IR 05000321/1997007

Insp Repts 50-321/97-07 & 50-366/97-07 on 970629-0816.No Violations Noted.Major Areas Inspected:Operations, Engineering,Maint & Plant Support

ML20198H859
Person / Time
Site:	Hatch
Issue date:	09/11/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20198H853	List: IR 05000321/1997007 ML20198H849
References
50-321-97-07, 50-321-97-7, 50-366-97-07, 50-366-97-7, NUDOCS 9709220208
Download: ML20198H859 (46)

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U.S. NUCLEAR REGULATORY COMMISSION REGION 11 Docket Nos: 50 321. 50-366 License Nos: DPR-57 and NPF-5 Report No: 50 321/97 07, 50 366/97-07

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Licensee: Southern Nuclear Operating Company. Inc. (SNC)

Facility: E 1. Hatch Units 1 & 2 Location: P. O. Box 439 Baxley. Georgia 31513 Dates: June 29 August 16, 1997 Inspectors: B. Holbrook Senior Resident inspector J. Canady. Resident inspector W. Kleinsorge. Reactor Inspector (Sections M1.1, M1.2, M1.4 and M1.5)

W. Holland. Reactor Inspector (Sections 0 .1, M1.1, M8.3)

Approved by: P. Skinner, Chief, Projects Branch 2 Division of Reactor Projects Enclosure DO $0$0! o Soo32i G PDR

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EXECUTIVE SUMMARY Plant Hatch. Units 1 and 2 NRC Inspection Report 50-321/97-07. 50 366/97-07 This integrated inspection included aspects of licensee operations, engineering maintenance, and plant support. The report covers a seven week period of resident inspection. In addition it includes the results of announced inspections by two regional reactor inspector Doerations e A good questioning attitude and crew involvement in decision-making was observed during routine operations in the control room, few annunciators were lit and the watchstanders understood why they were in an alarm condition. Observed shift turnovers were informal (Section 01.1).

e Instructions and procedures were provided to the operations personnel to use available means to mitigate potential problems due to hot weather conditions. The health and safety impact upcn1 personnel working in hot weather conditions were adequately addressed (Section 01.2),

e The actions taken by the control room operators for the Unit 1 Torus-to-Drywell vacuum breaker and Rod Position Indication System (RPIS) problems were excellent. Conservative decision making was demonstrated for each of the problems (Section 01.3),

e Maintenance demonstrated persistence in troubleshooting activities and provided good support for the work (Section 01.3),

e During a plant tour, operating and standby equipment appeared to be in good condition. In addition, a Superintendent of Shift's cuestioning attitude and sensitivity to plant equipment conditions curing the tour was good (Section 02.1),

o The operation's pre-job briefing for the performance of the 2A Emergency Diesel Generator (EDG) monthly test was conducted in a professional manner. Plant Ecuipment Operators demonstrated an excellent questioning attitude curing the activities. Operations personnel performed appropriate procedural and administrative actions for out-of-service 2A EDG stator temperature annunciator in the main control room (Section 02.2).

e Overall, plant o)erator performance with respect to monitoring and maintaining the Jnit 1 spent fuel pool level was considered a negative observation. Operator documentation for spent fuel pool pump trips wa: poor. Management actions to correct the problems were appropriate (Section 64.1).

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lbintenance e Maintenance work package documentation for a packing adjustment on the Residual Heat Removal Service Water motor operated valve (IEll-F119B) was complete and provided good craft feedback to planning and control for additional corrective action for this valve (Section M1.1).

e The observed balance of plant on line maintenance was generally performed in accordance with work instructions, procedures, and applicable clearance controls. Safety-related maintenance and surveillance testing evolutions were well planned and executed (Section M1.2).

e One example of a poor work practice associated with contamination control during balance of plant on-line maintenance was observed (Section M1.2).

