IR 05000334/1986020

Insp Rept 50-334/86-20 on 860828-0930.No Violations Identified.Major Areas Inspected:Plant Operations,Fire Protection,Housekeeping,Radiological Controls,Physical Security,Surveillance Testing & Plant Mgt Changes

ML20211C992
Person / Time
Site:	Beaver Valley
Issue date:	10/09/1986
From:	Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20211C971	List: IR 05000334/1986020 ML20211C966
References
50-334-86-20, NUDOCS 8610220073
Download: ML20211C992 (15)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Report N /86-20 Docket N Licensee: Duquesne Light ' Company One Oxford Center 301 Grant Street Pittsburgh, PA 15279 Facility Name: Beaver Valley Power Station, Unit 1 Location: Shippingport, Pennsylvania Dates: August 28 - September 30, 1986 Inspectors: W. M. Troskoski, Senior Resident Inspector A. A. Asars, Resident Inspector L. J. Prividy, Resident Inspector, BVPS Unit 2  ;

D. F. Li roth, Project Engineer, DRP 3A Approved by: .I 4tip /9 fd9l$

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L. E. TriU5, Chief, Reactor Projects Section 3A ' Uate Inspection Summary: Inspection No. 50-334/86-20 on August 28 - September 30,1986 Areas Inspected: Routine inspections by the resident inspectors (131 hours0.00152 days <br />0.0364 hours <br />2.166005e-4 weeks <br />4.98455e-5 months <br />) of licensee actions on previous inspection findings, plant operations, housekeeping, fire protection, radiological controls, physical security, surveillance testing, RCS flow setpoints, overpressure protection system, plant management changes and LER review Results: No violations were identified. Significant items reviewed included: a full power trip due to personnel error while testing the Solid State Protection System (Detail 4.b.1), equipment failure concerning the No. 3 inverter (Detail 4.b.2); concerns related to RCS flow measurement (Detail 6); and PORV stroke times inconsistent with those assumed in the safety analysis for a low temperature, overpressure type accident (Detail 7).

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TABLE OF CONTENTS P,afte Persons Contacted.................................................... 1 Plant Status......................................................... 1 Followup on Outstanding Items........................................ 1 Plant Operations..................................................... -3 Genera 1......................................................... 3 Operations...................................................... 4 Plant Security / Physical Protection.............................. 6 Radiation Controls.............................................. 7 Plant Housekeeping and Fire Protection.......................... 8 Surveillance Testing................................................. 8 6. . Reactor Coolant System F10w.......................................... 10 Overpressure Protection System....................................... 11 8. .Inoffice Review of Licensee Event Reports (LERs)..................... 12 Exit Interview....................................................... 13

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DETAILS Persons Contacted During the report period, interviews and discussions were conducted with members of licensee management and staff as necessary to support inspection activitie . Plant Status The plant completed its ascension to 100% power on September 3, 1986, and operated at full power throughout the inspection period with the exception of one trip (discussed in detail 4.b) on September 3, 1986. There was a planned shutdown period from September 12 - 14, 1986, to accomplish repairs in the main feedwater system (see detail 4.b), and a planned power reduction to 95% on October 1, 1986, to perform maintenance on a cooling tower pum On August 19, 1986, a reorganization of the DLC Nuclear Group was announce Mr. J. J. Carey was elected to the position of Senior Vice President - Nuclear Group, with QA, Nuclear Operations and the BV-2 project groups reporting directly to him. Mr. J. D. Sieber was elected Vice-President of Nuclear Operations, with primary responsibility for Unit . Followup on Outstanding Items The NRC Outstanding Items (OI) List was reviewed with cognizant licensee per-sonnel. Items selected by the inspector were subsequently reviewed through discussions with licensee personnel, documentation reviews and field inspec-tion to determine whether licensee actions specified in the OIs had been satisfactorily completed. The overall status of previously identified in-spection findings were reviewed, and planned and completed licensee actions were discussed for those items reported below:

(0 pen) Violation (86-11-02): Inadequate post-modification testing of Backup Indicating Panel (BIP) to assure it would perform its intended design func-tions. Specifically, a complete functional test was not performed on the RCS cold leg temperature indicators and therefore, did not identify that the in-

