IR 05000498/1989023

Insp Repts 50-498/89-23 & 50-499/89-23 on 890701-31.No Violations Noted.Major Areas Inspected:Plant Status,Onsite Followup of Plant Events,Actions on Previous Insp Findings, Monthly Maint Observation & Operational Safety Verification

ML20245K374
Person / Time
Site:	South Texas
Issue date:	08/10/1989
From:	Holler E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20245K358	List: IR 05000498/1989023 ML20245K354
References
50-498-89-23, 50-499-89-23, NUDOCS 8908180426
Download: ML20245K374 (15)

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APPENDIX

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U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

NRC Inspection Report: 50-498/89-23 Operating Licenses: NPF-76 50-499/89-23 NPF-80 ( Dockets: 50-498 50-499 Licensee: Houston Lighting & Power Company (HL&P)

P.O. Box 1700 Houston, Texas 77001 Facility Name: South Texas Project (STP), Units 1 and 2 Inspection At: STP, Matagorda County, Texas Inspection Conducted: July 1-31, 1989 Inspectors: J. E. Bess, Senior Resident Inspector, Unit 1 Project Section D, Division of Reactor Projects J. I. Tapia, Senior Resident Inspector, Unit 2 Project Section D, Division of Reactor Projects R. J. Evans, Resident Inspector, Unit 1, Project Section D, Division of Reactor Projects D. L. Garrison, Resident Inspector, Unit 2 Project Section D, Division of Reactor Projects S. D. Bitter, Resident Inspector, Comanche Peak Office of Special Projects D. M. Hunnicutt, Senior Project Engineer '

Project Section D, Division of Reactor Projects

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Approved: M4 / {f O /O '87 J.J. Holler,ChiGf,PfojectSectionD, Division Date ofReactor' Projects Inspection Summary Inspection Conducted July 1-31, 1989 (Report 50-498/89-23; 50-499/89-23)

Areas Inspected: Routine, unannounced inspection included plant status, onsite 1 followup of plant events, licensee action on previous inspection findings, B908280426 090810 PDR ADOCK 05000498 G PNU

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onsite followup of written reports of nonroutine events at power reactor fccilities, monthly maintenance observations, monthly surveillance observations, and operational safety verificatio Results: Within the areas inspected, no violations or deviations were identified. An open item was identified concerning obtair.ing the plant operations manager's signature for maintenance activities (paragraph 3). The licensee's response and followup to a Unit 1 trip on July 4, 1989, and a Unit 2 trip on July 13, 1989, were complete and thorough in identifying the root cause for both trip (paragraph 2). The Auxiliary Feedwater System for both Units 1 (Train D) and 2 (Train B) were inspected. All equipment was in the correct position to support equipment operation, notwithstanding several procedure / drawing errors (paragraph 8). The firewater pump house was inspecte General housekeeping and equipment condition were not being maintained (paragraph 8).

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DETAILS Persons Contacted

• P. L. Walker, Senior Licensing Engineer

• J. Jump, Maintenance Manager

• A. C. McIntyre, Manager, Sbpport' Engineer-

• T. J. Jordan, Manager, Plant Engineer

• 0. N. Niegand, PED / Senior Fire Protection Engineer-

• I. P. Morrow, Superintendent, Buildings Services

• J. W. Loesch,' Plant Operations Manager

• M. A. McBurnett, Licensing Manager

• W. H. Kinsey, Plant Manager-

• M. R. Wisenburg, Plant Superintendent

• J. E. Gieger, General Manager, Nuclear Assurance

• J. R. Lovell, Technician Services Manager

• A. Ayala, Supervisor Licensing Engineer

• K. Khosla, Senior Licensing Engineer In addition to the above, the inspectors also held discussions with various licensee, architect engineer (AE), maintenan:e, and other contractor personnel during this inspectio * Denotes those individuals attending the exit interview conducted on-August 3, 198 . Plant Status At approximately 7:15 p.m. on July 4,1989, with Unit.1 at 100 percent power, a reactor trip occurred when the main generator output circuit breaker opened. The licensee determined that the cause of this event was a shorted relay in the generator breaker trip circui Further investigation indicated that the shorted relay was undersized (125 VDC used in 250 VDC circuit) for its intended application. The licensee will report this incident in greater detail in Licensee Event Report (LER) 89-01 On July 20, 1989, Unit I reduced reactor power to 81 percent when Main

