IR 05000334/1988011

Insp Repts 50-334/88-11 & 50-412/88-07 on 880216-0331.No Violations Noted.Major Areas Inspected:Licensee Actions on Previous Insp Findings,Plant Operations,Physical Security, Radiological Controls & Plant Housekeeping

ML20153G098
Person / Time
Site:	Beaver Valley
Issue date:	04/28/1988
From:	Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20153G089	List: IR 05000334/1988011 ML20153G085
References
50-334-88-11, 50-412-88-07, 50-412-88-7, NUDOCS 8805110137
Download: ML20153G098 (18)

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-V. S. NUCLEAR REGULATORY COMMISSION

REGION I

Report Nos.: 50-334/88-11 License Nos.: OPR-66 50-412/88-07 NPF-73 >

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Licensee:- Duquesne Light Company  ;

One Oxford Center '

301 Grant Street Pittsburgh, PA 15279 &

Facility Name: Beaver Valley Power Station, Units 1 and 2 '

Location: Shippingport, Pennsylvania Dates: Unit 1 and Unit 2: February 16, 1988 - March 31, 1988 .

Inspectors: J. E. Beall, Senior Resident Inspector S. M. Pindale, Resident Inspector Approved By: / zZrMe[ t 4 /29/d3 4Lowell E. Tri'p# Chief Date

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Reactor Projects Section No. 3A, DRP Inspection Summary: Combined Inspection Report No. 50-334/88-11 and~

50-412/88-07 - February 16, 1988 through March 31, 198 Areas Inspected: Routine inspections by the resident inspectors (247 hours0.00286 days <br />0.0686 hours <br />4.083995e-4 weeks <br />9.39835e-5 months <br />) '

of licensee actions on previous inspection findings, plant operations, physical security, radiological controls, plant housekeeping and fire protection,

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natural circulation cooldown, review of periodic and special reports, review of licensee event reports and maintenance and surveillance testin _Re sults: No violations were identified. One NRC open item was closed during this inspection. Two unresolved items were opened regarding Unit 1 and Unit-2 labeling of plant components (Section 4.2.5) and resolution of Unit 1 fi re protection / separation deficiencies (Section 4.5.3). Licensee weaknesses identified during the inspection included Unit I housekeeping (Section 4.5) and recently submitted licensee event reports (Section 8).

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gDR ADOCK 05000334 DCD

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TABLE OF CONTENTS Page 1. Persons Contacted. . . . . . . . . . . . . . . . . . . . . . . . 1 2. Summary of Facility Activities . . . . . . . . . . . . . . . .. 1 3. Followup on Outstanding Items (92701). . . . . . . . . . . . . . 1 4. Plant Operations . . . . . . . . . . . . . . . . . . . . . . . . 2 4.1 General (71710) . . . . . . . . . . . . . . . . . . . . . . 2 4.2 Operations (71707). . . . . . . . . . . . . . . . . . . . . 2 4.3 Plant Security / Physical Protection (71881). . . . . . . . . 9 4.4 Radiological Controls (71709) . . . . . . . . . . .... 10 4.5 Plant Housekeeping and Fire Protection (71707). . . . . . . 10 5. Natural Circulation Cooldown (25586) . . . . . . . . . . . . . . 12 6. Calibration Program. . ..................... 14 7. Review of Periodic and Special Reports (90713) . . . . . . . . . 14 8. Inoffice Review of Licensee Event Reports (LERs) (90712) . . . . 14 9. Maintenance and Surveillance Testing . . . . . . . . . . . . . . 16 10. Exi t Intervi ew ( 30703) . . . . . . . . . . . . . . . . . . . . . 16 i

