves were located'in the steam tunnel and on August 23, i-h 1990, reactor power was reduced to about 65 percent and maintenance personnel entered the steam tunnel, torqued the valves, and manually

. seated the valves.

The inboard MSIV Leakage Control System (E32)

I was declared inoperable because of uncertainties that the motor operators would move the valves off their seats when the system was needed. Technical Specification 3.6.1.4-required that the

l inoperable subsystem be restored within 30 days or be in hot

shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

Reactor power was increased back to 94 percent after the leakage appeared to stop; but, power was again reduced to 80 percent.when

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the leakage started again. To be conservative, while leakage L

calculations were verified, the licensee closed the inboard MSIV on Main Steam Line "B" (1821-F22B). On August 25, after calculations had been verified and a temporary instruction (TXI-0111, "E32 Inboard-System E leakage Determination") issued,; the inboard MSIV was opened and reactor power was restored to 100 percent.

For As Low As Reasonably. Achievable (ALARA) considerations, the licensee decided not to attempt to manipulate or restore to operability the E32 valves until the refueling outage, which started September 7, 1990. The E32 Technical Specification Limiting Condition of Operation (LCO) time limit of 30 days allowed postponement of repairs until the scheduled outage.

Licensee personnel initiated Condition Report 90-207 to-y n

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document their internal investigation of this event. No reports to the NRC were required.

The inspectors found the licensee's actions, as discussed above, to be reasonable, f.

Plant Shutdown During this report period, the Perry plant was operated in a

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"coastdown" mode until the start of the second rehel outage on September 7.

Control room activities observed by the inspectors during the shutdown evolution were well controlled.

Of-particular note was the planned hold point during the shutdown (after the main

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generator output breaker was opened) at which tirre the shift relief occurred.

Shift turnover briefings were observed by the' inspectors to be comprehensive with ample time provided.

During the last 12 percent power reduction, a failure of the motor driven feedpump and increased vibration in the turbine driven feedpumps dictated that the plant shutdown be completed by a manual scram from about 10 percent reactor power.

In preparation for that planned evolution, the Shift Supervisor conducted a thorough i

briefing and directed additional licensed and non-licensed operators to be pre-staged at selected operating stations.

The inspectors

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noted that the manual scram evolution was performed well by plant

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operators which minimized the expected system transient.

Of particular note were the pre-scram briefing and discus, ions between control room personnel, the simultaneous use of required procedures, and verbal communication within the control room.

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Response to Equipment Failures As noted above, during the planned shutdown on September 7, the motor driven-feedpump failed.

In addition to tnat failure, two MSIVs failed to close on demand.

Following the reactor shutdown on September 7, plant operators

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attempted to " slow-close" all-MSIVs.

In accordance with procedural

. instructions, the MSIV test-switch was actuated to " slow-close" each

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MSIV individually. Once the MSIV indicated closed, its-control switch

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was taken to close and the test-switch was released.

Six of the eight MSIVs were " slow-closed" successful:1y; however, MSIVs 283 and 22C

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reopened, which indicated a-failure of the' associated ASCO solenrid valves to-properly position for valve closure.

The control switches for 28B and 22C were left in the close position and the' valves subsequently. closed.

After discussions with the NRC staff, licens'ee letter PY-CEI/0IE-0372L, dated September 11, 1990, outlined the licensee's planned activities to investigate the motor feedpump and MSIV failures.

At the conclusion of this report period, NRC specialist inspectors from Region III and NRR were on-site observing the licensee's troubleshooting effort.

The results of that inspection effort will be documented in NRC-maintenance team Inspection Report l

50-440/90-12.

.No violations _ or deviations were identified.

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Onsite-Followup of Events at Operating power Reactors (93702)

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General The inspectors performed onsite followup activities for events which occurred during the inspection period.

Followup inspection included one or more of the following:

reviews of operating logs, procedures, and condition reports; direct observation of licensee actions; and

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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

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conditions; and verification of the nature of the event. Additionally, in some cases, the inspectors verified that licensee investigation had

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identified root causes of equipment malfunctions and/or personnel errors and were taking, or had taken, appropriate corrective actions.

t Details of the events and licensee corrective actions noted during i

the inspectors' followup are provided in Paragraph b. below.

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Details

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(1). Loss of Standby Liquid Control Safety Function On August 6, 1990, at about 2:45 p.m.(EDT), while the plant was at.100 percent reactor power, a loss of a safety system function i

was declared when both trains of the Standby Liquid Control (SLC)

System were considered inoperable due to.a late surveillance.

A quality assurance audit of the Inservice Inspection Program

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found that a flowmeter in the SLC system had not been calibrated since November 1986.

