IR 05000338/1987019

Insp Repts 50-338/87-19 & 50-339/87-19 on 870617-0818. Violations Noted.Major Areas Inspected:Plant Status, Unresolved Items,Licensee Actions on Previous Enforcement Matters,Inspector Followup Items & LER Followup

ML20238F688
Person / Time
Site:	North Anna
Issue date:	09/01/1987
From:	Caldwell J, Cantrell F, King L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20238F684	List: IR 05000338/1987019 ML20238F682
References
50-338-87-19, 50-339-87-19, NUDOCS 8709160288
Download: ML20238F688 (20)

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. UNITED STATES ,. p pu atGoq'o, NUCLEAR REGULATORY COMMISSION 85 "* REGloN 11 h j..'d, 101 MARIETTA STREET, ' gy i r ATLANTA, GEORGI A 30323 s...../ Report Nos.: 50-338/87-19 and 50-339/87-19 Licensee: Virginia Electric & Power Company Richmond, VA 23261 E'ocket Nos.: 50-338 and 50-339 Facility Name: North Anna 1 and 2 Inspection Conducted: June 17 - August 18, 1987 Inspectors: &k 4f J. L. ' Caldwell , SRI 7hh7 Date Signed L. P. King, RI T% RL $hk] Date Signed ;

 ' Approved by:    . Y/ Mm  _ _

_9//,[[7 F. Cantr' elf ,~ Stc' tion Chief 6 D6te Signed Division of Reactor Projects SUMMARY Scope: This routine inspection by the resident inspectors involved the following areas: plant status, unresolved items, licensee action on previous enforcement matters, licensee event report (LER followup), review of inspector follow-up items, monthly maintenance observation, monthly surveillance observation, ESF walkdown, operator safety verification, operating reactor events, plant startup from refueling and design change modifications. During the performance of this inspection, the resident inspectors conducted reviews of the licensee's backshift operations on the following days - June 21, 23, 24, 25, 27, 28, 28, 29 and 30, and July 1, 2, 7, 13, 15, 16, 17, 19, 20, 27, 28, 29, 30, and 31, and August 5, 6, 13 and 1 Results: One violation was identified. Violation of Technical Specification (TS) 6.8.1.c for an inadequate surveillance procedure and violation of TS 3.7.7.1 for technically inoperable control room emergency ventilation system and bottled air pressurization syste (paragraph 9)

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I NHi< a; '\' M.? iN f 0 REPORT DETAILS g 6 J+ Licensee Employees Contacted E. W. Harrell, Station Manager

  *R. C. Driscoll, Quality Control (QC) Manager
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  *G. E. Kane, Assistant Station Manager
  * L. Bowling, Assistant Station Manager y n,,,  * O. Enfinger, Superintendent, Operations O
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a M. R. Kansler, Superintendent, Maintenance

  *A. H. Stafford, Superintendent, Health Physict,
  *J. A. Stall, Superintendent, Technical Serv kvrs ,

J. L. Downs, Superintendent, Administrative Servicds ! J. R. Hayes, Operations Coordinator f g D. A. Heacock, Engineering Supervisor D. E. Thomas, Mechanical Maintenance Supervisor G. D. Gordon, Electrical Supervisor R. A. Bergouist, Instrument Supervisor F. T. T6frdnella, QA Supervisor o f J. P. SmitS, Superintendent, Engineering L _, U. B. Roth, Nuclear Specialist J. H. Leberstein, Engineer

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y *G. ;G. Harkness, Licensing Coordinator Other licensee employees contacted include technicians, operators, mechanics, security force members, and office personne ' '

  * Attended exit interview y  NRC Regional Management Site Visit: L. A. Reyes and F. S. Cantroll' visited i  the North Anna Power Station on June 24, 198 . Exit Interview (30703)

The inspection scope and findings were summarized on August 18, 1987, with those persons indicated in paragraph I above. The licensee acknowledged i the inspectors findings. The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspectio (0 pen) Violation 338,339/87-19-01: Violation of TS 6.8.1.c for an i a' inadequate control room bottled air surveillance procedure and Violation of TS 3.7.7.1 for inoperable control room emergency ventilat' ion system and j bottled air pressurization system (paragraph 9).

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  (0 pen) Unresolved Item 338,339/87-19-02: Potentid; vioittion 10 CFR 20 for failure to perform or require the performance of a radiation survey following a resin discharge which resulted in an unlocked and improperly posted radiation area of approximately 2 REM /hr. (paragraph 11).

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   -(Open). Unr'esolvedI Item- 338/87-19-03: . Potential violation for. an inoperable loutside' recirculation spray. pump due to a degraded seal. package
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(0 pen); Inspector Followup' Items 338,339/87-19-04-through 338,339/87-19-15: L Items pertaini_ng to_the.NRR letter dated May 4, 1987, from L. B.-Engle.to

   ;W._ L. Stewart discussing control room habitability (paragraph 9).

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   (0 pen) Inspector Followup Item 338,339/87-19-16: Review evaluation of l-    -.startup problems for possible common cause (paragraph 15).

(0 pen) Licensee. Identified Violation 338,339/87-19-17:. Core alterations without: charging pump emergency power supply (paragraph 11).