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OETAILS Persons Contacted During the report period, interviews and discussions were conducted with members of licensee management a id staff as necessary to support inspec-tion activitie . Summary of Facility Activities At the beginning of the inspection period, Unit I was in Mode 5 (Cold Shutdown) following the Cycle 6 refueling outage and Unit 2 was at 100%

power. During the period, Unit 1 completed outage recovery and was placed on the grid on March 2,1988. On March 3,1988, the licensee identified that Unit I had operated in apparent violation of the Technical Specifica-tions for about eight days in that two of four high-high containment pressure channels had been rendered inoperable by placing their associated bistables in the bypass condition (see Section 4.2.4). A Special Inspec-tion (50-334/88-12) was conducted during March 3 - 8, 1988, and an En-forcement Conference was held with the licensee on March 24, 1988, at the Region I offices in King of Prussia, Pennsylvania. Both Unit I and Unit 2 were at 100% power at the close of the inspection perio . Followup on Outstanding Items The NRC Outstanding Items (01) List was reviewed with cognizant licensee personnel. Items selected by the inspector were subsequently reviewed through discussions with licensee personnel, documentation reviews and field inspection to determine whether licensee actions specified in the OIs had been satisfactorily complete The overall status of previously identified inspection findings was reviewed, and planned / completed licensee actior.s were discussed for the item reported below:

(Closed) Unreso 'ved Item (50-334/86-15-04): Evaluate / resolve whether QA Procedure OP-4, Design Change Control, should be revised to require a 10 CFR 50.59 revies prior to design change package implementatio The licensee revised OP-4 (Revision 1, effective 2/26/88) to require that the safety evaluttion be completed prior to physically modifying an existing safety-relatea system described in the FSA The inspector reviewed the procedure revisions and no concerns were identified. This item is closed.

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. 2 4. Plant Operations 4.1 General Inspection tours of the following accessible plant areas were con-ducted during both day and night shif ts with respect to Technical Specification (TS) compliarce, housekeeping and cleanliness, fire protection, radiation control, physical security / plant protection and operational / maintenance administrative control Control Room -- Safeguard Areas

-- Auxiliary Building -- Service Building

-- Switchgear Area -- Diesel Generator Buildings

-- Access Control Points -- Containment Penetration Areas

-- Protected Area Fence Line -- Yard Area

-- Turbine Building -- Intake Structure The operability of selected Engineered Safety Features (ESF) Systems were verified by performing walkdowns of the accessible portions of the systems. The inspectors confirmed that system components were in the required alignments, instrumentation sensors were valved in with appropriate calibration dates, prints reflected the as-built systems and the overall conditions observed were satisfactor Sys-tems inspected during this perind include the Auxiliary Feedwater, Emergency Diesel Generator and Low Head Safety Injection System No concerns were identifie .2 Operations During the course of the inspection, discussions were conducted with operators concerning knowledge of recent changes to procedures, l facility configuration and plant conditions. During plant tours, logs and records were reviewed to determine if entries were properly made and that equipment status / deficiencies were identified and communi-cated. These records included operating logs, turnover sheets, tag-out and jumper logs, process computer printouts, unit off-normal and draft incident reports. The inspector verified adherence to approved procedures for ongoing activities observe Shift turnovers were witnessed and staffing requirements confirmed. In general, inspector comments or questions resulting from these reviews were resolved by licensee personne Inspections conducted during backshifts and weekends verified that plant operators were alert and displayed no signs of fatigue or inattention to dut . Inadvertent Reacter Trip Signal On February 19, 1988. while in Mode 5 (Cold Shutdown) a reactor trip signal was generated on Unit 1. Plant opera-tors had begun a draining and refilling evolution on the steam generators (SGs) to improve SG secondary side chem-istry for plant startu During the midnight shift, the

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reactor trip breakers were closed to support solid state '

protection system (SSPS) testing (Maintenance Surveillance Test). Following completion of the SSPS testing, the  ;

breakers were -lef t in the closed position. During the day shift, plant operators began draining the "B" SG; however,

-when the SG water level drained to below the low-low level reactor trip setpoint, the trip signal was generated. The  !