Feedwater Pump No.13 experienced a seal failure and Motor Driven Startup -

Feed Pump No.14 was out of service due to bearing vibration problem )

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On July 26, 1989, Unit I reached 100 percent reactor power and remained at that power level until July 29, 1989, when the power level was reduced to 70 percent due to problems with Main Feedwater Pump No. 32 (high vibration) and Startup Feedwater Pump No.14 (failed inboard seal). At ,

the end of this inspection period, Unit I was operating at 78 percent i reactor powe l

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Unit 2 began this inspection period at 100 percent reactor power. On l July 13,1989, at 8:02 p.m. , Unit 2 experienced a turbine / reactor-trip due 1 to a. failure of one of. the two main transformers. An "A" phase  !

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fault-to ground was identified as the cause of the transformer failur Recovery efforts concentrated on isolating the damaged transformer and returning to power generation at 50 percent of rated electrical . outpu The reactor was again brought critical on July 10, 1989. At the close of this inspection period, Unit 2 remained stable at 65 percent reactor ,

powe Reactor power was limited by the maximum output current of !

20,000 amps on the remaining transformer. . (

I Onsite Followup of Plant Events (93702)

On July 4,1989, at 7:15 p.m. , Unit I tripped from 100 percent reactor power. The trip occurred when the main generator output circuit breaker opened. The reactor tripped on over temperature-delta. temperature. The plant safety systems responded as designed and no post-trip transients occurre '

The licensee investigated the cause of the event.and determined that an auxiliary relay in the generator breaker trip circuit had shorte ;

Troubleshooting of the trip circuit, which operates at 250 VDC, indicated that the shorted relay was rated at 125 VDC. Over a period of time, the

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undersized relay deteriorated and subsequently shorte An investigation of documentation associated with prior maintenance and construction activities on the main generator was performed to determine the source of the 125 VDC rated relays installed in 250 VDC circuits. The results of the investigation revealed that no maintenance activities had been performed on the generator breaker circuits which would have resulted in char.ging relays to the 125 VDC models. The licensee suspects that the original relays received from the supplier were 125 VDC models instead of the 250 VDC models specifie All 125 VDC relays in the generator breaker trip circuits have been replaced with the correct 250 VDC models. The licensee also verified that the correct relays were installed in the Unit 2 generator breaker trip circuits. The licensee will report this event in greater detail in LER 89-015. The inspectors will continue to monitor the licensee action On July 13, 1989, at 8:02 p.m., Unit 2 received a reactor trip and turbine trip initiated by a main transformer lockout. The lockout. caused a' loss of all auxiliary buses and a loss of Train "A" engineering safety feature (ESF) power, resulting in a Train "A" loss of offsite power (LOOP). The licensee operates with one ESF train powered from the auxiliary bus (onsite power) and two ESF train powered from the standby bus (offsite power). The Train "A" diesel generator started and all ESF equipment operated as designed. All four trains of auxiliary feedwater (AFW) actuated on low steam generator water levels. ' Reactor coolant temperature was maintained on natural circulation using AFW and steam generator power operated relief valves (PORVs). The main i

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transformer lockout was caused by.a bursting of the Main Transformer 2A l cas The main transformers were electrically isolated and electric power l was restored using the Unit I and Unit 2 standby transformer After HL&P completed its recovery efforts, an "A" phase fault-to ground i was identified as t.he cause of the transformer failure. The recovery l efforts were monitored by the inspector and included performing damage