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   (0 pen). Licensee Identified , Violation - 338,339/87-19-18: Mode change .

l . without' automatic initiation available for auxiliary feedwater pumps j (paragraph 11). ' 3.- ' Plant Status Unit 1 Unit 1 began. the inspection period in Mode 5 restoring from a 60-day refueling ' outage. The unit was in the process of heating up to enter Mode 4 when the "A" reactor coolant pump (RCP) tripped due to an , electrical ground on the motor. The unit was cooled back down to less j than 140 degrees F. in preparation to repair.the "A" RCP moto On.-June 21', while still in Mode 5 with the repair of the "A" RCP motor still . not complete, the licensee discovered inadvertent voiding in the reactor vessel- head.and steam generator (S/G) tubes (see. inspection report 87-21 for details). The vessel was refilled on June 21, and the operators monitored various vessel level indications to ensure the reactor coolant system-(RCS) remained filled. On June 27 (day 70 of the outage), with the

   "A" RCP motor repair complete and the pump tested, the licensee heated up to Mode On June 29, with the unit at approximately 18% power, an automatic turbine trip / reactor trip was experienced. The cause of the trip was a high water level in the number 5 feedwater heater which resulted from an improperly performed tagout and isolation of the feedwater heater divert valves (see I

section 12 for details). The unit was restarted the following day, June 30; and on July 1 at approximately 24% power, the licensee discovered the manual isolation . valve for the "C" main feedline stuck in the shut position. . Attempts to open the valve resulted in a broken stem. The unit was shutdown on July 2 and cooled down to approximately 205 degrees F. to allow repair of the manual isolation valv On July 4, 'after repair of the feedwater isolation valve was completed, the unit was restarte With the unit at approximately 80% power on July 7, the licensee had to ramp the unit back down to 50% power due to a decreasing temperature in the "A" moisture separator reheater (MSR). The _ _ - _ - _ _ _ _ _ _ _ _ - _ ._ _ _ _ _ - _ _ _ . - = _ _ _ _ _ . _

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   ..s cause of the temperature probiem was discovered to be an improperiy installed "B" MSR stop valve which would not. fully open ' or close (see
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section 8 for details). The unit proceeded to rf tintain power less than 47?s based on a recommendation from Westinghouse until July 10 when the unit was shutdown to repigce the "B" MSR stop valve. The valve was l

/ replaced on' July 11 and the unit was restarted on July 1 '

Unit 1 achieved 'approximately 100?4 power on July 14, however; on t.iet morning of July 15, 1987, at approximately 6:30 a.m., Unit 1 experienced'a

 , S/G tube rupture (see inspection report 87-24 for details). At 'the d')d of
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the inspection period the unit was in day 35 00 the S/G tube rupure d

 ' outage. The licensee is performing extensive S/9; tube inspections and  <j wpects to have the unit back on line in late Septwbeg or early October f  papdingtheinspectionresultsandNRCapproval, j   '
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Unit 2 commenced the inspection period operating at 100?; power w,ith 0 ppm boron in the RCS, -The unit is in the process of a coastdown to the refueling outage which was scheduled for July 31. However, due to the S/G tube rupture outage on Unit 1 and the power demands on the '/EPC0 system, Unit 2 refueliog has been rescheduled for August 23, 1987. The unit is

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presently operhting at approximately 63?? power continuing to coast down to

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the August 23 refueling outag < The licensee reports that Unit r.as operated for 415 days without an

> d* automatic reactor trip. Of the AJ 6yr, the unit was only off line fon
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21 day , Unresolved Items 4 An' Unresolved Item is a matter a' bout which more information is required to  ; determine whether it is acceptable or may involve a violation or , deviatio , y Two unresolved items were identified during this inspection and are I discussed in paragraph 1 . Licensee Action on Previous Enforcement Matters (92702)

 (Closed) Violation 339/86-28-09: Inadequate Procedure Resulting in the Failure of a Charging Fump. The licensee installed new identification tags on the Unit 1 and Unit 2 service water valves for each charging pump, Padlocks were installed on Unit 1 and Unit 2 service water isolatin valves to lock the valves in the open positio i Maintenance procidures for both units M0P-8.01, 8.02 and 8.03 were revised
 ' to lock open or verify that the service water isolation valves for each charging pump are opened and. locked prior to returning the charging purr:is to service following lube oil maintenanc ,

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e Operating procedures for both units,-OP - 8.1, were revised to verify that service water is available to the lube oil cooler . . Licensee Event Report (LER) Fo110w-Up,(90712) t The following LERs were reviewed and closed. The inspector verified that reporting requirements had been met, that causes had been identified, that corrective actions appeared . appropriate, that generic applicability had been considered,, and that the LER forms were complete. Additionally, the inspectors confirmed that no unreviewed safety questions were involved and that . violations of. regulations or . Technical Specification (TS) conditions had been identifie (Closed) 10 CFR. P2185-02: Calvert Cliff's Generator Failur The licensee _ contacted Colt Industries, the manufacturer of North Anna's

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s emergency' diesel generators, and performed a visual inspection on each of g' ~ th e'stati,on's emergency diesel generators. The problem does not exist at

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Morth Ann The generators were built with independent winding The

 
    ,connqction stpap/ link that failed at Calvert Clif f is not' installed at
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,. iMorth: Ann / (Closed) LER 338/87-04: Unit 1 Reactor Trip Caused by Dropped Control