, reactor trip breakers opened as designed upon receipt of -

the' signal. All shutdown and control rods were already fully inserted and there were _ no positive reactivity addi-tions in progress at the time of the even Simulated  :

water level signals were subsequently inserted into the SG

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level circuitry to prevent addi tir. ial actuations as the  ;

draining and refilling evolutions continue The licensee ,

, notified the NRC of the event via ENS in accordance with'10 . ,

CFR 50.72 reporting requirement i The licensee determined that the cause for the event was  !

personnel error in that the individuals involved failed to t take additional actions needed to prevent the reactor trip  ;

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signal during the filling and draining evolution The inspector noted that Operating Manual Chapter No. 24, Pro-  ;

cedure 7, Draining and Refilling the Steam Generators, was not consulted for the above evolution. The licensee stated that during certain activities trat are routine and within the knowledge of plant operators, plant procedures are not  :

used as directed by a senior opentor. OM 24.T, however,  !

i included steps which insert "dume:i" normal SG water level i j signals to prevent a reactor trip signal during these evo-lutions. The licensee counseled the individuals involved in the event concerning maintaining proper awareness of plant status at all times and the use of available and

, appropriate plant procedures during routine evolution Additionally, this event was reviewed by all operations shift personnel at shift briefing During the review of this event, the inspector noted that  !'

the Maintenance Surveillance Procedure (MSP) failed to instruct the technicians to return the reactor trip break-ers to the as-found (in this case, open) conditio The licensee stated that the MSP is written assuming that the test is to be performed while at power (reactor trip break-  !

ers are closed). The inspector noted that this event is  ;

similar to the March 3,1983, identification of equipment ,

out of service in that both resulted from MSPs which did

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. 4 not return equipment to the as-found condition. Specift-cally, two out of four high-high containment pressure chan-nels were defeated by technicians for a period of eight days (see Section 4.2.4 and also Inspection Report 50-334/

88-12). The licensee stated that CM 24.T contains steps-which specifically direct the operators to assess scram breaker position and take~ the required action The licensee agreed to review the MSP for possible revision .2.2 Refueling Water Storage Tank Instrumentation Line Freezing On February 21, 1988, the control room bistable status light for the "C" refueling water storage tank (RWST) . level transmitter illuminated indicating that the low-low level setpoint for that channel had been reache Plant opera-tors immediately verified that the remaining three RWST level channels were indicating normal RWST levels, and con-firmed that "C" channel had failed low. Licensee investi-gation determined that the affected instrumentation line had frozen. Ambient temperature was about 12' F., A tem-porary kerosene heater was subsequently placed in the RWST cubicle area. Additionally, a tent was erected to increase the effectiveness of the kerosene heater. After about 2N hours, the af fected transmitter sensing lines thawed and the transmitter was returned to servic About five hours later; the "C" transmitter bistable status light again illuminated. Licensee investigation found that the instrumentation line had frozen again causing the transmitter to fail lo Further investigation found that the heat tracing for both the "A" and "C" level transmitter sensing lines had bei:n de-energized. The local temperature inside the tent had apparently reached the setpoint at which the associated thermostats de-energized the heat tracing circuit The licensee therefore increased the trip setpoints for. the thermostat Before the heat trac-ing could thaw the "C" transmitter sensing lines, the same lines associated with the "A" level transmitter had also frozen causing tnat transmitter to fail lo Technical Specification action statement 3.0.3 was entered, and tne licensee bypassed the bistable associated with the "C" level tran smi tte r. Therefore, a one-out-of-two coincident was required for the remaining two operable transmitters to satisfy the two-out-of-four logic which automatically initiates the recirculation cooling mode of the safety injection system following a safety injection actuatio ,...

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About 20. minutes after both lines had frozen, the lines thawed and both transmitters were returned to normal opera- y tion. :The licensee is in the process of developing a per- i manent fix for this problem. A similar situation occurred '

on January 1,1988. Adequate resolution of this problem will- be reviewed during a subsequent inspectio . Outage Recovery +

A separate NRC inspection (50-334/88-10) was_ conducted on

. February 22-26, 1988, to observe outage recovery activ-itie The resident inspectors also monitored portions of -

these activitie The attitude of plant operators was noted to be positiv Access to the control board was >

, limited as described in station procedures. The inspectors

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noted that the drawings in the control room were not always

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kept current to reflect actual system alignment, however, '

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significant deficiencies were not identified. While a con-siderable amount of required surveillance time was spent in '

verifying that all prerequisites and testing were completed prior to mode changes, tne system assumes that several  !

plant systems / components are not changed by the various station groups (also see NRC Inspection Report No. 50-334/

88-12). Portions of the approach to criticality and grid synchronization were observed by the inspecto . Auxiliary Feedwater System Actuation On February 25, 1988, while in Mode 3 (Hot Standby), a Unit  ;

I automatic auxiliary feedwater system initiation occurre A monthly operations surveillance test (OST 1.24.4) was being performed on the steam driven auxiliary feedwater ,

(AFW) pump which incorporated the yearly requirement to manipulate the steam driven AFW pump supply valves from the emergency shutdown panel (SDP). The flowpath for the steam supply to the AFW pump turbine is through two parallel trip valves (105A and 105B) and then through a common trip throttla valve. The sequence of events, as directed by OST 1.24.4 is as follow !