! struments were wired incorrectly, and no test was conducted to ensure that I the keys provided for the BIP locking transfer switches would work. Immediate corrective action consisted of making the necessary wiring changes on the temperature indicators and permanently attaching the correct keys for the BIP l

transfer switches to the Appendix R key rings. After these actions were com-plete, OST 1.45.9, BIP Instrumentation and Source Range Indication Test, was performed successfully. By letter dated August 8, 1986, the licensee stated

! that Nuclear Engineering and Construction Unit Management Procedure 2.7, En-l

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gineering Specifications, would be revised to clearly establish a minimum re-quirement for design change test specifications. This item remains open pending inspector review of Procedure 2.7, i

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. 2 (0 pen) Unresolved Item (85-11-01): Successful completion of OST 1.33.10, C0-2 Fire Protection System Test and licensee evaluation of current fire damper maintenance to determine need for a preventive maintenance program. The in-spector reviewed the completed OST 1.33.10, which was performed on August 19, 198 Partial performance of the OST was to verify damper actuation in the cable mezzanine and both EDG room The test was satisfactory in that all dampers actuated as designate However, this item will remain open pending licensee evaluation of the need for a fire damper preventive maintenance pro-gram. Further description of recent problems with fire damper operability is contained in NRC Inspection Report 334/86-15, detail 4. (Closed) Inspector Follow Item (86-01-02): Revision of incorrect river water levels in TAB 23 of EPP Implementing Procedures. Earlier, the inspector had identified a discrepancy between the EPP/IP matrix and the corresponding TAB

'for classification of the emergency condition in the event of the Ohio River flooding. Revision 7 to the EPP/IPs has been issued and the inspector veri-fied that the correct river water levels are contained in TAB 2 (Closed) Violation (85-02-01): Completion of OST 1.11.16, Leakage Testing of RCS Pressure Isolation Valves, and licensee evaluation of questionable data gathered by OST 1.11.4, Accumulator Check Valve Testing. This item was last updated in NRC Inspection Report 334/86-07. OST 1.11.4 was previously per-formed on May 17, 1986, with questionable results. The licensee reperformed it on August 14, 1986. During this run of the test, the check valves on al three accumulators were found to have no leakag ,

(Closed) IFI (86-04-04): Follow inspection and repair of steam generator safety valves that are showing signs of steam leakage. During the SR outage, the licensee conducted mechanical maintenance on TV-MS-105A and B. After'

startup, the inspector observed the safety valve tail pipes and noted that the corrective maintenance efforts were effective in eliminating the leakage.

This item is close (Closed) IFI (86-04-03): Review balance of plant QC Program regarding preven-

, tion of foreign material addition at critical secondary system locations.

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The inspector was informed by the licensee that for critical secondary valves opened during the SR outage, inspections were conducted both upstream and downstream to identify any potential loose part On all major valves in the Turbine Plant that were opened, a maintenance foreman performed loose parts searches before valve reassembly. The inspector determined that this practice should reduce the possibility of foreign material introduction. This item is close (Closed) Violation (86-08-01): Failure to adhere to electrical separation criteri A June 6, 1986, inspection found redundant chassis circuit cables located in the reactor trip breaker control wiring cubicles that were not separated by a fire retardant barrier or a maintained air space of 6". In the DLC August 27, 1986, response, the licensee committed to a 1" minimum separation that would be reflected in a future update to the BV-1 FSAR, Sec-tion 8. The basis for the 1" free air space was provided in " Test Report

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on Electrical Separation Verification Testing for Duquesne Light Companies BVPS No. 2" which was reviewed and accepted by NRR Technical Reviewers (see NUREG-1057, SER for BV-2). The' inspector had no further technical concern and this item is close (Closed) Unresolved Item (85-06-05): Review licensee action to reduce backlog

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of mechanical MWR At Beaver, Valley, MWRs are not used just to track deft-ciencies but also for accounting, budgetary and work control practices. The number of outstanding MWRs do,es not provide a true performance indicator as there is no segregation between nice-to-do items and station operability and Discussions with the Maintenance Supervisor indicated that

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priority item most of the outstanding MWRs are not related to plant performance issue Additionally, the station is currently moving to revamp the system to conform

, with INPO recommendations for tracking performance indicators. Since the licensee is in.the process of revamping their system to' provide more meaning-

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ful inforsation, this opeh item serves no purpose and is therefore close . Plant Operations Generdl Inspection tours of the plant areas listed below were conducted during i

both day and night shifts with respect to Technical Specification (TS)

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compliance, housekeeping and cleanliness, fire protection, radiation control, physical security and plant protection, operational and main-

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administrative controls.