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   '! ; Rod. lThe cause of the rod drop was a blown fuse in the stationary gripper
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coil circui All fuses were replaced during the Unit 1 outage in

   ' accordance. with ' recommendations contained in Westinghouse Data Letter NSP-78-12 which suggests replacement every other refueling perio '(Closed) LER 338/87-11: Core Alterations Initiated Without An Operable Charging Pump Due To An Inoperable Emergency Diesel Generator. This event is discussed in section 11 of this report and the root cause of the personnel error is being evaluated via the Human Performance Evaluation Syste (Closed) LER 339/87-05: Unit 2 Enters Mode 3 From Mode 4 With No Auto Start On Aux Feedwater Pumps. This event is discussed in section 11 of
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e via the Human Performance Evaluation Syste VY

J' ?! Review of Inspector Follow-up Items (92701)

    (Closed) IFI 338,339/86-28-05: Perform Inspections to Determine Source of 1   Contamination " Rubidium Releases"
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    (1) The licensee completed chemistry procedure CAP-35.0 which tests
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laboratory and sample room ventilatio (2) The cold leg samples and the influent to the mixed beds are recirculated and sent to the gas stripper. If the samples cannot be sent to the gas stripper, they are routed to the VCT 4 after notification of the shift supervisor, V y

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 (3), The discharge side _ of the air handling system was checked for-l ea k s.. Leaks were found at the discharge of the number 8, A, B and C fans. Seven work requests to correct this have been completed, (Closed) IFI 338/86-28-08: Replacement of Air Cylinders Associated with the Auxiliary Feedwater Syste The licensee completed installation of new air cylinders and tubing during the .last Unit 1 outag (Closed) UNR 338.,339/86-28-02: Potentially Inadequate Surveillance Procedures. This item is closed and reopened as a violation in section 9 of this repor . Monthly Maintenance (62703)

Station maintenance activities affecting safety related systems and components were observed / reviewed, to ascertain that the activities were conducted in accordance with approved procedures, regulatory guides and industry codes or standards, and in conformance with Technical Specification On July 7, 1987, following a ramp up to 80% power, Unit I had to be ramped back down to approximately 50% power due to temperature and water level problems in the "A" moisture separator reheater (MSR). The licensee determined that the cause of the problem was the failure of the "B" MSR stop valve to open fully causing an increased steam flow from the "A" MSR to compensate for the reduction from the "B" MS On July. 8,1987, the licensee declared the "B" MSR stop valve inoperable because they could not guarantee that the valve would perform its intended safety function which is to shut on a turbine trip signal. The licensee then shut the "B" MSR intercept valve isolating the steam from the "B" MSR. Westinghouse informed the licensee that they could operate with the steam flow from the "B" MSR isolated at a power level less than 50% without damaging the turbine. On July 10, Unit I was shut down to repair the "B" MSR stop valv During the repair, the licensee discovered that the valve installed in the

 "B" MSR stop valve position was actually a valve designed for the intercept position and consequently the actuator was not installed correctly to allow the valve to stroke from the full open to the full    !

closed positio Instead, the "B" MSR stop valve was stroking from a partial open through the closed position to a partial open positio Following this discovery, Westinghouse informed the licensee that for Unit I the stop valves and intercept valves were not interchangeable and that the Unit 2 valves could not be used in the Unit 1 valve location. This information had not been communicated to the licensee previous to this event. The licensee has replaced the "B" MSR stop valve with a correct Unit 1 stop valve.

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.  'The inspector reviewed. the maintenance procedure' MMP-C-GV-NSR-1, Mechanical Maintenance Procedure for Non : Safety Re:ated Valve Repair 'and Inspection, used for the "B" MSR stop . valve replacement performed during j
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the1 refueling ~ outage. ' The instructions for the work were nothing more than. handwritten -steps which simply stated remove, reinstall, torque - and i reconnect _the valve. The reason given for the write-in steps was forman.- ' experience. . However, as demonstrated by :the problem ' encountered, the

 ;1icensee did not.have'the experience or the knowledge necessary to ensure that - the MSR stop valve was installed correctly. ~ Further review : of MMP-C-GV-NSR-1 -showed that operations and maintenance had signed step 8.5-stating that the "B" MSR stop' valve' stroked satisfactorily. The, valve was considered to' stroke properly-by the maintenance-procedure and 1-PT-34.3, Turbine Valve Freedom Test, which was conducted on July 4, 1987, to verify'

valve operability for Technical Specification (TS) 4.7.1.7.2.a and It is clear from the review of the maintenance and surveillance procedure and the. actual .results of the valve performance that the conduct o f-maintenance, maintenance retest and the T.S. , required surveillance were inadequate to ensure o that the. valve was reinstalled and operated as required to isolate-steam to the turbine on a trip signa The' surveillanc procedure 1-PT-34.3 'did, however, verify - that at least one of the two- . in-series isolation valves in the. "B" MSR line went shut on a trip signal,

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therefore, -the turbine was, protected from an overspeed condition by- the

 "B" intercept valv The inspector also observed that there did not appear to be any < Quality Assurance (QA) involvement associated 'with the maintenance'or testing of this valv The "B" MSR stop valve is a non-safety related valve, therefore, the maintenance procedure is also non-safety related. However, this valve is required by T.S. to be able to isolate the turbine and protect it from an overspeed condition following a trip signa The surveillance, though inadequate to ' verify the actual operation of an improperly installed
 - valve, is adequate as long as the valves are correctly installed and verified by the maintenanc Therefore, the root cause of this event appears to be the inadequate maintenance and maintenance retest performed on the "B" MSR stop valve. Since these procedures are non-safety related the licensee will not be issued a notice of violation. This item is also discussed in paragraph 15.

i On July 14, 1987, the inspectors witnessed the performance of ICP-T-3-432A for troubleshooting protection channels.