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Steam driven AFV pump started from Control Room using  ;

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Control for 105B transferred to SD ;

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105B opened from SDP - 105A closed from Control Roo ,

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Both 105A and 1058 verified open from SD Steam driven AF# pump shut down by closing 105A and 105 Transferred control for 105A and 105B back to control roo Upon control transfer of the closed steam supply valves back to the control room, a momentary de-energization of the solenoid valves, which vent air pressure from the steam supply valves to open them, occurred. This de-energization resulted in a start demand signal for the steam driven AFW pum However, when the pump was stopped by closing 105A and 105B at the SDP, the turbine trip throttle valve (located downstream cf the steam supply valves in the com-mon steam supply line) automatically closed as per desig The trip throttle valve a tomatically closes when either a low bearing oil pressure or mechanical overspeed occurs and the valve must be manually relatched to open it. When the steam driven arf pump was stopped by closing 105A and 105B, a low bearing oil pressure condition occurred, and there-fore, the trip throttle valve automatically closed, and was not yet relatched and reopened. Since the trip throttle valve was closed, the steam driven AFW pump did not star The AFW system design is such that the motor driven AFW pumps (2) automatically start whenever the steam driven AFW pump does not develop a specified discharge pressure within a pre-determined time following a start demand. The above conditions resulted in generating automatic start signals for both motor driven AFW pump The B motor driven AFW pump automatically started as de-signed, however, the A motor driven pump did not star Each motor driven pump uses a separate pressure switch to sense the discharge pressure of the steam driven pump to determine when an automatic start signal is required. The licensee concluded that the failure of the A motor driven pump to start was due to a momentary misoperation of its associated pressure switch (PS-FW-157) in that it appar-ently "hung up" and did not respond to the low discharge pressur The licensee subsequently tested the switch several times, and it functioned properly each time, init-iating an automatic start signal for the A motor driven pump. The initial actuation of the 'CV system resulted due

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to a procedural deficiency in that the procedure allowed the transfer of closed valves in a circuit that incorpor-ates break-before-make contacts for the associated solenoid valves after the steam driver, pump was shut down. The procedure was revised to require that control for 105A and 105B be transferred back to the control room prior to shut-ting down the steam driven pump. The inspector verified that this change was impicmente Repeated tests failed to repeat the malfunction of the pressure switch, however, a maintenance work request (MWR)

was generated to re verify the operability of the pressure switch during the next scheduled performance of OST 1.2 This was perforced on March 21, 1988. MWR 882569 requested that a recorder be connected to TS-FW-157 to monitor the output status of the pressure switch during the running of OST 1.2 The inspector reviewed the MWR and its asso-ciated recorder trac The trace was inconclusive as to whether the pressure switch properly reset and when the pressure switch operated as related to the starting and stopping of the steam driven pum Pressure switch opera-tion :ould not be confirmed from the trace following com-pletion of the OST and MW The MWP. instructions were apparently unclear as to what was to be compared to press-ure switch operation (i.e., pump operation), and therefore, pump starts and stops were not noted on the trac The inspector questioned whether the pressure actually did re-set since it could not be confirmed from the test or MWR results. The licensee subsequently obtained voltage and resistance readings across the pressure switch contact The readings cc nfirmed that the associated pressure switch had functioned properly and had reset. Due to the inter-mittent nature of the pressure switch misoperation, the licensee committed to recheck the proper functioning of both pressure switches (one per motor driven pump) during the next two OST performance The results of these checks will be reviewed during routine inspection No additional concerns were identifie .2.5. ESF Actuation On February 19, while at 84% power, the Unit 2 operators attempted to place the startup feedwater pump in servic Unit 1 was in Mode 5 (Cold Shutdown) at the time. Upon placing the control switch in the start position, an elec-trical transient occurred such that an overcurrent protec-tion relay was actuated for the emergency response facility (ERF) 3B transformer. The overcurrent condition resulted in the actuation of auxiliary relays which isolated the 3B