-- Control Room -

-- Primary Auxiliary Building

-- Turbine Building

'-- Service Building

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-- Main Intake Structure

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-- Main Steam Valve Room

-- Purge Duct Room '

-- East / West Cable Vaults

-- Emergency Diesel Generator Rooms

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-- Containment Building

-- Penetration Areas

-- Safeguards Areas

-- Various Switchgear Rooms / Cable Spreading Room Protected Areas l Acceptance critoria for-the above areas included the following:

-- BVPS FSAR

-- Technical Specifications (TS)

-- BVPS Operatt.ng Manual (OH), Chapter 48, Conduct of Operations

-- OM 1.48.5, Section D, Jumpers and Lifted Leads i -- OM 1.48.6, Clearance Procedures

-- OM 1.48.8, Records

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-- OM 1.48.9, Rules of Practice

-- OM Chapter 55A, Periodic Checks, Operating Surveillance Tests

-- BVPS Maintenance Manual (MM), Chapter 1, Conduct of Maintenance

-- BVPS Radcon Manual (RCM)

-- 10 CFR 50.54(k), Control Room Manning Requirements

-- BVPS Site / Station Administrative Procedures (SAP)

-- BVPS Physical Security Plan (PSP)

-- Inspector Judgement b. Operations Inspection tours of all accessible plant areas were conducted. During the course of the inspection, discussions were conducted with operators concerning knowledge of recent char.ges to procedures, facility configura-tion and plant conditions. The inspector verified adherence to approved procedures for ongoing activities observed. Shift turnovers were wit-nessed and staffing requirements confirmed. Except where noted below, the inspector comments or questions resulting from these daily reviews were acceptably resolved by licensee personne (1) A reactor trip occurred from full power at 6:30 a.m. on September 3, 1986, due to personnel error during testing of the Train B solid state protection system in accordance with MSP 1.0 This MSP had been revised to include additional steps as a result of the shunt trip panel equipment installed per Design Change Package No. 622

" Automatic Actuation of the Reactor Trip Breaker Shunt Trip Coil."

During one of these new procedure steps, the I&C technician incor-rectly tripped the Train A reactor trip breaker by operating the shunt trip panel push button. A reactor trip occurred. It appears that the revised procedure was not clear to the I&C technician as a result of the added steps to accommodate the shunt trip panel equipmen The licensee plans to again revise MSP 1.05 to remove these added steps and to test the automatic feature of the shunt trip coil by a separate procedure. Review of licensee action to modify and clarify procedures to preclude recurrence is Unresolved Item (86-20-01). The reactor was restarted at about 7:00 p.m. on September 3, 1986, and taken to full power. The inspector observed the reactor and plant startup and no adverse conditions were note (2) On September 5, 1986, at approximately 11:50 a.m., the inspector was in the control room and observed the actions of the operators in response to a loss of power to the No. 3 vital bus. Numerous annunciator alarms and indications occurred. The shift supervisor and the control room operators recognized almost immediately that the cause of the problem was the loss of the No. 3 vital bus in-verte It was confirmed later that the No. 3 inverter main power fuse had blow The plant operator immediately switched the SG feedwater regulating valves from automatic to manual since the SG water level control signals are fed from No. 3 vital bus. A startup operator was directed to restore power to the No. 3 vital bus from

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the auxiliary. power source by placing the power transfer switch at the No. 3 vital bus distribution panel into the Auxiliary positio Power was restored in approximately one minute, and the SG feedwater regulating valves were returned to automatic. Other affected con-

, trols and alarms;were reset and returned to normal. By 11: 55 a.m. ,

the plant,,was stable. A Unit Off Normal Report was issued to alert

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other operating personnel about the matte For the balance of the inspection period, the licensee powered the No. 3 vital bus from its auxiliary source. The licensee's efforts

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in determining the root cause of the problem with the No. 3 inverter were inconclusive. After replacing the blown power fuse for the inverter, a' dummy electrical load was connected to it to check performanc No similar blown fuses occurred.