' No violations or deviations were identifie . Monthly Surveillance (61726) The inspectors observed / reviewed technical specification required testing and verified that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, that limiting conditions for operation (LCO) were met and that any deficiencies identified were properly reviewed and resolve i l 1 i i l

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V; - L { 7 ! The. inspectors reviewed 1-PT-57.8A " Leak Rate Test of 1-BR-EV-2A and Associated Equipment"-(BR - Boron Recovery Evaporator). i On' June 30, 1987, the inspectors, together with NRR personnel witnessed the licensee's attempt to perform 1-PT-76.4, Control Room Bottled Air - Pressurization System Test. This attempt was unsuccessful due to a relief valve lifting on the Unit 2 side, dumping one half of the air bottles outside of the control room envelope. The licensee adjusted the pressure control valve setpoints and attempted the test again on July 31, 198 The resident inspector, a NRR inspector and a NRC consultant were present to observe the test. This test attempt also failed, but only in the last two minutes when several of the differential pressures dropped below the Technical Specification (TS) limit of 0.03 inches water gaug Following the second attempt, the licensee repressurized the bottles to 2400 psig and adjusted the pressure setpoint on the Unit 2 side pressure control valves to reduce the flow out of the bottles. Then, on August 2, 1987, the licensee conducted a successful performance of 1-PT-7 A review of the data indicated that the test passed with approximately 45 seconds to spare. This test indicates that the bottled air system is marginal and, combined with the fact that the starting pressure of the test was 2400 psig, the inspector questioned whether the TS limit of 2300 psig was still valid. The licensee is presently evaluating this situation and for the time being, will line up three sets of bottles instead of just the two that are normally required to ensure that TS requirements are me Following the successful test performance, the inspector requested a copy of the test data from the previous three 18-month test performance A review of this data revealed that numerous pressure gauges indicated less than 0.05 inches throughout the test, with some even indicating zero differential pressure. Since the pressure gauges do not indicate below Iero, the potential exists for some of the zero differential pressures to have been negative in relation to the adjacent environmen This could have established a flow path from the outside environment into the control room envelope. The inspector reviewed the surveillance procedure used to perform the previous tests and discovered the acceptance criteria to be an average positive pressure greater than or equal to 0.05 inches water guage between the control room envelope and the outside atmospher This acceptance criteria allowed tne licensee to have differential pressure less than the TS requirement of 0.05 inches water guag The licensee was informed by the NRC during a review of their control habitability system in December 1986 and documented in the report that was issued in May 1987 that the proper interpretation of TS is that any indication below 0.05 inches will cause the test to fail. Therefore, the latest successful test that was conducted on August 2,1987, had been changed to reflect that interpretatio Several items of concern resulted from the control room habitability review in December 1986. The immediate items were addressed, and the licensee took action to resolve them. A review of the latest bottled air _ - _ _ _ _ _ - _ _ -

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test, the previous three 18 month test data and the FSAR assumptions for the bottled air system have raised operability concerns associated with the bottled air system. These concerns are as follows:

(1) Based on the FSAR, the control room is assumed to be isolated for the first hour. This assumption is not valid as demonstrated by the recent stoam generator tube rupture event, where the control room doors were opened numerous time However, the TS required surveillance test is performed with guards on the control room envelope doors to prevent opening; therefore potentially not demonstrating the conditions of an actual even (2) Prior to the latest test, the licensee allowed various sections of the control room envelope to be at a pressure less than the TS limit of 0.05 inches relative to the outside environment and in some cases, possibly negative in relation to the outside environmen Both situations appear to be in violation cf the TS limit of 0.05 inches delta P between the control room envelope and the outside atmospher (3) Prior to the review performed in December 1986, the licensee had a condition established in the lower emergency switch gear ventilation rooms which prevented a positive pressure from being established between the ventilation room and the outside atmosphare (the chiller room which communicates directly with the turbine building). This situation was discussed in the NRR report dated May 4, 1987, documenting the control room habitability review and findings, and by the inspector in inspection report 338,339/86-28 as an unresolved item 86-28-0 The negative delta P from the emergency switchgear room to chiller room could establish a possible flow path from the turbine building into the control room envelope during an accident. The licensee has taken action consisting of removing a block wall between the ventilation rooms and the adjacent switchgear rooms in both units to alleviate the low pressure condition being established in the ventilation rooms. Now the two areas in both units are essentially the same pressure. The licensee also reversed the flow direction of the fan in the adjacent chiller rooms from flowing into the rooms to flowsng out of the rooms, thereby reducing the pressure in the chiller rooms. Both of these actions appear to have alleviated the concern associated w1th the failure of the bottled air system to establish a positive pressure between the switchgear ventilation room and the adjacent chiller room Based on these concerns, coupled with the fact that the bottled air system is marginal under ideal circumstances, the inspector considers the control room emergency bottled air system to have been in non-compliance with TS 4.7.7.2.b until August 2, 1987, when a successful test was completed. The question of the control room being isolated for the first hour following an event must still be addressed by the licensee and NRR. The fact that 1-pT-76.4 was considered satisf actorily completed on several occasions l
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1 s with the Jabove described. discrepancies, . demonstrates ' that the 1 test was - inadequate to ensure that the bottled air : system was in ' compliance with TS. Therefore, unresolved item:338,339/86-28-02 will.be considered closed