! assessment walkdowns, reviewing trip logs, and establishing a long-term action plan to prevent recurrenc HL&P has arranged to replace the damaged transformer, manufactured by McGraw-Edison, with a compatible' transformer manufactured by Westinghous In the interim, HL&P plans to move one of the two Unit 1 transformers to Unit 2 after Unit I shuts down for a 55-day refueling outage on August 4, 1989. The damaged transformer will be returned to the manufacturer for refurbishing and then returned to the STP site as a spare sometime in the first quarter of 1990. Unit 2 is.being operated at approximately 65 percent reactor pewer, limited by the maximum current capacity of 20,000 amps for the remaining main transforme In a letter dated June 28, 1989 Control Cbmponents Inc. (CCI) notified

.HL&P of a potential significant deficiency concerning the design of the atmospheric dump valves (ADV) supplied by CCI to STP. This letter was issued to modify the conclusion in another letter issued on March 27, 1989, in which CCI addressed the applicability of the failure of the ADV at the Palo Verde Station to open. The ADY at Palo Verde are similar in design and rely upon the same principal of operation as those at STP. The March letter indicated that there was sufficient' actuator force to overcome a potential high load required to open the subject valv According to the June letter, this conclusion was erroneously based on the assumption that the capability of the actuator wass 20,000 pounds. The 20,000 pounds was in error :;ince the actual maximum actuator load available is 13,620 pounds. The worst case actuator load required was calculated to be approximately 14,250 pounds. Therefore, CCI conservatively concluded that.the thrust available from the electro-hydraulic actuator was 630-pounds less than that required to operate the valve. HL&P initiated an investigation'to determine the operability status of the steam generator PORVs at STP. The inspectors 'j reviewed these effort .

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It was determined that eight nuclear power plants have installed a total of 49 ADV of a design similar to STP's. Of these ADV, nine have failed to operate on different occasions because of excessive leakage across the ]

piston ring. These nine failures occurred over 126 valve years. STP, Shearon Harris, and Vogtle have essentially identical ADV and similar )

actuators with a total operating experience of about 18 valve years, with j no failures attributable to this cause. The CCI " worst case" calculation '

was found to contain the following conservative assumptions:

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Steam flew into the bonnet area was assumed through the maximum 5 mils clearance possible from the piston ring to plug around the l

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l entire circumference of the 31ston ring. The flow calculated in this

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manner is over two times hig 7er than measured in any ADY at Palo i Verde, where extensive testing was done following the failure of the

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ADV to ope *

The flow coefficient assumed for the pilot valve on ADV was 15 percent lower than the nominal expected flow coefficien I

Packing friction was conservatively estimated by assuming the design torque on the packing nuts even though torque drops off rapidly as  !

the ADV is stroked. The piston ring friction was calculated using the upper range of published friction coefficients while the vendors'

test data supported a lower valu Unit 1 experienced a reactor trip on July 4,1989, and all four PORVs opened when called upon in the post-trip period. Unit I had been operating at essentially full reactor power for approximatEly 121 day This experience verified that the PORVs were operable. Unit 2 had been operating at full reactor power for 18 days when a full load rejection test was performed with successful operation of the PORV Based on the factors listed above, the licensee concluded that continued i operation would be justified if surveillance testing would be performed on a monthly basis at a main steam pressure of no less than 1050 psi Verification of operability on a monthly basis until the valves are modified should provide reasonable assurance that the safety functions and regulatory criteria are met. The licensee olans to modify the valve internals to reduce the maximum potential load required to open the valve j as soon as it becomes feasible but in no case later than November 30, '

199 No violations or deviations were identified in this area of the  !

inspectio j Licensee Action on Previous Inspection Findinos (92701)

l (Closed) Open Item 499/8870-01: This item concerred completion of the licensee's review of applicable ASME Code N-5 data packages. The inspector selected 10 of the 75 Bechtel Master N-5 data packages and 26 of the 161 associated Ebasco N-5 data packages for review. The review determined that the selected N-5 data packages were in order. The N-5 packages had been reviewed by the licensee and an'ASME Code inspecto This item is close . Onsite Followup of Written Reports of Nonroutine Events at Power Reactor facilities - Unit 1 (92700)