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Problems with the blown power fuse for the No. 3 inverter have been reported in previous inspections (see detail 4 b(2).of Inspection Report 50-334/86-04). It was thought that the root cause of th inverter problem was a loose connection between the ground strap and the ground bus bar which was causing arcing. These loose con-nections had been tightened. However, now it appears that the root cause of the blown fuse problem with the No. 3 inverter is still unknown. Determination of the cause of this condition and licensee action to prevent recurrence is Unresolved Item (86-20-02).

At the end of the inspection period (September 30, 1986), the opera-tion of the No. 4 inverter became suspect when it was reported that

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the " Phase Locked" indicating light on the front of the. inverter

panel intermittently flashed off and on. The licensee switched the

! No. 4 vital bus to its auxiliary po'wer source and it remained in this condition until the end of tha inspection period when it was returned to normal. Determination of the cause of the problem for the No. 4 inverter and the licensee's corrective action will be reviewed in a subsequent inspection.

The inspector was advised by the licensee that arrangements had been made with an equipment specialist to assist in solving the inverter problem He was expected to be on site the week of October 6,198 (3) A scheduled shutdown took place at 8:00 p.m. , on September 12, 1986, to accomplish repairs in the feedwater system. The inspector ob-served the plant shutdown which occurred without inciden The major repair items were a leaking body-to-bonnet seal ring on the

"A" feedwater isolation valve and a spring on the "B" feedwater regulating valv These repairs were made as planned and the plant was brought back to power on September 14, 198 I

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(4) While in the control room on September 25, 1986, the inspector ob-served the response of the operators to an anomaly in the Reactor Plant Component Cooling Water System (CCR System). At 8:26 a.m.,

the reactor operator acknowledged a CCR Pump discharge pressure low alar Simultaneously, it was noted that the CCR surge tank level rapidly decreased from 46" to 34". Operators immediately began to isolate CCR flow to all non-essential loads. CCR pressure and surge tank level' stabilized. The operators then selectively unisolated individual loads to pinpoint the problem area. It was determined that the problem was due to a large flow of relatively cold coolant to the Boron Recovery System Evaporator Bottoms Cooler (1BR-E-3)

which is a heat exchanger served by the CCR System. This large flow of relatively cold coolant occurred when 1BR-E-3 was started up after having been isolated, thereby quenching 1BR-E-3 and causing the transient in the CCR System (reduced pressure and surge tank level). The inspector observed the actions of the operators as they attempted to determine the cause of the anomaly. The operators used A0P-20 " Loss of CCR" and annunciator response for guidance during the transient. During this abnormal situation, operators were dis-patched to the Auxiliary Building to check for leaks and to makeup the surge tank. Approximately 210 gallons were added to the surge tank. Normal conditions were established and the CCR System was considered stable at about 9:30 a.m. A Unit Off Normal Report was issued to alert other operating personne c. Plant Security / Physical Protection Implementation of the Physical Security Plan was observed in various plant areas with regard to the following:

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Protected area barriers were not degraded;

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Isolation zones were clear;

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Persons and packages were checked prior to allowing entry into the Protected Area;

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Vehicles were properly searched and vehicle access to the Protected Area was in accordance with approved procedures;

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Security access controls to Vital Areas were being maintained and that persons in Vital Areas were properly authorized;

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Security posts were adequately staffed and equipped, security per-sonnel were alert and knowledgeable regarding position requirements, and that written procedures were available; and

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Adequate lighting was maintaine .

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A bomb threat was received on September 5, 1986, at approximately 12:00 noon that affected Units 1 and 2. The Unit 2 switchboard operator re-ceived a telephone call stating that a bomb was planted in the fuel building. The caller did not indicate a specific time for detonation or which fuel building was involved. Unit 1 and 2 response team person-nel immediately evacuated both fuel buildings and conducted searche No bomb was foun At about 8:20 a.m. on September 30, 1986, a security supervisor discovered a breach in the protected area fence where construction personnel were working in a pipe trench. The breach was large enough for an individual to crawl under the fence. The detection devices were inoperable at the time due to the work in the locality. The only compensatory measure available was a watchman stationed on the Unit 2 Control Room less than 100 yards away from the trench. The watchman had a clear view of the area and the trench was within his assigned section. According to the licensee, no one entered or egressed through the trenc Construction personnel from Unit 2 had been working off and on in this trench for the past several days. When the work reached the protected area fence, a temporary metal plate (about 1,000 pounds which had to be installed and removed daily by use of a crane) was used. The construc-tion forces were instructed to notify Security daily prior to start of work so that a permanent guard could be stationed in-the area. This had been done for several days but it was neglected on September 30, 198 The amount of time that the opening was unattended by Security personnel was estimated to be less than 25 minutes, since a Security Supervisor had inspected the site at 7:55 a.m. that mornin The inspector discussed corrective actions with DLC Unit 2 personnel, S&W Project Management, and the Site Construction Manager. The inspector was informed that Site Directives would be issued to clearly require the presence of Unit 1 Security prior to the start of any work that could impact the integrity of the plant boundary. No such work would be al-lowed until a guard was posted. These actions appear acceptable, and the inspector had no further concern d. Radiation Controls Radiation controls, including posting of radiation areas, the conditions of step-off pads, disposal of protective clothing, completion of Radi-ation Work Permits, compliance with the conditions of the Radiation Work Permits, personnel monitoring devices being worn, cleanliness of work areas, radiation control job coverage, area monitor operability (portable