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. 8 transforme During de-energization and transfer of af-fected electrical buses, the momentary voltage loss actu-ated a supplementary leak collection and release (SLCR)

radiation monitor (2RMR-RQI301). The loss of power to 2RMR-RQI301 simulated a high radiation signal, which init-iated the SLCR system realignment to its ESF (filtered)

flowpat The opening of the supply breaker for the 3B transformer also resulted in a loss of power to the Unit 1

"1B" station service transformer and its associated two normal 4 KV buses (1C and 1D) in the 4 KV emergency bus (DF). The associated No. 2 emergency diesel generator did not automatically start as designed because it was out of service for repairs, (since Unit I was in Mode 5, only one train of 4 KV emergency power was required to be operable).

The "A" train had been the priority train at the time of the event and all associated equipment was operable. This event was reported to the NRC via ENS in accordance with 10 CFR 50.72 reporting requirement The three phase overcurrent relays for the ERF 3B trans-former were subsequently tested and found to be operating satisfactoril The licensee elected to replace the relay which was sent to an off-site vendor for further analysi The transformer overcurrent protection provides the second level of protection for the circui Overcurrent relays downstream of the 3B transformer on an associated 4 KV bus feeder breaker constitute the first level of protectio The licensee found that the 125 volt DC control power for the overcurrent relays had been de-energize The control power circuit breaker located in the ERF substation was left open because it was not labeled i.1d was mistakenly thought to be an unused spar This breaker was also ,

omitted from the ERF operating manual power supply switch lis The power supply switch list has since been revised to include this breaker and plans were made to place a label on the breake The licensee plans to initiate a review of the entire ERF substation to identify and resolve any similar problem Similar concerns have previously been identified (NRC Inspection Report No. 50-334/87-11) with respect to label-ing components in the plant. The previous concern identi- -

fied that many plant components were labeled with marking pens or other types of uncontrolled markers. The licensee initiated corrective actions to assure that appropriate plant equipment is correctly identified in a controlled

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manner through an improved identification system. The con-cern identified during this inspection (inadequate and/or lack of labeling) should also be included in the licensee's  ;

evaluation. A followup inspection was performed on Unit 2,  !

during which similar problems with respect to labeling also existed. Resolution of this concern for both units will be followed via Unresolved Item Nos. 50-334/88-11-01 and 50-412/88-07-0 . High-High Containment Pressure Channels Defeated  ;

On March 3,1988, with Unit 1 at 30% power, the licensee identified that two out of the four high-high containment  ;

pressure (HHCP) bistables were bypassed (defeated). The  ;

bistables were promptly restored but the two channels were i found to have been defeated for about eight days. This I event and the licensee's initial corrective actions were reviewed during NRC Special Inspection 50-334/88-12 and discussed during the March 24, 1988, Enforcement Confer-ence. One root cause of this violation was that certain licensee Maintenance Surveillance Procedures (MSPs) did not *

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require restoration of switches to the as-found posit 1u The HHCP bistables involved had been placed in the opera- ,

ting position as part of a Startup Checklist, then placed in the bypass position for a MSP, and lef t bypassed af ter the MSP's were performed on February 22, 198 .3 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 and Vital Area barriers were well maintained and not compromised; i l

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Isolation zones were clear; i

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Personnel and vehicles entering and packages being delivered to the Protected Area were properly searched and access control was in accordance with approved licensee. procedures;

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Persons granted access to the site were badged to indicate whether they have unescorted access or escorted authorization; t

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and that persons in Vital Areas were proped y aut% rize t i

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Security posts were adequately staffed and equipped, security personnel were alert and knowledgeable regarding posit 19n requirements, and that written procedures were available; and

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Adequate illumination was maintaine No concerns ware identifie .4 Radiological Controls Posting and control of radiation and high radiation areas were inspected. Radiation Work Permit compliance and use of personnel monitoring devices were checked. Conditions of step-off pads, dis-posal of protective clothing, radiation control job coverage, area monitor operability and calibration (portable and permanent) and personnel frisking were observed on a sampling basi P Significant concerns were not identified during this inspection in the area of radiological controls. Housekeeping in radiologically controlled areas, hcwever, was found to exhibit weakness (see Section 4.5.2).