(Closed)LER88-01: " Control Room Ventilation Actuation to Recirculation Mode Due to a Hich hcl and Ammonia Trip on a Toxic Analyzer" - Unit 2 On December 17, 1988, with Unit 2 in Mode 6 (refueling) during initial

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reactor core fuel loading, an automatic actuation of the control room ventilation to recirculation mode occurred. The actuation resulted from a high level trip of the hydrochloric acid (hcl), ammonia, acetic acid, and-vinyl acetate channels on one of the two toxic gas analyzers (analyzer).

The licensee determined that the ESF actuation was caused by an analyzer malfunction, specifically, on improper rezeroing during an automatic rezero cycle. The licensee determined that a low nitrogen' flow condition was caused by nccasional nitrogen starvation to the analyzer during its automatic rezero cycle. The design of the analyzer nitrogen supply was reviewed. The licensee increased the nitrogen reference gas supply capacity under Construction Work Request (CWR) No. 4895, Maintenance Work Request (MWR) No. 73533, and Work Request (WR) No. HE-47768. The design indicated that sufficient nitrogen sample gas flow would be available to support simultaneous nitrogen reference gas sampling by both analyzer This design change has been installed and implemented on Units 1 and Testing verified operability of the ESF, non-ESF, and loss of power / malfunction operations of both analyzers. This item is close (A subsequent malfunction of an analyzer was reported in Unit 1 LER 89-11

" Actuation of Control Room Ventilation to the Recirculation Mode Due to a Malfunction of a Toxic Analyzer." This subsequent malfunction is discussed in the paragraph below (Unit 1 LER 89-11).)-

(Closed) LER 89-11: " Actuation of Control Room Ventilation to the Recirculation Mode Due to a Malfunction of a Toxic Analyzer" - Unit 1 On April 12, 1989, with Unit 1 in Mode 1, an automatic actuation of.the control room ventilation to recirculation mode occurred. The actuation resulted from a malfunction signal from one of the two analyzers. The licensee determined that the ESF actuation was caused by a malfunction alarm that occurred on loss of flow while the toxic. gas analyzer.was taking an hourly reference gas sampl At the time of the malfunction alarm, the redundant analyzer was also drawing a nitrogen reference gas sample. The nitrogen reference gas supply did not have sufficier' capacity to maintain adequate flow to both analyzers when both analyzers attempted to draw nitrogen sample gas simultaneously. This condition was sensed and alarmed by the I malfunctioning analyzer. Each analyzer typically drew a nitrogen l reference gas sample at a different time each hour. However, the j analyzers timebases are independent and cannot be synchronize ;

Therefore, the remote potential existed for overlapping _ nitrogen reference j gas sampling.

The cause of the analyzer malfunction signal was inadequate design. The

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licensee increased the nitrogen reference gas supply capacity to ensure-that sufficient nitrogen sample gas flow will be available to support l simultaneous nitrogen reference gas sampling by both toxic gas analyzer ,

l Thee design of tbt analyzers actuation circuitry was changed in accordance i with WR HE-80625. TM installation of the analyzer actuation circuitry l work was completed under CWR No. 5373. This design, as installed, l

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l requires a malfunction of both analyzers to initiate actuation of the

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control room heating, ventilating, and air conditioning (HVAC) to the recirculation mode. This design has been installed and tested on Unit Testing verified operability of the ESF, non-ESF, ar.d loss of

power / malfunction operations of both analyzers. This item is closed.

l l No violations or deviations were identified in this area of the

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inspectio . Monthly Maintenance Observations (62703)