e Job staging Isolation and(M Valve sub)

lV)port limitactivities for the Unitwere switch adjustment 2 Main Steam thoroughly planned and organize Maintenance management's active involvement and support from Health Physics. Security and Plant Safety were excellent during the work activity. Contingency planning and pre-job coordination for a potential Unit 2 forced outage to repair inboard MSIV limit switches were detailed (Section M1.3),

e An inadequate review by fire protection engineering personnel for a replacement diesel fire pump temperature regulator valve and temperature gage resulted in maintenance rework and prolonged repair for the fire protection system. Fire Action Statements and surveillance requirements of the Fire Hazardous Analysis were me The diesel fire pum]s were appropriately excluded from the scope of licensee's 10 CFR 50.65 program (Section M1.4).

e The Significant Occurrence Report for the primary coolant leak on the Unit 2 Reactor Water Cleanup System heat exchanger identified root causes and made specific reconinendations for corrective actions. The quality of the report was good. Operator response to the reactor coolant leak was satisfactory (Section M1.5).

e The recent recurring reactor coolant leak on the Reactor Water Cleanup System heat exchanger was due to poor quality welds caused by a lack of detailed review for the job scop Poor interface between craft and supervisory personnel contributed to t' a problem (Section M1.5),

e The inspectors concluded that the overall material condition of systems and components and radiological controls of contaminated and high radiation areas in the Unit 1 and Unit 2 torus areas were Enclosure

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goo The upper steel support members for the torus on both Units were in excellent condition with no signs of peeling or rus The lower steel support members contained some minor scars that were not coated. No system or component leakage was observe Although minor examples of discarded materials were observe general housekeeping was adequate (Section M2.1).

e B0P maintenance was subjected to an independent audit, with appropriate action recommended for the identified weaknesses (Section M7.1).

En_qineerina n

e The actions taken for the resolution of the cable divisional separation issues were adequat No discrepancies were identified in the 50.59 evaluation for the temporary modification associated with returning the IB Residual Heat Removal Service Water pump to an operable status and the use of silicon dioxide tape as a barrier material. Adequate engineering oversight was provide The proposed change to the Updated Final Safety Analysis Report was appropriate (Section E1.1).

• Licensee's actions were appropriate for a disparity between the General Electric (GE) core analysis procedure assumptions and the Hatch Unit 1 and Unit 2 Technical Specifications requirements regarding Rod Block Monitor Operability (Section E2.2).

• Engineering and Nuclear Safety and Compliance actions in conducting a detailed review of the Updated Final Safety Analysis Report with respect to a failed main turbine pressure regulator on Unit I was a)propriate. Operator performance to detect and respond to t7e failing pressure regulator was excellent (Section E2.3).

Plant Suonort e A negative observation was identified in that Radchem engineering personnel failed to communicate and coordinate their work activities with operations personnel for the feed and bleed activity associated with the reactor building closed cooling water system (Section R1.2).

e The inspectors concluded that the areas of security inspected met the applicable requirements. The operability test for the security power systems verified that the systems were maintained in a reliable standby condition. The physical modification observed in the security facilities was performed in accordance with the guidelines of the security procedures (Section S2).

Enclosure

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Reoort Details Summary of Plant Status Unit I began the report period at 100% rated thermal power (RTP). On July 1. power was reduced to approximately 88% RTP due to a stuck open torus to drywell vacuum breaker. The vacuum breaker was subsequently closed and the unit was returned to 100% RTP the same day. The unit operated at 100% RTP for the remainder of the report period, except for routine testing activitie Unit 2 began the report period at 100% RTP. Power was reduced to approximately 75% RTP on July 20 for turbine control valve testing, main steam isolation valve (MSIV) limit switch adjustment / repair. MSIV testing, and a control rod sequence exchange. Power was further reduced to approximately 55% this same date due to a relief valve 3roblem on the 7th stage feedwater heater. Power was returned to 100% RT) on July 2 The unit operated at 100% RTP for the remainder of the report period, except for routine testing activitie I. Ooerations 01 Conduct of Operations 01.1 General Comments (71707)