Instrumentation and Controls Administrative Procedure (IAP)-0501, revision 1, " Calibration / Loop Calibration Check Intervals for Plant Instruments," Section 6.2.1, required that instrumentation used;to satisfy Technical Specification surveillance requirements be calibrated at least once an operating cycle. The flowmeter (1C41-R700) was used to verify operability of the SLC system pumps as required ~by Technical Specification Surveillance Requirement 4.1.5.c every-3' months.

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The licensee notified the NRC Operations Center of this event

'i via the. Emergency Notification System (ENS) at about 5:15 p.m.,

within the.four hours required by 10 CFR 50.72.

A loss of safety-system function would have placed the plant in an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> shutdown L

Limiting Condition of 0peration (LCO) except that Technical

L Specification 4.0.5 allowed a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> LC0 for any late surveillance.

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Immediate corrective actions, included performing the surveillance tests on the SLC system pumps using a calibrated flow-meter installed by a Work Order. The pumps were declared operable within the appropriate time limits of the LC0 and the-flowmeter (1C41-R700) was determined to be within calibration.

There was an informational followup call via the ENS to the NRC Operations Center to state that both SLC system pumps had been

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F declared operable. The licensee documented their investigation of this event on Condition Report 90-187. The licensee determined that the root cause for this event was that the

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calibration requirement of the administrative procedure was a l

general statement. applicable to all Technical Specification i

associated instrumentation throughout the plant and had not i

documented the specific exception of the SLC system flowmeter.

The f,lowmeter was a type for which the licensee had a policy of

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not requiring calibration because these flowmeters were " simple" j

devices unlikely to drift out of calibration.

Since the

flowmeter was found to have been in calibration at all times, i

the licensee concluded that:

the SLC system pumps had been

operable; there had been no loss of safety system function; the l

notification to the NRC via the ENS was not required; and an event report was not required.

The corrective actions as stated in the investigation summary

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of Condition Report 90-187 were:

IAP-0501 was to be revised to

note exceptions of calibration frequencies.of greater than 18

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months; American Society of Mechanical Engineers (ASME) Code I

Section XI, requirement IWP-4000, will be referenced by IAP-0501

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to ensure future changes to the IAP will be in conformance with

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Code requirements; and Repetitive Task 90-1010 will perform a j

calibration check on the flowmeter on an 18 month frequency until

the IAP is revised. The actions and conclusions of the licensee appeared reasonable to the inspectors.

However, the inspectors

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requested the licensee to provide additional justification and a listing of instrumentation determined not to require periodic B

calibration.

This is considered an unresolved item

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(440/90018-01(DRP)).

il (2) Loss of Feedwater Heaters Causes Brief Power 'ncrease I

i On August 14, 1990,. at about 7:00 a.m. (EDT), while the plant was at 100 percent reactor power, Section 2.C,1 of the j

operating. license (which limits thermal power to.100 percent)

l was violated due to equipment failure. At about 3:30 p.m., the j

licensee notified the NRC Operations Center via the ENS (within

the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. time limit required by Section 2.F of the license)

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that they had determined that thermal power had exceeded 102 percent for about 101 seconds and had peaked at about q

104.4 percent,

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At about 7:00- a.m., the SA and 6A feedwater heaters isolated i

on high heater level due to a malfunction of normal level f

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controller drain valve N25-F340A for heater SA.

The loss of

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feedwater heating caused an expected increase in thermal power

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due to colder'feedwater temperature.

P.lant operators promptly i

lowered reactor power by reducing reactor recirculation flow in

accordance with Off Normal Instruction (ONI)-N36, revision 3,

" Loss of Feedwater Heating." A manual level controller was i

installed to replace the automatic level controller.

Since the automatic level controller was in an area of the plant with i

high radiation levels, the permanent repair of the automatic

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level controller was postponed until the second refueling outage, which began on September 7, 1990.

The licensee documented their investigation of this event in Condition Report 90-197.

In addition, LER 440/90-017 was issued on September 13, 1990.

The inspectors will review that LER during a future inspection period.

t (3) Loss of Control Room Ventilation Safety Function On August 31, 1990, while performing corrective maintenance on control room ventilation backdraf t damper 0M25-F510A, plant technicians cut through ventilation ductwork in order to eliminate mechanical interference. The work performed was contrary to the specific work order instructions (Work Order No. 90-4066); and, the cut-out ductwork (1" x 11") was

identified by the system engineer during the post maintenance testing activities.

The licensse initiated

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Condition Report (CR)90-217 to document the engineering review ofl system impact and to document the corrective actions.

The degraded ductwork was in the A-train of control room ventilation which had been declared inoperable when the original work order was initiated (due to binding in the

backdraftdamper).