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and permanent), area monitor calibration and personnel frisking proce-dures were observed on a sampling basi No discrepancies were identifie .

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8 Plant Housekeeping and Fire Protection Plant housekeeping conditions including general cleanliness conditions and control of material to prevent fire hazards were observed in various areas during plant tours. Maintenance of fire barriers, fire barrier penetrations, and verification of posted fire watches in these areas were also observe No discrepancies were identifie . Surveillance Testing To ascertain that. surveillance of safety related systems or components is being conducted in accordance with license requirements, the inspector observed portions of selected tests to verify that:

(1) The surveillance test procedure conforms to technical. specification requirement (2) Required administrative approvals and tagouts are obtained before initiating ~the tes (3) Testing .is being accomp'.ished by qualified personnel in.accordance with an approved test procedur (4) Required test instrumentation is calibrate (5) LCOs are me (6) The test data are accurate and complete. Selected test result data was independently reviewed to verify accurac (7) The test provides for independent verification of system restoratio (8) Test results meet. technical specification requirements and test discrepancies are rectifie (9) The surveillance test was completed at the required frequenc The inspector observed portions of the following tests:

-- MSP 1.05 - Solid State Pr'tection o System, Train B, Functional Tes OST 1.11.1 - Safety Injection Pump Tes Comments pertinent to MSP 1.05 are included in detail 4.b.(1) of this repor The inspector identified no other concern .

. 9 Review IndicationofSystem Surveillance Testing for Rod Control and Rod Position The inspector conducted a review of the various operational surveillance tests (OSTs)

Indication conducted pertinent to the Rod Control and Rod Position System This review consisted of the inspector observing operator action in performing the OST in some cases and in reviewing the

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test results for all the listed OSTs. The inspector noted if the OST results met technical specification requirements. The following OSTs were included in this review and were performed satisfactorily:

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OST 1.1.1 - Control Rod Assembly Partial Movement Test - This test was conducted satisfactorily on 4/21/8 OST 1.1.13 - Channel Check of Group Demand Counters Within a Bank and Overlap Verification - This test was conducted satisfactorily on 5/17/86 and 8/26/8 It is required to be performed during startup and shutdow The inspector observed the reactor operators performing this channel check during the reactor startup on 8/26/8 OST.1.1.14 - Inter-Comparison Between Control Bank Benchboard Indi-cators and Logic Cabinet Indicator - This test was conducted satis-factorily on 8/24/86 in conjunction with Test Procedure BVT 1.6-2.2.1 " Initial Approach to Criticality after Refueling". The in-spector observed the performance of this test by test personnel and operators as data was recorded from the group demand counters in the logicControl Room and from the indicators in the Rod Control System cabine OST 1.1.15 - Operability Check of Group Demand Counters - This test was conducted satisfactorily on 8/14/8 In addition to the above review of OSTs, the inspector discussed the results of the-rod drop tests with licensee personnel. These tests were performed in accordance with BVT 1.1 - 1.1.1 in Mode 3 at normal operat-ing temperature, after refueling. pressure and flow prior to the . initial reactor startup The inspector observed the visicorder trace of one rod which was used to determine rod drop times. .The drop out signal for the visicorder trace is taken from the stationary gripper coil voltage and