The purpose of this inspection was to ascertain that maintenance activities were conducted in accordance with approved procedures, Technical Specifications (TS) - and appropriate industrial codes and standard The inspectors observed portions of those corrective maintenance activities that were directed toward resolving the cause of a spurious Unit 1 pressurizer low pressure bistable trip. While at full power, the Channel 4 bistable tripped and remained tripped for 4 minutes before clearing itself. All other plant indications remained normal during this period; no cause for the bistable trip was evident. The bistable was promptly declared inoperable and tripped in accordance with plant T WR BS114627 was submitted to the Instrumentation & Control (I&C)

Department to request an investigation of the cause of the bistable tri j Work Order 89032598 was then generated which contained instructions j that called for obtaining numerous voltage readings in the instrument loop. These values were evaluated in an effort to determine the cause of the proble During the performance of this initial troubleshooting, the inspector determined that: ,

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The troubleshooting was conducted in accordance sith the instructions i in the work packag *

The troubleshooting did not violate any limiting condition for i operation (LCO). l

Redundant channels were operable during the troubleshootin *

The required administrative approvals were obtained before initiating i the wor I

The procedure appeared to adequately address the scope of the wor Because the results of the initial troubleshooting were inconclusive (all ..

laced the lead-lag j voltage card (card). A revision to the work order was made rep (Revision 1) which readings were normal), the I&C Department <

called for replacing and calibrating the suspect card in the protection--

cabinet. Before beginning work, the I&C technician noticed that several l

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steps were missing from the ap) roved Revision 1 procedure. The additional  !

necessary steps were added as levision 2 to the work orde ~

After obtaining permission from the shift supervisor to initiate the 2 troubleshooting, the I&C technicians procured the replacement card and  !

began the switch lineup in accordance with the procedure. Shortly after  ;

performing several of the steps immediately prior to replacing the card, ' !

one of the technicians ~ noticed that a particular step could not be "

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performed because the master test card test switch had been placed and left in the TEST position. This had been done in accordance with the original work' instruction. Work was stopped while the technicians .

resolved this discrepancy. - This step was eliminated with no effect on the i procedur j After again obtaining permission from the shift supervisor to perform the '

procedure, the I&C technicians resumed work. While the technicians were preparing to-remove the faulty card, the Quality Control (QC) inspector noticed that the replacement card had a crack in its frame. This QC ,

inspector was present because of the holdpoint that had been placed in the  !

procedure. This hold point called for the QC inspector to inspect the materisl and card configuration prior to installing the car After obtaining a replacement, the technicians installed the card, calibrated the circuit, and restored the channel to its normal operable stat ,

The inspectors monitored portions of the I&C activities pertaining to the l card replacement. These activities included generating, approving, and revising the procedure; obtaining the administrative approval to perform ,

the work; briefing the control room personnel; obtaining the (first) new card from the warehouse; and directly monitoring various switch j!

manipulations in the cabinets and on the main control boards. During this inspection, the inspectors determined that:

The card replacement activities were conducted using the instructions in the work package. This is evidenced by the fact that the I&C .

technicians detected errors in the procedur !

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Quality control points were established and observed. The QC ;

inspector noticed the defect in the card prior to its being installe ;

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The work activities were accomplished by knowledgeable personne *  ;

TS LCOs were not violate '

The inspectors did note one weakness. This involved the area of administrative approval for performing work. The revised work package (Revisions 1 and 2) called for obtaining the plant operations manager's  !

signature, in the space where the shift supervisor signs, if the plant is in Modes 1, 2, 3, or 4 during a channel calibration. However, the plant

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operations manager's signature was not obtaine Instead, only the shift supervisor signed in the appropriate block. The inspectors identified the following concerns to the licensee:

The signature block whms the plant operations manager may be required to sign has h words " Shift Supervisor" under i Therefore, because he requirement for the plant operations manager to sign is buried in the prerequisites of the procedure (1 PSP 05-RC-0458) and because the si Operations Manager - if required" (gnature or similarblock does under wording) not have it, the " Plant shift supervisor could miss the requirement to obtain the necessary signatur *

If the plant operations manager were to sign as required, it is possible that an I&C technician might see the signature, assume that it is that of the shift supervisor, and possibly begin work without ever contacting the shift superviso *