The inspectors conducted frequent reviews of ongoing plant operations. The inspector observed several operations shift turnover meetings in the control room and observed that the turnover meetings involved briefings on unit status and upcoming evolutions by each oncoming crew's Shift Su)ervisor and Operator-at-the Controls. The inspectors observed tlat the briefings of shift personnel were generally informal in that briefing notes were not always used. -For example. in one briefing, the inspectors observed that the reactor operator briefed from a small yellow piece of paper attached to the end of his finger. Although important items were briefed one operator had to recall from memory one or two items which he wanted to discus The inspectors conducted several control room tours and observed each unit's operator-at-the-controls performing evolutions. Few annunciators were lit and when questioned about lit annunciators, operators understood reasons why the anunciators were in alar Also, the inspectors observed operators discussing evolutions involving plant operations. On one occasion..the reactor o)erator, the unit shift supervisor, and the superintendent of slift (SOS) discussed a request to stroke a valve. The inspectors considered that this questioning attitude and crew involvement

)- demonstrated a good operating safety sensitivity. In general, the

, conduct of operations was professional and safety conscious; specific events and observations are detailed in the section belo Enclosure

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01.2 Hot Weather Ooerations Insoection Scone (71707)

The inspectors reviewed De)artmental Instruction (01)

Dl 0PS 56-0293N. " Hot Weatier Operation." Revision (Rev.) 2 and

>rocedure 3450-N34 004-1S. " Lube Oil Stora e and Transfer System."

lev 8. Edition (ED) Observations of lant equipment and activities with potential hot weather prob ems were performe Discussions were conducted with licensee personnel associated with actual or potential hot weather related problems, Observations and Findinas The inspectors observed that the licensee had taken several actions to mitigate the effect of hot weather conditions on plant operations. The inspectors observed during a plant tour on July 30 that the Unit 1 temporary helper chiller was operating and the Units 1 and 2 turbine building roll up doors on the 130 foot (ft) elevation were partially opened with a locked and alarmed, grilled barrier (gate) in the opening for security reasons. This provided added air flow cooling to several systems in the are The inspectors observed that the doors and windows to the Fire Pump House were opened to provide additional air flow. However, the manual louvers not fully opened. The inspectors noted that DI-0PS-56-0293N 3rovided instructions which indicated that the manual louvers s1ould be opened first and then the windows as necessary to maximize the cooling effect. The inspectors informed Control Room supervision of some )artially opened louvers and corrective actions were taken. T1e inspectors were informed by control room supervision that the other equipment described in Dl 0PS 56-0293N was operated as required and no temperature limits had been approache The inspectors reviewed a temporary change to procedure 3450-N34-004-IS. The change was made to allow the arallel operationoftheReactorFeedwaterPumpTurbine(RFhT)oilcoolers on Unit 1. The inspectors were informed by licensee personnel that temperatures for the oil was approaching upper limits with the temperature control valve (TCV) in the full open position and

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the bypass valve around the TCV nearly full open. Parallel o)eration of the oil coolers for Unit 1 RFPTs A and B alleviated tie hot we6ther operational problems. The inspectors were also informed by licensee personnel that oil cooler temperature problems had-not occurred on Unit The inspectors observed that licensee management routinely cautioned personnel of potential effects of hot weather problems on emergency equipment. A heightened awareness was demonstrated Enclosure

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with respect to river level and temperatur Additionally, operating temperatures of emergency equipment, temperature regulating valve response and position, and overall equipment performance was discussed. While the inspectors observed that river level and temperature had not approached the technical specification (TS) limits, they did not observe emergency equipment problems associated with hot weather operation.

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The ins ectors observed.that the Unit 1 toras water was routinely mixed b RHR torus cooling due to water stratification. This resulte in a more representative temperature distribution of water inventor TS limits on torus temperature was not a concer The inspectors observed that the hazards of heat stress were emphasized during pre-job briefings, shift turnovers, and staff meeting Conclusions The inspectors concluded that instructions and procedures were provided to operations personnel for using available means to mitigate potential problems due to hot weather conditions. A heightened awareness for emergency equipment operation was demonstrated. The health and safety hazards associated with working under hot weather conditions were adequately addresse .3 Hot Shutdow1 Reauirements for Unit 1 due to Failure o" Drywell Vacuum Brea cer and Rod Position Indication System (RPLS) Insoection Scone (71707)

The inspectors reviewed TSs. Maintenance Work Orders (MW0s) and the applicable procedures associated with the failure of a torus to drywell vacuum breaker solenoid valve rectifier and the failure of a power supply for the Rod Position Indication System (RPIS).