4.5 Plart Housekeeping and Fire protection Plant housekeeping conditions including general cleanliness condi-tions and control and storage of flammable material and other poten-tial safety 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 The inspector conducted detailed walkdowns of the accessible areas of both Unit 1 and Unit . Unit 2 Areas ,

Ouring the previous inspection, the inspector expressed the l concern that items such as improperly secured gas bottles, unsecured gas bottles and wheeled devices were still being found near safety-related equipment. In addition, a tem-porary laydown area of boards, ladders and scaffolding material was found by the inspector to be stacked around and against a Unit 2 containment isolation valve during plant startu The inspector concluded that this area exhibited weakness during the previous inspection perio During the current inspection period, the inspector noted a marked improvement in Unit 2 housekeeping including the removal of gas bottles and securing of equipment. At the end of this period, Unit 2 had attained a very good level

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, 11 4.5.2 Unit 1 Radiologically Controlled Locked Areas During the current period, Unit I completed the sixth re-fueling outage and was placed on the grid on March 2, 198 Housekeeping was found generally to be adequate during the eleven week outage although the general radiological house-keeping and posting practices were found in one inspection (see Inspection Report 50-334/88-03; 50-412/88-02) to be poor compared to other utilitie The licensee attributed the decline in radiological housekeeping to the large volume of outage activitie At the end of the period, approximately one month after outage completion, the inspector conducted a detailed walk-down of the accessible Unit I radiation areas including those normally locked to limit acces Notable improve-ments were observed in that some areas which had been con-taminated, like the fuel pool cooling pumps, were now accessibl Other areas, such as the boron recovery pump cubicles, were also nearly complete in decontaminatio Aggressive efforts to reduce the area of floor space marked as contaminated were evident. In some cases, the residual taped areas appeared to be too small in that insufficient taped area was provided around a contaminated component to '

provide working access. In the waste pump cubicles, one pump had a very small oil drippage but the oil was found to have pooled off the pump platform within the contaminated area, across the boundary tape, and into the "clean" are In another waste pump cubicle a coiled extension cord was found straddling the taped boundary, half inside the con-taminated zone and half outside on the "clean" floor. These examples are considered isolated cases, but they do indi-cate a need for caution in the control and reduction of contaminated area '

Hcusekeeping in the Unit I radiologically controlled areas still exhibited weakne.ts one month after conclusion of the sixth refueling outag Many areas were found littered with tools (such as wretches, knives, crowbars and flash-lights), parts (such as gaskets, pipe caps, screws and fittings) and debris (such as used gloves, cotton glove liners, paper swipes and empty bags). Some cubicles not marked as contaminated were visibly dirty and one area had clearly experienced a spill of chromate-contaminated fluid.

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4. Unit 1 - Non-Radiological Housekeeping Unit 1 general housekeeping improved af ter the outage al-though examples of unsecured gas bottles and open cable junction boxes were identified by the inspector and re-ported to the licensee. Two potentially serious defici-encies were identified by the inspector in the cable spreading room. Cable ,iunction boxes designed to provide ESF train separation were found open and cable tray covers were found missing, damaged and improperly installed. The inspector brought these deficiencies to the licensee's attention and corrective actions were in process shortly after the completion of the inspectio This item is Unresolved (50-334/88-11-02). The inspector will review the licensee's corrective actions including root cause evaluation and actions taken to prevent recurrence in a future inspectio . Natural Circulation Cooldown Unit 1:

The inspector reviewed the licensee's action taken to implement Generic Letter (GL) No. 81-21, Natural Circulation Cooldown. The NRC has tracked this issue as multi plant action No. B-66 and SIMS No. MTA-B-66, The GL, issued on May 5,1981, requested that within six month: ef receipt of the generic letter, licensees furnish an assessment of their facility's pro-cedure and training program with respect to reactor vessel voiding during natural circulation cooldown. The assessment was to include (1) a demon-stration that controlled natural circulation cooldown from operating con-ditions to cold shutdown conditions, conducted in accordance with plant procedures, should not result in reactor vessel voiding, (2) verification that supplies of condensate grade auxiliary feodwater are sufficient to supoort the cooldown method, and (3) a descriptian of tha training program and the provisions v, the procedures that deal with prevention or mitiga-tion of reactor vessel voidin The licensee responded to GL 81-21 for Unit 1 by letter dated November 1, 198 By letter August 2, 1983, the NRC issued a safety evaluation report which concluded that the licensee had adequately demon-strated the capability to reach cold shutdown using natural circulation without upper head void formatio Additionally, the safety evaluation report concluded that the plant had sufficient condensate supplies for an extensive cooldown. The safety evaluation report did not review operating procedures; however, the letter documented that the operator procedures will be adequate for performance of a safe natural circulation cooldown ,

upon acceptable implementation of the NRC-approved Westinghouse Owner's Group Emergency Response Guidelines. This was subsequently achieved on November 15, 1985.

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. 13 The inspector reviewed the licensee's training program and confirmed that natural circulation cooldown is adequately addressed for both classroom and simulator coverage. Discussions were held with selected operators, which indicated that the individuals were knowledgeable on the natural circulation cooldown process. Plant specific emergency operating proced-ures also adequately address natural circulation cooldown in accordance with the licensee's responsa to Generic Letter 81-2 No concerns were identified. This issue is close Unit 2:

Natural Circulation cooldown was addressed in the NRC Safety Evaluation Report (SER), NUREG-1057, related to the operation of BVPS, Unit 2. The issue of natural circulation testing was previous tracked by NRC Licensing as Confirmatory Issues No. 22, Natural Circulation Test The licensee l was to perform a comparison study of BV-2 with North Anna Unit 2 to verify the adequacy of the mixing of borated water added to the reactor coolant system under natural circulation and the ability to cool down the plant with natural circulation. However, the only natural circulation tests were performed at a Westinghouse plant to meet the requirements of Branch Technical Position RSB 5-1 were at the Diablo Canyon Plant. Diablo Canyon is a four-loop plant and there was the concern that other significant differences may exist between the two plants such as upper vessel head temperatur The SER noted that, with respect to natural circulation testing, the licensee can demonstrate that the Diablo Canyon test is applicable to BV-2 with comparison of thermal and hydraulic similarities in the core, upper vessel head and loops. By letter dated May 11, 1987, the licensee submitted a report which documents the applicability of Diablo Canyon boron mixing results to BV-2. Based on the above, the NRC concluded that there was reasonable assurance that BV-2 could operate for

, one cycle until this issue was resolved since (1) natural circulation has been demonstrated for other Westinghouse plants, (2) operator training

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will be provided on a simulator which adequately represents BV-2 perform-ance with regard to natural circulation, (3) systems required for natural circulation cooldown (e.g., auxiliary feedwater) are safety grade, and (4)

there is an ample auxiliary feedwater supply from seismic Category I sources. Therefore, a license condition was not imposed on BV-2 with respect to natural circulation testing. The NRC closed Confirmatory Issue No. 22 in SER, Supplement No. 5, and resolution of the natural circulation testing issue will be tracked via licensing action No. TAC 6290 The licensee's training program for BV-2 is similar to BV-1. Natural circulation cooldown is adequately covered in the operator training pro-gram as confirmed through discussions with plant operators who were demon-strated to be knowledgeable on the issue. The plant specific emergency operating procedures also adequately address natural circulation cooldown concerns. With the exception of natural circulation testing, which will be tracked separately, this issue is close _ _ _ _ _ - _

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. 14 6. Calibration Program l The licensee's calibration program uses red foil-type stickers to identify those components required by TS to be calibrated within a specific perio Certain components which are used to measure the performance of other TS required equipment are also given red foil-type sticker In a previous inspection (50-334/88-01; 50-412/88-01), the inspector noted that certain j of these stickers had been identified to the litersee as being beyond the