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the bottoming signal is taken as the point of dashpot entry. All drop out times were acceptable and were less than 2.0 seconds (Technical Specification value less than or equal to 2.2 seconds). On September 25, 1986, at approximately 6:30 a.m., while in Mode 1, the licensee was conducting the scheduled monthly operational surveillance test (OST 1.13.1) on the 1A Quench Spray Pump (QS-P-1A). This test re-quires that the pump be run for at least 30 minute minutes of operation, the pump automatically tripped due to an elec-After appro trical overload condition. The licensee declared QS-P-1A inoperable which invokes the action statement of TS 3.6.2.1. This requires that

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the pump be restored to operable status in 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or to shutdown the

,- reactor. The licensee suspected that.the problem was a defective breake A Maintenance Work Request was written to replace the defective breaker with a spare breaker. This work was completed and OST 1.13.1 was then performed satisfactorily at approximately 12:40 p.m. on September 25, 1986. While performing OST 1.13.1, electricians monitored the running current at the breaker and the current values were considered norma Vibration data recorded locally at the pump.was also normal. Other data (e.g., pressure, flow) and.information were reviewed and considered satisfactory and QS-P-1A was restored to an operable status at approxi-i mately 2:00 p.m. on September 25, 198 The inspector determined from the Director of Maintenance that bench i testing of the defective breaker by maintenance personnel has produced similar unsatisfactory performance - i.e. ,- the breaker initially closes but trips after about five minute The licensee has not yet isolated the defective part in the breaker, a GE Model AK-3A-25 600 V fram Determination of the cause of this breaker problem will be reviewed in -

a subsequent inspectio . Reactor Coolant System Flow The inspector reviewed Unit Off Normal Report 86-152 which was issued on September 17, 1986, to document an out of-spec condition for the reactor trip setpoint of RCS flow transmitter FT-RC 414. This is one of three flow trans-mitters for the A Loop which are used for the two out of three logic to de-velop a reactor trip signal.if RCS flow decreases below 90%. . Technical

, Specification Table 2.2-1, Reactor Trip System Instrumentation Trip Setpoints,

requires that loss of flow protection be provided by requiring this trip when flow decreases to 89% of the design flow per loop. A footnote defines the design flow as 88,500 gpm per loop (for a total flow of 265,500 gpm).

I&C became aware of the out-of-spec condition at 4:00 p.m. on September 17, 1986,-after rtvinw of BVT 1.3 - 1.6.1, RCS Flow Measurement Test, performed on September 11, 1986. This BVT accurulated flow data for I&C oven though it was unrelated to the tes This data (in the form of voltage readings)'

indicated that FT-RC 414 had a~ higher than previous 100% loop flow indication which when coupled with the existing trip setting produced an as-found reactor trip setpoint value of 87.5% flow. This is below the 89% allowable value *

limit specified in Table 2.2- The other two channels in.the A Loop and all other channels for the B and C Loops were within specification. Upon identi-fication of the problem, I&C notified tt.e Shift Supervisor and placed the applicable channel in its tripped condition within one hour per TS 3.3. MSP 6.03, F-414 Reactor Coolant Flow Loop 1 Protection. Channel 1 Test, was modified to adjust the reactor trip setpoint based on the new value for 100%

loop flow. The new setpoint was 3.377 plus or minus 0.020 vdc compared to the old setpoint which was 3.250 plus or minus.0.020 vdc. The channel was