The inspectors also held discussions with maintenance and engineering personnel. Each failure required entry into a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to hot shutdown action, Observations and Findinas On June 30, while performing a torus-to-drywell vacuum breaker operability test. vacuum breaker 1T48-F323F failed to clos Operations personnel entered the Required Action Statement (RAS)

of TS 3.6.1.8. Suparession Chamber-to-Drywell Vacuum Breaker This TS requires tlat the vacuum breaker be closed within two hours. If the vacuum breaker cannot be closed within the two hour period. then the unit is recuired to be in mode 3 (hot shutdown)

in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and mode 4 (colc shutdown) in 36 hour4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> Maintenance Enclosure

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personnel were contacted to assist in trouble shooting the problem. In an initial attempt to close the vacuum breaker, the operators performed torus venting in accordance with procedure 34S0-T48 002-15. " Containment Atmos)heric Control and Dilution Systems " Rev. 16. The vacuum breater did not close, lhtrogen was added to the drywell in an attempt to close the vacuum breake Maintenance troubleshooting efforts identified and then replaced a blown fuse in control room pa.*1 1H11 P602. The fuse blew again during a subsequent attempt to close the vacuum breake Maintenance personnel discovered that a bridge rectifier was defective. The bridge rectifier was replaced and another fuse was installed. However the vacuum breaker still would not close due to mechanical binding. The operating crew eventually closed the vacuum breaker by pressurizing the drywell and the vacuum breake >

was declared inoperabl Reactor power had been reduced to approximately 88% RT Power was returned to 100% RTP, The inspectors discussed with maintenance supervision the troubleshooting difficulties encountered to identify the proble The inspectors were informed that because fuses had blown on two previous occasions, the maintenance crew suspected that the solenoid valve had a ground, but was unable to identify a proble A technician arriving on the next shift recalled a similar problem in the past and recomended troubleshooting the bridge rectifier associated with the solenoid. The bridge rectifier was determined to be the cause of the problem and it was corrected. However, due to mechanical binding, the vacuum breaker was left closed and inoperabl The inspectors reviewed drawing H-17081. Primary Containment Purge and Inerting System sheet 1 of 4. The bridge rectifier circuit was not clearly indicated on the drawing. This observation was discussed with engineering. Engineering personnel indicated that the drawing would be clarifie On July 20. Unit 1 entered a second Technical Requirement Manual (TRM) Action Statement. Section T3.3.3. due to an inoperable RPI which requires that the unit be in Mode 3 (Hot Shutdown) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for an inoperable RPIS. The RPIS became inoperable due to a failed power suply. The operators were unable to select or move control rods wit 1 the inoperable RPIS. However, the manual and automatic shutdown functions'(scram) were still availabl The operating crew performed the required actions of abnormal operating procedure 34AB-C11-002-1S, "RPIS Failure." Rev. 1. ED 1.

Maintenance personnel investigated and re) laced the power supply in accordance with MWO 1-97-1772. Power lad reduced slightly during troubleshooting due to the build up of xeno Enclosure

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5 Conclusions The actions taken by the control room operators were excellent and conservative decision making was demonstrated. Maintenance demonstrated persistence in troubleshooting activities and provided good support for the vacuum breaker and RPIS problem Operational Status of Facilities and Equipment 02.1 Observed Plant Doerational Conditions (71707)

The inspectors conducted a tour of the )lant with the SOS on August 14, 199 Areas or components caserved included:

. Main Turbine Deck

. Unit 2 Reactor Feed Pumps

. Unit 2 Condensate Booster Pumps

. Unit 2 Condensate Pumps

• Instrument Air Compressors

• Unit 2 Reactor Core Isolation Cooling Pump e Unit 2 High Pressure Core injection Pump e Jnit 2 Residual Heat Removal Pumps