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required calibration due dat The licensee provided a response near the end of the inspection period which indicated that most of the inspector-identified stickers were erroneously labelled. In some cases, the stickers were marked incorrectly and in others the wrong type sticker had been used. The inspector pro-vided the licensee additional examples of potentially deficient stickers and will continue to review this area during the next inspection perio . Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted pursuant to Technical Specification 6.9 (Reporting Requi ren,ent s) were reviewed. The review assessed whether the reported informntion was valid, included the NRC required data and whether results and 5,upporting information were consist-ent with design predictions and performance specifications. The inspec-tor also ascertained whether any reported information should be classified as an abnormal occurrence. The following reports were reviewed:

BV2 - Monthly Operating Report for Plant Operations from January 1-31, 1988 (Revised).

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Monthly Operating Report for Plant Operations from February 1-29, 198 BV1/BV2 - Monthly Operating Report dated March 10, 198 BV1 -

Reactor Containment Building Integrated Leak Rate Test Result BV1/BV2 -

Annual Report of all Challenges to the Pressurizer Power Operated Relief Valves (PORVs) or Pressurizer Safety Valve No concerns were identifie . Inoffice Review of Licensee Event Reports (LERs)

The inspector reviewed LERs submitted to the NRC Region I office to verify that the details of the event were clearly reported, including accuracy of the description of cause and adequacy of corrective action. The inspector determined 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:

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Unit 1 LER 88-01-00: Steam Generator Tube Pluggin :

LER 88-02-00: Reactor Trips on Low-Low Steam Generator Level Due to  !

Personnel Erro LER 88-03-00: Inadvertent Start of Auxiliary Feedwater Pumps Oue to Pro-cedural Deficienc Unit 2 LER 87-33-01: Failure to Perform Surveillance Test within Required Frequenc LER 88-02-00: Reactor Trip and Control Room Emergency Bottled Air Pressucitation System Actuatio LER 88-03-00: Improper Clearance Results in ESF Actuatio LER 88-04-00: Diesel Generator Actuation due to Spurious Cvercurrent Signa LER 88-05-00: Overcurrent Relay Trip Leads to ESF Actuntio LER 88-06-00: 2/4 Refueling Water Storage Tank Level Ch.snnels Inoperabl The above LERs were reviewed with respect to the requirements of 10 CFR 50.73 and the guldsnce provided in NUREG 1022. Previous inspection re-ports have noted that while most LERs provided good documentation of event >

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analyses, root cause determination and corrective actions, some LERs were

, weak in that they contained event inaccuracies and safety evaluation omissions. Most of the above LERs were good but two, LER 88-03 on Unit 1 and LER 88-06 on Unit 2, were not as strong. LER 88-03 misidentifies which motor driven AFW pump started and which one failed to start (see Section 4.2.4 for details of this event). The LER correctly states that there was no safety implication to the inadvertent auto-start of a motor driven AFW pump, but did not address the potentially more significant safety implication inherent in one pump failing to auto start on deman .

LER 88-06 concludes that there were no safety implications due to the inoperability of two out of four RWST level channels because the other two channels were operable and "fully capable of initiating" automatic switch-over to the Containment sump. This is not wholly accurate in that the two failed-low channels would, without operator action, have immediately upon ,

receipt of an SI signal initiated switchover to the dry containment sump

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thus defeating the ECCS. This potential safety significance was also discussed in Inspection Report 50-334/88 01; 50-412/88-01. The concern was addressed by leaving one low-low signal in and bypassing the other failed channel. This allowed the automatic switchover feature to be actuated from either one of the two operable channels (one out of two logic). These actions are not presented in the LE . Maintenance and Surveillance Testing Corrective and presentive maintenance and routine surystillance testing activities during this inspection period were reviewed as cart of the Unit 1 NRC Probabilistic Risk Analysis Based Team Inspection. Specific activ-ities and programmatic reviews are documented in NRC Inspection Report 50-334/88-08. Other maintenance and surveillance activities were reviewed during NRC Special Inspection Report 50-334/88-1 . Exit Interview Meetings were held with senior facility management periodically during the course of this inspection to discuss the inspection scope and findings. A summary of inspection findings was further discussed with th;t licensee at the conclusion of the report period on April 4, 198 .

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