The shift supervisor, as observed by the inspectors, did not indicate that he was signing "for" the plant operations manage The licensee stated that a rev.'sion to the procedure will be implemented to delete the requirement for tne plant operations manager signatur This concern will be identifieo as Open Item 498/8923-01. This item will remain open pending the licensee's implementation of the revision to the procedure as described abov In summary, the inspectors were satisfied that corrective plant maintenance is being properly accomplished. With the exception of the open item identified above, there were no discrepancies. No violations or deviations were identified in this area of the inspectio . Monthly Surveillance Observations (61726)

The purpose of this inspection is to ascertain, by direct observation of licensee activities, that surveillance of safety significant systems and components were being conducted in accordance with TS and other requirement During this inspection period, the inspectors witnessed the performance of the following safety-related surveillance tests:

Department Procedure N Title I&C 1 PSP 13-RC-0451, Response Time Test, RCS Revision 1 Temp Loop 1 (T0451)

I&C 1 PSP 13-RC-0462, Response Time Test, RCS Revision 1 Temp Loop 2 (T0462)

ISC IPSP13-RC-0473 Response Time Test, RCS Revision 1 Temp Loop 3 (T0473)

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I&C 1 PSP 13-RC-0410, Response Time Test, Revision 1 Delta T and T Average Loop 1 (T-0410)

Electrical IPSP06-PK-0003, 4.16 KV Class IE Revision 3 Undervoltage Relay Channel Calibration /TADOT

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In the witnessing of the I&C department's performance of the RCS RTD time response test, the inspectors verified that:

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to test initiatio *

The test equipment used was in calibratio *

The reactor coolcnt system (RCS) resistance temperature detector (RTD) time response testing was being performed on tim TS LCOs were properly met (as required).

The tests were conducted satisfactorily. No discrepancies were identified. A cursory scan of the extensive data revealed no obvious

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j out-of-specification condition j .

In the witnessing of the electrical maintenance department's performance of the 4.16 KV Class 1E undervoltage relay channel calibration surveillance test (Channel 3 of Train B), the inspector verified that: 1 i

The surveillance procedure conformed to TS requirement The required administrative approvals and tagouts were obtained prio l to test initiatio ]

The test equipment used was up-to-date in calibratio l

-* Communications were properly established prior to performing steps involving remotely-located personne ,

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TS LCOs were properly me The test was conducted satisfactorily. No discrepancies were identifie In sumary, no weaknesses in the surveillance test program were identified during the witnessing of these surveillance activities. No violations or deviations were identified in this area of the inspectio _ _ - _ _ _ _ _ _ _ . ___ ___

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• 12 Operational Safety Verification (71707)-

The purpose of this inspection was to ensure that the facility was being'

operated safely and in conformance with license and regulatory requirements'. This inspection also included verifying.that selected activities of the licensee's radiological protection program were being implemented in conformance with requirements and procedures, and that the licensee was in compliance with its approved physical' security pla The inspectors inspected the control room on a daily basis and verified that:

The control room was free from distractions such as nonwork-related reading material Operators were adhering to approved procedures for ongoing-activitie The operability of reactor protective systems and engineered safety components was as require On July 20,1989, Unit 1 Main Feedwater Pump No.13 experienced a seal failure. With the motor driven startup Main Feed Pump No.14 out of service due to bearing vibration problems, Unit I had to reduce reactor power to 81 percent, which is the limitation for operation with two main feedwater pump An investigation into the causes of the seal failure on Main Feedwater Pump No. 13 was ongoing at the close of this inspection perio Preliminary findings indicated that debris from a spare thermowell _ and startup strainer (which had been left in the system after star _ tup) were i the cause of the seal failure. The licensee discovered that a spare

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thermowell, which was installed in the feedwater booster pump combined discharge header, had broken off and was sucked into the suction side of the main feedwater pump. The thermowell was found lodged in the pump impeller when the pump was disassembled. The licensee also found debris identified as parts from the startup strainer. The licensee estimated that approximately 160 square inches of strainer parts were lost in the system. Approximately 50 square inches of strainer parts were retrieve The-licensee assumed that the rest of the strainer parts may have migrated into High Pressure Feedwater heater Nos. 11A and 11B. There is a L possibility that smaller parts may have migrated into the steam generators.