However, the initial engineering evaluation of CR 90-217 concluded that the degraded ductwork also made the

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B-train of control room ventilation inoperable since the area of-concern was common to both trains. After receipt of the

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engineering. evaluation, plant operators declared the B-train of control room ventilation inoperable at 12:10 a.m. (EDT) on September 1, and entered Technical Specification 3.0.3.

While

.-making preparations to perform a plant shutdown, repair activities were initiated on the degraded ductwork. At about

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3:30 a.m...-repairs were completed and the B-train of control

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room ventilation was declared' operable,

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In order to complete repairs on the A-train under the original

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work order, the licersee determined that additional entries

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into Technical Specification 3.0.3 were required.

This was due j

to the location of the access manway being in a portion of ductwork that was common to both the A and B-trains.

After discussions with the NRC Region III staff, the licensee entered Technical Specification: 3.0.3 on two occasions on September 2 to' complete repairs to the A-train of control room ventilation.

x The inspectors noted that the causes for this event were maintenance personnel errors while performing corrective

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maintenance.

A combination of failure to follow written work i

. order instructions and inadequate-supervisory involvement led to the cutting of ductwork to remove interference.

lbwever, the inspectors also noted that the proper performance of post

meintenance test activities, while the subject ventilation train l

was still considered inoperable, provided a prompt identification cf the degraded condition. At the conclusion of the report l

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period the licensee had not completed their root cause investigation of this event.

Additionally, an important aspect of this event is that a single failure caused a loss of redundant systems.

The licensee is reviewing this aspect. The inspectors will review this event further in a future inspection report.

As noted above, the licensee identified that the degraded ductwork in the A-train of the control room ventilation system affected the safety function for the control room emergency recirculation system. While the licensee complied with the provisions of Technical Specification 3.0.3, a notification to the NRC was not made until about 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> after the degraded condition was identified.

10 CFR 50.72(b)(2) required that the licensee notify the NRC as soco as practical, and in all cases within four hours, of the occurrence of any event or condition that alotis could have prevented the fulfillment of the safety function of net &d structures or systems.

Failure of the licensee to notify the NRC within four hours af ter identification at 12:10 a.m. on September 1 that both trains of the control room emergency recirculation system were inoperable is a violation (440/90018-02(DRP)).

'The inspectors noted that the licensee's failure to notify the NRC of. the subject safety function loss within four hours has been a repetitive problem.

Inspection Report 50-4a0/90005, paragraph 11.b.(5), discussed the licensee's failure to report the loss of the same safety function (reference noncited violation 440/90005-04). In addition, the licensee was issued a notice of violation (440/89015-03) in November 1988 for

. failure to report a similar loss of the same safety function.

Therefore, the inspectors concluded that the violation was repetitive and issuance of a notice of violation was warranted.

(4) Main Steam Isolation Valve Failure to Close On September 7,1990, while in Operational Condition 3 " HOT SHUTDOWN," two main steam isolation valves (MSIVs) failed to.

-close on demand. As discussed in paragraph 5 9 of this inspection report, MSIVs 288-and 22C failed to remain closed af ter the licensee had " slow-closed" all MSIVs during a planned shutdown evolution.

The initial valve re'sponses were indicative of a failure of the dual ASCO closure solenoids-At

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the conclusion of this report period, the licensee was still investigating the cause for the MSIVs failure to close on demand.

The inspectors and Region III specialists will review the licensee's root cause determination following completion of the on going investigation.

The licensee notified the NRC Operations Center of this event via the ENS at about 9:00 a.m. (EDT) and within the four-hours required by 10 CFR 50.72.

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(5) _ Reactor Water Cleanup Isolation On September 7, 1990, while in Operational Condition 3, " HOT SHUTDOWN," unexpected isolations of the reactor water cleanup system occurred on two separate occasions.

The first isolation occurred at about 6:30 a.m. (EDT), shortly af ter a-plant shutdown and was initiated on a high differential-flow signal.

P_lant operators verified an actual system leak had not occurred and the system was subsequently returned to service.

The second isolation occurred at about 2:30 p.m., and was again initiated on a high differential flow signal. After verification

that an actual leak in the reactor water cleanup system was not present. plant operators restored the system to service.

Both of the event occurrences were attributed to the low feedwater conditions while in HOT $4UTDOWN.

The licensee notified the NRC Operations Center-of these events at about 9:00 a.m. and 3:00 p.m., respectively, on September 7, within the four hours required by 10 CFR 50.72.

(6) Engineered Safety Feature Actuation Due to Loss of RPS Bus On September 7, 1990, while in Operational Condition 3, "H0T-SHUTDOWN," an unexpected engineered safety feature actuation occurred due to a loss of reactor protection system (RPS)

electrical bus "A".