 "and identified as - a ' violation (338,339/87-19-01) of TS 6.8.1.c. for ' an inadequate. surveillance: procedur TS13.7.7.1 requires'that.the following contro11 room emergency habitability systems shall be operable:
 -(1)' The emergency ventilation system (2) The. bottled airfpressurization system-(3) Two air conditioning systems Based on the above discussions, the bottled air pressurization system was not. fully operable' per TS ~ until August 2, 1987, and as discussed in
 : inspection report' 338,339/87-01, the emergency ventilation system was-inoperable during the months of June.to December.1986. The fact that both systems. were in non-compliance with TS 3.7.7.1 and therefore considered technically inoperable at the same' time for the months of. June through i

December 1986 will: be identified as ~a violation (338,339/87-19-01).

~ The May _4, 1987 letter from L. B. Engle to W. L. Stewart documented several additional findings associated with the control room habitabilit The above violation is being' considered for escalated enforcement and ma be changed based on a review of the' additional finding The , following Inspector Followup Items were identified during the control room habitability survey (see the May 4, 1987 letter for details).

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  (Ocen) - IFI 338,339/87-19-04: NRR letter 5-4-87, ductwork inleakage from chiller roo (0 pen) IFI 338,339/87-19-05: NRR letter 5-4-87, control room ventilation system gauges.

E (0 pen) IFI 338,339/87-19-06: NRR letter 5-4-87, marking control room pressure boundary door (0 pen) IFI 338,339/87-19-07: NRR letter 5-4-87, adequacy of procedure for access control of control roo (0 pen) IFI 338,339/87-19-08: NRR letter 5-4-87, absence of fire dampers in ductwor (0 pen) IFI338,339/87-19-09: NRR letter 5-4-87, system descriptions, station procedures, etc., should reflect actual acceptable operational configuration .(0 pen) IFI 338,339/87-19-10: NRR letter 5-4-87, emergency filter unit in leakag _ - _ _ _ - _

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10 (0 pen) IFI 338,399/87-19-11: NRR letter 5-4-87, air handling units and emergency filtration unit not operating as designe (0 pen) IFI 338,339/87-19-12: NRR letter 5-4-87, additional makeup air entering control room envelop '

   (0 pen) IFI 338,339/87-19-13: NRR letter 5-4-87, differential pressure should be measured with respect to the two air chiller rooms and label gauge (0 pen) IFI 338,339/87-19-14: NRR letter 5-4-87, modify technical specification (0 pen) IFI 338,339/87-19-15: NRR letter 5-4-87, resolve comments on procedure . ESF System Walkdown (71710)

__ The following sel.ected ESF system was verified operable by performing a walkdown of the accessible and essential portions of the systems on July 14,198 P-31.2A " Valve Checkoff Auxiliary Feedwater" - The inspector observed the following items which were discussed with the license The hose connection upstream of 1-FW-173 labeled as 1-FW-299 was leakin In the turbine driven feedpump room, 1-FW-283 isclation valve to 1-FW-PI-100A was missing from the valve checkoff lis No violations or deviations were identifie . Operational Safety Verification (71707) . By observations during the inspection period, the inspectors verified that the control room manning requirements were being met. In addition, the inspectors observed shift turnover to verify that continuity of system status was maintained. The inspectors periodically questioned shift personnel relative to their awareness of plant condition , Through log review and plant tours, the inspectors verified compliance with selected Technical Specification (TS) and Limiting Conditions for Operation In the course of the monthly activities, the resident inspectors included a review of the licensee's physical security program. The performance of , i various shifts of the security force was observed in the conduct of daily ! activities to include: protected and vital areas access controls, l searching of personnel, packages and vehicles, badge issuance and I retrieval, escorting of visitors, patrols and compensatory posts. In addition, the resident inspectors observed protected area lighting,