The licensee had decided to open up the channel head in the high pressure feedwater heaters during the Unit I refueling outage (scheduled to start on August 4, 1989) and inspect for foreign debris that may be in and around the tube sheets. Also, the steam generators will be sludge lanced

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to remove all foreign materials during this outage. The' licensee will

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document the results of their findings in Station Problem )

Report (SPR) 89-0552. The inspectors will report any findings in a subsequent inspection repor Tours were conducted throughout various locations of the plant to observe work and operations in progress. Radiological work practices, posting of barriers, and proper use of personnel dosimetry were observe The inspectors verified, on a sampling basis, that the licensee's. security force was functioning in compliance with the approved physical security-plan. Search equipment such as x-ray machines, metal detectors and explosive detectors were observed to be operational. The inspectors noted that the protected area was well maintained and not compromised by erosion or unauthorized openings in the area barrie Train D of the AFW system for Unit 1 was inspected to ensure the system valves, control room control switches, and electrical power supplies were in their correct positions, as required by the system operating procedure and plant drawings. The AFW system, Train D, was compared to-Procedure IPOP02-AF-0001, Revision 9, " Auxiliary Feedwater," and the system piping and instrument diagrams (P&ID). The P& ids used included SS199F00020 No. 1, Revision 15, " Condensate Storage," and SS149F00024 No. 1, Revision 15, " Auxiliary Feedwater." Items observed during the l inspection included:

Steam Trap Blowoff Valve 1MS-0607.was shown as normally open on the P&ID 55149F00024, but was required to be closed per Valve Checklist IPOP02-AF-0001-9. Additionally, Secondary Sampling System Isolation Valve 1AF-0208 was shown as normally closed on the P&ID 55199F00020, but was required to be open per Valve Checklist IP0P02-AF-0001-8. The licensee initiated document change notices to revise the two P& id Condenser Hotwell Dump Line Vent Valve ICT-0123 was incorrectly called Valve ICT-0125. in the valve checklist. An incorrect elevation !

was given for Suction Line Vent Valve 1AF-0326 in Valve i Checklist 1 POP 02-AF-0001-9. The incorrect elevation was given for all three instruments listed in the Instrument Vent Checklist 1P0P02-AF-0001-14. Vendor supplied skid valves were not listed in Valve Checklist 1 POP 02-AF-0001-9. Additionally, the vendor supp. lied valves were not labelled. The licensee initiated a field change request to correct the procedure deficiencie Isolation valve cubicle (IVC) building area Temperature Indicator N1HC-TI-9747 was noted to be reading 107 F, a value above the TS limit (Table 3.7-3) of 101 The Unit 1 control room was i informed. A hand held thermometer was used to' measure local area ,

temperature. The highest reading, near a steamline, was 100 F. The )

licensee initiated a work request to recalibrates the Temperature 1 Indicator TI-974 !

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Other items noted.and. reported to-the. licensee included: AFW Line-Drain Isolation Valve 1AF-0173 had a packing . leak with no maintenance-tag attached, Nitrogen Supply ICT-PCV7714A was missing its identification tag, and the seal for.the Turbine Vent Line Pressure Indicator 1AF-PI-7537 appear'ed damage In general, all valves, centrol switches, and power supplies.were found 'in the. position required to support system operation. All inspection findings'were reported to.the licensee for corrective actions.

f . Train B-of the-AFW for Unit'2 was inspected to ensure the' system valves, control room control switches, and electrical power supplies were,in their correct positions, as required by the _ system operating procedure .and plant '

drawi ngs.~ The AFW. system, Train B, was compared to .. ,

Procedure 2 POP 02-AF-0001, Revision 2, " Auxiliary Feedwater," and th system P& ids. The P& ids used included SS199F00020 No. 2, Revision 13,,