During the' performance of Surveillance Instruction (SVI)

C71-T5230, revision 4, " Reactor Protection System - Electrical i

Power Monitoring Calibration / Functional for-1C71-S003A and J

1C71-S003C," plant technicians and operators performed the SVI on the wrong component (IC71-S003G vs. 1C71-5003C):

The actions performed on the wrong component resulted in a loss of power to RPS bus "A", a half scram signal, and outtward valve group isolations.

Immediate actions were performed by control room personnel in accordance with Off-Normal Instruction (ONI) C71-2 to restore power to the affected RPS bus and restore plant systems to the required conditions.

Initial investigation for this event indicated a combination a

L of. personnel error and component labeling to be causal factors.

The licensee took immediate action to improve component labeling; however, the inspectors concluded adequate labeling was present and was typical-of labeling throughout the Perry plant.

The, inspectors will review the licensee's root cause investigation and additional corrective actions for this event after receipt of the LER required by 10 CFR-50.73.

The results of-that review will be documented in.. 4 0 inspection

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report.

The licensee notified the WC Operations Center of this event at about 10:00 p.m.'on September 7, within the four hours required by 10 CFR 50.72.

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(7) ESF Actuation Due to unexpected Valve Closure At about 8:30 a.m. (EDT) on September 15, 1990, while in Operational Condition 5, COLD SHUTDOWN, the licensee identified four containment isolation valves closed that were believed to have been open prior to the event.

Based on three previous surveillance valve lineups, which verified containment isolation valves B21-F067A, B, C, and D were open, the licensee initially concluded that the as-found closed condition was only explained by an unexpected isolation signal.

However, the licensee's=

initial investigation indicated that wrong assumptions were made by personnel performing surveillance valve lineups; and, in fact, the subject valves may have been closed since the plant shutdown on September 7.

The licensee initiated Condition Report 90-245todocumenttheirinvestigationintothis-event, The inspectors will review the licensee s root cause determination and corrective actions following completion of i

that investigation'

This is considered an Unresolved Item

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(440/90018-03(DRP)) pending the inspectors review.

The licensee reported this event to the NRC Operations Center via the ENS at about 12:15 p.m. on September 15, within the four hours required _by 10 CFR 50,72, i

(8) Main Steam Line Leakage _ Exceeds Allowable

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On September 16 and 17, 1990, while in Operational Condition 5,

" COLD SHUTOOWN," the licensee identified, through required leak-rate testing, that main steam lines A, B, C, and D exceeded the o

Technical Specification limit of 25 standard cubic feet per

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hour (scfh) leakage when tested at 11.31 psig,

.The licensee reported-this event to the NRC Operations Center-via the ENS within the four hours required by 10 CFR 50.72 for each identified leakage failure.

Immediate actions included

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further testing to quantify leakage and leakage paths. The licensee was still preparing planned corrective actions at the l

conclusion of this report period.

The inspectors and Region III specialists will review the licensee's root cause investigation and corrective actions-following issuance of the required LER

for_this event.

The results of that review will be documented i

in a future inspection report, One violation and two unresolved items were identified.

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Plant Status Meeting and Commissioner Visit (30702)

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NRC Management and Commissioner Rogers met with Cleveland Electric

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Illuminating' Company management on August 7,1990, at the Perry plant, in order to discuss the current status of monthly performance indicators, training and requalification programs, maintenance programs, and Perry issues and initiatives.

Personnel in attendance at that meeting are designated by (#) in paragraph 1 of this report.

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The licensee discussed the results of a recent management audit and subsequent organizational changes.

The licensee's discussion of plant-performance included the recent operating history, personnel exposure i

controls, and planned activities for their second refuel outage. The licensee then discussed the operations training and qualification programs and the status of plant specific simulator upgrades.

In addition, the licensee presented an overview of their maintenance program, including predictive, preventive, and corrective maintenance activities.

The Perry plant specific issues discussed included the scram reduction program, Technical Specification improvements, individual plant examination, and control of zebra mussel infestation.

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NRC management acknowledged the licensee's plans and current plant status 8.

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. Unresolved items are identified in Paragraphs 6.b.(1) and 6.b.(7).

9.

Exit Interviews '(30703)

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The inspectors metLwith the licensee representatives denoted in paragraph 1 throughout the inspection period and on September 19, 1990, i

The inspector summarized the scope and results of the inspection and discussed the likely content of the inspection report. The licensee did not indicate that any of the information disclosed during the inspection could be considered proprietary in nature.

During the report period, the inspectors attended the following exit

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interview:

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Inspector Exit Date

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J, House 7/13/90

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