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! 11 p"otected and vital areas barrier integrity and verified an interface between the security organization and operations or maintenanc On a regular basis,_ radiation work permits (RWP) were reviewed and the specific work activity was monitored to assure the activities were being conducted per the RWPs. On July 14, 1987, RWP-87-2133 for the replacement of Unit 2 quench spray recirc pump seal was reviewed in detail. Selected radiation protection instruments were periodically checked and equipment operability and calibration frequency was verifie The inspectors kept informed, on a daily basis, of overall status of both units and of any significant safety matter related to plant operation Discussions were held with plant management and various members of the operations staff on a regular basis. Selected portions of operating logs and data sheets were reviewed dail The inspectors conducted various plant tours and made frequent visits to the Control Room. Observations included: witnessing work activities in progress; verifying the status of operating and standby safety systems and equipment; confirming valve positions, instrument and recorder readings, annuciator alarms, and housekeepin On June 28, 1987, while conducting a tour of the Unit I control room, the inspector observed alarms annunciated in the control room for the outside recirculation spray pumps (0RSP) seal head tanks. These alarms indicate either a high or low level condition existing in the seal head tanks. The inspector questioned the operators as to whether the alarms were for a high level or low level and determined that no one knew the actual status of the ORSP seal head tanks. The condition of the unit at the time was Mode 3 in the process of a startup following the refueling outag The ORSP are required to be fully operational per T.S. 3.6.2.2 in Modes 1, 2, 3 and 4. Therefore, the licensee had entered Mode 4 and then Mode 3 without knowing the exact status of the ORSP. The inspector requested the licensee investigate the actual status of the seal head tanks and determine whether or not the ORSP were operational. The licensee was able to determine that the "A" pumo seal head tank was a high level alarm which was considered acceptable .i the "A" ORSP was considered operationa The "B" pump seal head tank, however, was determined to have a low level and the licensee was unable to fill the tank, indicating either a failed diaphragm in the tank or a failed lower sea The licensee assumed that the diaphragm had failed since this had occurred previously and proceeded to develop a Justification for Continued Operation (JCO) to allow the unit to continue with the startu The licensee completed the JC0 on June 28, 1987, which determined that the ORSP was operational with the seal head tank system degraded. Attached to the JC0 was a 10 CFR 50.59 safety evaluation concluding that an unreviewed safety question associated with a degraded ORSP seal system did not exis This JC0 ana 10 CFR 50.59 were reviewed and approved by the safety committee. The licensee continued with the startup until a reactor trip occurred from 18% power on June 29, 198 _ _-_ __ - _ _ - _ _ _ - _ - _ _ -- __

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On June 30,.the licensee commenced a repair of the "B" 0RSP seal head tank system and discovered that the diaphragm was intact, but the lower of the two shaft seals had failed. The licensee has informed the inspector that both the "A" and "B" seal. head tank systems are now fully operational and theyf are continuing .to discuss che seal problems with both the pump and seal vendors. The. licensee has committed to provide the inspector. with information. from their conversations with the vendors which will. certify that the "B" 0RSP was fully operations; with the seal system in a degraded' condition. Until this information can be reviewed and verified by the inspectors, this item will be identified as Unresolved Item (338/87-19-03).

Several events occurred during the licensee's attempt to restart from the Unit I refueling outage and the Unit 2 outage to fix the "C" RCP leaking seal package in Ma These events relate to mode changes or fuel alterations with equipment not fully operational per These apparent mode change violations are listed as follows:

(1) Based.on the review of a licensee deviation report and LER 87-11, the inspector discovered that the licensee had commenced core alterations, which is similar to a mode change, while in Mode 6 with a less than fully operational charging pump as required by T.S. The
 "C" . charging pump was aligned to the IJ electrical bus while the IJ  '

Emergency Diesel Generator (EDG) was inoperable. The charging pump was capacle of being operated if it had been required to operate with power supplied from the normal electrical power supply. However, it would not have started if offsite power had been lost until it was transferred to the 1H bus which had a fully operable EDG. Therefore, even though this is an example of a personnel error causing a violation of T.S. , the safety significance was mino (2) Inspection Report 87-15, section 11, described an event where the licensee changed modes from 6 to 5 with a questionably operable '. pressurizer code safety valv This event was not identified as a violation based on the minor safety significance and other circumstances associated to the event (see inspection report 87-15 for details). This event occurred on May 26, 198 (3) Based on a review of the reactor operator's log, a licensee deviation report and LER 87-05, the inspector discovered that the operators on Unit 2 entered Mode 3 with all three auxiliary feedwater pumps in a condition with no automatic start capabilities. The motor driven pump's controls were in pull-to-lock and the Terry Turbine pump controls were placed in the closed position. This situation occurred on June 1 while Unit 2 was restoring for the "C" RCP seal replacement outag Since the pump controls prevented the auxiliary feedwater pumps from automatically starting they were technically inoperable by .3.2.1. T.S. Table 3.3-3 requires the automatic actuation logic for i the auxiliary feedwater pumps to be operational in Modes 1, 2 and 3.