" Condensate Storage," and 55149F00024 No. 2, Revision 11, !' Auxiliary Feedwater." Items observed during theLinspection included:

AFW Storage Tank Loop Seal Isolation Valve 20W-1658 was shown.on P&ID SS199F00020 and was located in the field. Nonsafety-related Valve 20W-1658 was not listed in Valve Checklist 2P0P02-AF-0001-52 The licensee initiated a field change request to add the valve tc the -

valve checklist. ' i-

l Secondary Sampling System Isolation Valve 2AF-0208 was'shown as l normally closed on P&ID SS199F00020 and was listed as closed in the valve checklist. The same valve for Unit I was listed as open in the Valve Checklist 1 POP 02-AF-0001-8. The licensee. initiated a field-change request-to change position of Valve 2AF-0208 from closed to open on the valve checklist in 2P0P02-AF-0001. The P&ID will be revised by a document change notic Both Units 1 and 2 AFW Storage Tanks have local level gauges that-provide tank level indicatio A review of the' Yard Logsheet.:

Form IPSP03-ZQ-0002-4, Revision 9, was performed. . Operations personnel do not inspect the tanks' level locally, but depend on control room indications, which are provided by different instruments -

than the: local level gauge. The licensee should consider adding th gauge to the-logsheet for verification of tank leve During the inspection period, a walkdown of the fire pump house was performed. Items inspected included general housekeeping, equipment- condition, and identification of any potential ~ fire hazards. All items ,

noted during the inspection were reported to the licensee. Items observed' l included:'

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General: housekeeping was not being maintained. Live and dead insects-were located throughout the. building. Trash,noted throughout the building included loose nails, washers, peeled paint, pieces of tape, empty food containers, and dirty oil soaked rags.

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General equipment condition was inspected. Towels were found stuffed in the public address (PA) speaker inside Fire Pump Room No. 2, apparently to suppress the high PA noise level. Abandoned audible and visual alarms were observed on the south side of the buildin The connections to the alarms were hanging loose and were (

disconnected from any power source. One outside door window was cracked. Valve OPW-0129, Potable Water Supply to Fire Water Pump House Isolation Valve, was leaking at the valve flang Valves IFP-0891, Discharge Header Vent, and IFP-0041, Fire Pump Discharge Isolation Valve, had packing leaks. The cover on Electrical Box N0XP1TKSP37 was missing seven of eight bolts. Other 3 electrical panels also had loose or missing bolt *

The flexible rubber sleeve over a conduit on Fire Pump No. I was split lengthwise in several places. A loose communication wire was found with exposed leads. The flexible conduit for cable leading to Fire Pump Loop Isolation Valve IFP-0042 was damaged. The faceplate on Pressure Indicator FP-PI-8609 was cracked. MWR tags were not attached to the above component *

Water from a nearby valve that was undergoing maintenance was noted leaking into the Fire Pump No. 3 battery compartment. The bases of the four batteries were submerged in water, but the electrical terminals were well above the water level. This condition was reported to the shift supervisor, who initiated immediate corrective action Through discussions with Health Physics (HP) personnel, it was determined that the licensee was planning to use new models of respiratory protective equipment. The new model numbers are NPO SAR 101 and SAR 102 Supplied Air Hood Respirator Systems, National Institute for Occupational Safety and Health (NIOSH)CertificationTC-19C-140. These units have a protection factor of 1000. The inspectors reviewed the equipment proposed to be used 4 and found that the protection factors for this equipment were consistent with the values specified by 10 CFR 20, Appendix A, " Protection Factors for Respirators."

No violations or deviations were identified in this area of the inspectio . Exit Interview The inspectors met with licensee representatives (denoted in paragraph 1) i on August 3, 1989. The inspectors summarized the scope and findings of the inspection. The licensee did not identify as proprietary any of the information provided to, or reviewed by, the inspector .. .

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