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During review of BVT 1.3 - 1.6.1, the inspector identified several apparent anomalie This procedure is run once per 18 months in accordance with TS 4.2.5.2, to verify that various DNB parameters are within the design envelop Specifically, the reactor coolant system total flow rate for three-loop operation is required to be greater than or equal to 265,500 gpm with RCS T-average less than or equal to 581 F and pressurizer pressure at greater than or equal to 2,220 psia. The results of the test identified a total flow rate of 277,871 gpm. Though this was greater than the TS acceptance criteria, the inspector noted that both Loop A and Loop C had approximately 87,000 gpm each while. Loop B had 103,000 gp The inspector questioned the magnitude of this discrepanc The loop flow rates were obtained by performing a primary plant calometric while at steady state full power conditions. The inspector noted that from the.calometric data, Loop B T-Hot indicated about 604 to 605 F while the A Loop indicated about 613 F and the C Loop indicated 611 F. This test proce-dure did not specify acceptable ranges for the various parameters measured nor did it appear to account for instrument inaccuracies. Since both the core design document and Table 2.2-1 specify an RCS total flow rate of greater than or equal to 265,500 gpm, the inspector questioned whether or not the measure-ment uncertainty was built into this number or whether it was assumed that-the various test procedures would account for them. Discussions with the-Plant Manager and Plant Performance and Testing Engineers indicated that the licensee would: (1) determine whether or not an acceptance range should be specified for each RCS Loop when performing BVT 1.3-1.6.1, (2) determine whether the instrument inaccuracies were built into the design acceptance criteria or whether the procedure would have to be revised to include instru-ment uncertainties, (3) determine why the B Loop T-Hot value differed signi-ficantly from the other two loops. Licensee action in this regard will be followed as Unresolved Item (86-20-03). Overpressure Protection System Technical Specification 3.4.9.3 requires that overpressure protection be pro-vided by two power operated relief valves (PORVs) with a nominal trip setpoint of less than or equal to 350 psig whenever the temperature of a non-isolated RCS cold leg is less than or equal to 275 F. The TS surveillance requirement only addresses stroking the operable PORV each time the plant enters Mode 5 (Cold Shutdown) unless tested within the preceding three months. OST 1.6.9, Placing Overpressure Protection Systems in Service, conducts that surveillance requirement verbati The inspector reviewed NRR Safety Evaluation Report dated April 4, 1983. This SER analyzed two cases for this particular type of accident: (1) a mass input ~

case and (2) a heat input case. The.most restrictive PORV opening time was identified as the mass input accident which would require valve opening within 2.5 second A review of MSP 6.68, Reactor Overpressure Protection PORV Set-point Functional Tests, indicated that the nominal trip setpoint of less than I

or equal to 350 psig was addressed but the stroke time value was not. The inspector reviewed the Station's ASME Valve Stroke Log for PCV-RC-455C and

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. 12 D (the~two PORVs used to provide protection against exceeding the 10 CFR 50, Appendix G limit during periods of RCS water solid operation). The maximum stroke time specified per the ASME Code for 455 C was 3.8 seconds. During the last two years, the stroke time ranged from 2.0 to_2.8 seconds, just ex-ceeding the SER assumption Valve 455 D had a maximum stroke time specified as 2.7 seconds by the ASME Code, though actual testing ranged from 1.8 to second The inspector questioned why this assumption had not been included in either the-TS or the Operating Surveillance Test. Discussions with licensee person-nel indicated that appropriate revisions would be made prior to cooling down to 275 F. The licensee is currently evaluating this concern to determine whether the plant operated in an unanalyzed_ condition and potential report-abilit Verification that the PORV stroke times are under 2.5 seconds during the next appropriate outage, will be followed as Unresolved Item (86-20-04).

The inspector brought this TS deficiency to the attention of the Lead NRR Technical- Reviewer as the Beaver Valley Technical Specifications were being used as the model for other plant . Inoffice Review of Licensee Event Reports (LERs)

The. inspector reviewed LERs submitted to the NRC:RI office to verify that the details of the event were clearly reported, including the accuracy of the description of'cause and adequacy of corrective action. The inspector deter-mined whether further information was required from the licensee, whether

_ generic implications were indicated, and whether the event warranted onsite followup. The following LERs were reviewed:

LER 86-09, Failure to Perform Surveillance Test Within the Required Frequenc LER 86-10, ESF Actuat. ion LER 86-11, Manual Reactor Trip When Four Control Rods Droppe LER 86-09 reported a missed ASME surveillance for the 1A fuel pool cooling pump, a non-technical specification system. Though it was performed within seven days of the plants return to normal operation (ASME XI - 1974 edition,.

Section IWP-3460(a)), it was outside the 1.25 limit of TS 4. The pump was operating'throughout this time period and passed its subsequent surveil-lance test. The inspector determined that reporting this item was conserva-tiv The Operations Supervisor indicated that the station still intends to keep all ASME components on a routine surveillance frequency throughout an outage when possible, and have all testing reinitiated prior to startu The inspector had no further concern LER 86-10 was discussed in detail.4.a.3 of Inspection Report 334/86-1 No further concerns were identifie LER 86-11 was discussed in detail 4.a.5 of Inspection Report 334/86-1 No further concens were identifie .

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9. Exit Interview Meetings were held with senior facility management periodically during the course of this inspection to discuss the inspection scope and findings. A sumary of inspection findings was further discussed with the licensee at the conclusion of the report period.