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, Therefore, the licensee entered Mode 3 with technically inoperable auxiliary feedwater pumps. However, the safety significance is minor since the. pumps could have been started manuall (4) As discussed above, the licensee entered Mode 4 and then Mode 3 with alarms annunciated in the control room indicating a possible problem on the outside recirculation spray pumps. T.S. 3.6.2.2 requires these . pumps to be fully operational in Modes 1, 2, 3 and 4. Since the operators were not knowledgeable of the condition of the ORSP seal head tanks and the licensee is continuing to conduct an engineering evaluation including conversation with the pump and seal vendors to ensure the pumps were in fact fully operational, it is clear that the unit entered Modes 4 and 3 without the operator knowing for certain that the ORSP were fully operable. The licensee has been able to demonstrate that the pumps would perform based on the previous surveillance test results and is in the process of certifying that the pumps will perform their intended safety function without fully operable seal package Therefore, the safety significance is minor, however, this is another example of. a potential mode change violatio These four examples listed above indicate a potential problem with lack of sensitivity to changing modes without fully operationally T.S. related equipment. Even though the safety significance appears to be minor for each case and two were identified and reported by the licensee, the fact that four similar types of T.S. violations occurred around the same time indicates a need to address the problem as a whole to determine if there is a root caus Items 1 and 3 have been determined to meet the criteria of 10 CFR 2 Appendix C for consideration of licensee identification and will therefore will be identified as Licensee Identified Violations (LIV 338,339/87-19-17 and LIV 338,339/87-19-18). Item number 2 was discussed in inspection report 87-15. Finally item number 4 is waiting resolution of the j unresolved item discussed abov On August 2,1987, at 1830, a deviation report was written as a result of a survey done in the decon building basement. The area was identified as a 2 REM /hr general area, which did not meet the requirements of T. S. 6.1 because the area was not properly posted and locke The area identified as a cause of the high radiation was a blank flange on . a spoolpiece of 1-LW-LCU-111 in the decon building basement. A survey was ; required by the '4P o the general area when the flushing of the lines to l the resin hold 1? > k was completed. Procedure OP 20.1, which was used ! for the transfer, 'equires final system flushes to fill the cask. These I flushes should have removed any traces of resin. The inspector has . requested a copy of the final radiation survey and a signed-off copy of OP ! 20.1. This will be considered Unresolved Item (338,339/87-19-02), pending i further review by the inspectors of the signed off procedure, the survey l required when the cask is full by RWP 87-222 ; l j

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,12.~ Operating Reactor Events (93702)
 .The : inspectors , reviewed' activities . associated with the below listed
 . reactor event The, review- included. determination ~ of cause, safety:

significance, performance of personnel and systems, and corrective actio The inspectors : examined instrument _~ recordings, ' computer printouts, operations journal entries', scram reports and had discussions with-operations, maintenance and engineering support personnel-as appropriat '

 .0n' June 29,J1987,.at 10:48 p.m... Unit 1 experienced a turbine trip / reactor trip due to 'a' high-high water. level signal from. the SA feedwater heate , The unit was operating at approximately 18% power, ' in .the' process of starting up.from the_ refueling outage. All the' safety systems operated as

_ required and after determination of.the cause of the turbine trip / reactor trip, the unit was restarted on June'30, 198 The inspector's. review of the event involved discussion.with the operators following the: trip, a review of the post trip' analysis and a review of LER 87-15. The review revealed the licensee's identification of the cause of the high-high water level-in the SA feedwater heater to be an improper valve lineup on. the' feedwater heater water level controls. The improper valve lineup resulted from a - tagout which was supposed to have been-cleared but still had tags hanging which isolated instrument air to the feedwater heater level control valves, This' isolatton caused the normal level . control valve to be closed preventing water removal from the SA-heated via the normal path. The isolation also caused _ the high level divert valves to fail open, however, one of the manual isolation valves ' associated with the high level divert was improperly closed preventing water removal via the high level divert path. Therefore, the water level was allowed to continue to increase in the heater until the high-high water level turbine trip signal was receive The tagout associated with the problem was supposed to have been cleared sometime prior to the startup but tags associated with the tagout appear to have been rehung in violation of the' licensee's tagout procedure The licensee had also deviated the valve lineup procedure for the SA ; feedwater heater level control system to delete the positioning of valves which were under the control of the tagout. Therefore, the only assurance the- licensee had that the system was aligned properly was the proper ; adherence to the tagout procedure. The licensee is continuing to l investigate the problem and has initiated a Human Performance Evaluation System (HEPS) evaluation of the apparent failure to follow the administrative procedures for removing danger tags and returning valves to service. Since the problems associated with this event are on.non-safety related equipment and procedures, the failure to follow procedures will not be considered a violatio The inspector considers the event significant since it resulted in a reactor trip and a challenge to the safety system Therefore the inspector requested the licensee submit an update to LER 87-15 addressing i

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p their HPES - evaluation;- determination of- root cause and final corrective - actions. . The licensee has committed to provide Ethis supplement' to LER 87-25. .The inspector will' review the licensee'sL evaluation and corrective actions in the closeout of.LER 87-1 On July 15 Unit 1 experienced a . steam generator tube rupture' event. The - unit was manually tripped by the' operators and safety' injection initiated automatically 'approximately 20 seconds ;later. A~. notification of unusual event was initially-declared and the event was upgraded-to alert status 15:

  ' minutes later. By 1.:30- pm the operators had placed the unit in mode' 5
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At the end' of this inspection period, the licensee was in day 35 of the tube. rupture outage with steam generator eddy current inspections still-being performed. The. cold leg side of the' ruptured tube was removed from the C steam generator on August'12 and sent to Pittsburgh to. be. examined

  ' by Westinghouse. This examination will~ attempt ' to determine the root cause:of the tube rupture. The unit is expected to start up in lat September following the completion 'of the eddy current inspections and'
  -their.._results and the review.and concurrence by the NR . 13. ; Plant Startup from Refueling (71711)

a. . Dntrol Rod Drop Time The inspector witnessed ' portions of' l-PT-17.2, Rod Drop Time, from the control room and from .the control rod drive' room. The test was

   . performed on June 28, 1987. The inspector confirmed that all prerequisites were satisfied prior to beginning testin ' Rod drops were timed using a Nuclear Quality Controlled strip chart recorder with calibrated speed, as well as a 60 cycle per second station voltage signal superimposed on the rod position indicatio It was apparent from an initial . inspection of the strip chart traces that no control rod drop times approached the Technical Specification limit of 2.2 seconds for dashpot entry. Subsequent detailed analysis
   .by the licensee showed the maximum rod drop time to be 1.8 seconds for Bank A control rod 8- RTD Cross Calibration

The portion of 1-PT-121, RTD Cross Calibration /RTO Calibration performed above 540 degrees F Tavg was witnessed by the inspector on June 28, 1987. Results of the resistance check, performed previously in Mode 5, were reviewed. No problems were identified with the test or test result _ - - _ _ - _ _ _

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             . The hydrostatic test of the primary system was completed with no problems at 8:50 p.m. on June 28, 1987. The inspector verified that
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the following surveillance tests were completed: 1-PT-41.3 " Safe Shutdown Equipment Control Location Verification"

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1-PT-34.3 " Turbine Valve Freedom Test" 1-PT-36.7.2 " Reactor Trip from Turbine Trip Response Time Test" 1-PT-60.2 " Containment Air Temperature" 1-PT-52.2A " Reactor Coolant System Leak Rate" Identified leakage was 1.09 g.p.m. unidentified .021 g. { l 1-PT-30.1 "NIS Functional Check prior to Startup" i ' 1-PT-41.1 " Auxiliary Shutdown Panal Monitoring Instrumentation - , Channel Check" The shutdown banks were pulled at 12:30 a.m. on June 29, 198 Control Bank "D" was inserted when the reactor f ailed to go critica The primary system was diluted with 1,000 gallons of primary grade water and the reactor was brought critical at 144 steps of the "D" control bank on 3:09 Startup Physics Testing The inspector witnessed the intermediate and power range channel functional tests, the all-rods-out boron endpoint determination, and . the moderator and isothermal temperature coefficient portions of 1-PT-94.0, Refueling Nuclear Design Check Tests. The inspector also ' reviewed the initial critical condition predictions performed using 1-0P-1C, Estimated Critical Position. No problems were identifie m The measured all rods out boron endpoint was 1969 ppm, well within the administrative model check criterion of 400 pcm (about 40 ppm) of the design valvue of 1995 ppm. Isothermal temperature coefficient was determined from the most conservative portions at constant boron concentrations of two heatups and cooldowns. The resulting average measured moderator temperature coefficient (MTC) was +1.24 pcm/ degree F, satisfying the test acceptance criterion that MTC be more negative than +6 pcm/ degree As required by 1-PT-94.0, the zero moderator * coefficient was extrapolated to 70% full power according to procedure 1-PT-94.10, and verified to be negativ No violations or deviations were identifie , _ _ _ _ _ _ _ _ _ _ _ . _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ . _ _ _ _ _ _ _ . _ _ _ _ _ . _ _ _ .

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l 1 Design Change Modifications (37700) See Inspection Report 338,339/87-15 ,.oncerning design change modifications for previous review.

, The inspector verified' that the design changes were listed on the I required 10 CFR 50.59 annual report to the Nuclear Regulatory Commission. The jumper' log was also reviewed for Unit No violations or deviations were identifie . Post. Outage Startup Proble.ms The licensee has experienced several problems during the startup of Unit 1 refueling outage. These problems have either prevented the unit from starting up or have prevented the unit from exceeding certain low power levels and required shutdowns to fix the problems prior the unit l' being able to achieve full power. Several of these problems are discussed l in the inspection report. The following is a list of the event ) On June 21 the A Reactor Coolant Pump (RCP) tripped due to an electrical ground on the motor. The A RCP motor had just completed the five year inspection during the refueling outage. Following the outage the pump had only operated for approximately an hour before developing the groun ) During the repair of the A RCP the' licensee inadvertently voided the vessel head and the steam generator tubes (See Inspection Report 87-21) 3) On June 29 Unit 1 experienced a Reactor trip / Turbine trip from 184 power. The root cause of the trip was an improperly performed tagout and isolation of the high level divert valves (See Section 12 for details).

4) On June 30 the licensee was unable to exceed approximately 24?s power due to a stuck shut main feedwater line isolation valv The unit had to be shut down and cooled down to approximately 205 degrees F to allow repair of the valv . 5) On July 7 the licensee discovered a problem with the B MSR stop ' valve. The unit could not exceed approximately 50?; power without potentially damaging the turbine. The unit was shut down on July 10 l to replace the valve (See Section 8 for details).

- 6) On several occassions during the Unit I startup from the refueling outage and the Unit 2 startup from the RCP seal replacement outage in May 1987, the licensee potentially violated TS 3. The apparent violations were caused by the licensee changing modes with questionable operable or inoperable TS required equipment (See Section 11 for details).

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The licensee has initiated an investigation into each of these items along with other items that they have identified . This study will look at the cause of each of the items and determine if there is a potential for a common cause associated with the items. This investigation will abo include a HPES evaluation. The potential common cause is identified a~s'an Inspector . Followup Item (IFI 338,339/87-19-16) pending review of the licensee's evaluation p

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