. Unit 2 Recirculation Pump Motor Generators

. Refueling Area The inspectors observed that housekeeping in most of the areas was good. In addition, most of the operating and standby equipment appeared to be in good condition. Few oil leaks were noted, with an exception being a Recirculation Pump Motor Generator. Also, the inspectors noted that the SOS vas attentive to plant conditions and took several notes associated with equipment status inde The inspectors considered the SOS's pendent of the inspector questioning attitude and sensitivity to plant equipment conditions to be goo .2 Doerator Performance of 2A Emeroency Diesel Generator (EDG)

Testina Insoection Scope (71707) (92901)

The inspectors attended the operations' pre-job briefing for the performance of surveillance 3rocedure 345V-R43-001-25. " Diesel Generator 2A Monthly Test." Rev. 22. Additionally, the inspectors reviewed temporary modification (TM) 2-97-023. interviewed o)erators and maintenance personnel, examined local EDG panel 2121-P230. and reviewed applicable control room logs Enclosure

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b. Observations and Findinos On July ll, the inspectors attanded the pre-job briefing for the performance of the 2A Emergency Diesel Generator (EDG) monthly surveillance. The pre-job brief was led by the control board operator (CBO) responsible for operating the EDG from the control room. Briefing oversight was provided by the Shift Supervisor (SS). Plant Equipment Operators (PEOs) responsible for local activities at the EDG were in attendance. The inspectors observed the use of a pre-job checklist during the pre-briefing. The inspectors reviewed the checklist and noted that all applicable items c'1 the checklist were covere Personnel in attendance maintained a professional demeano A PE0 asked if an Instrument and Control technician (I&C) would be available to assist in the monitoring of generator stator temperature The PE0 stated that an I&C technician was available durmg the previous monthly EDG surveillance due to the installation of a temporary codification (TM). The SS referred to TM 2-97-023 and made the decision that the presence of I&C was not neede The inspectors obtained a copy of TM 2-97-023 for review. The inspectors' review indicated that Omniguard temperature indicating ,

switch 2R43 K774 provides temperature monitoring, indication, and alarming capability for the 2A EDG generator stator. Three resistance temperature detectors (RIDS) provide input to an Omniguard monitor. The monitor, in turn, )rovides input to a local indicator and to an annunciator in t1e control room. The control room generator stator temperature alarm function is listed in Unit 2 Updated Final Safety Analysis Report (UFSAR)

s Table 8.3-8. The monitor and indicator are inoperable and cannot be repaired due to the unavailability of replacement part TH 2 97-023 provides a means to monitor the 2A EDG generator stator temperature until replacement parts can be obtained for the Omniguard monitor and indicator. The TM specified that links in the RTD circuits be opened and the RTDs be electrically isolated from the monitor. A volt-ohmmeter (vom) was connected to each of three differently installed RTDs. The-three voms were placed in local panel 2H21-P230 for EDG stator temperature monitoring during surveillance and automatic starts. The vom output was converted to a-Centigrade temperature using a conversion chart posted next to the vo During the performance of the 2A EDG monthly test. the PE0s assigned to perform the local aspects of procedure 34SV-k23-001-2S were given copies of the conversion chart'from IM 2-97-023. The PE0s noted that the conversion chart posted on the inside of the local panel had the lead resistance values crossed out with different values entered in red. The PE0s informed control room 3 Enclosure

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supervision of this discrepancy and asked for further guidance, These values were not in agreement with the original values provided by the TM nor were a date, initial, or signature entered for the added values. The inspectors were later informed that I&C technicians had changed the values of the conversion chart following testing of the circuit and inclusion of the temperature compensation value The inspectors examined the voms in the local panel and observed the conversion chart posted on the panel interior door with the added lead resistance values in re Operations supervision made the decision to stop the performance of procedure 34SV-R23 001-2S until the conversion chart values could be validate Engineering personnel recalculated the values for the conversion chart. Procedure 34SV R23 001-2S was successfully performed the following day using engineering validated values on the conversion chart.-

The inspectors verified that the out-of-service annunciator in the control room for EDG 2A stator temperature was labeled and logged per the requirements of procedure 30AC-0PS-009-05, " Control Room Instrumentation," Rev. Conclusions The operations pre-job briefing for the performance of the 2A EDG monthly test was conducted in a professional manner. The PE0s demonstrated an excellent questioning attitude during the briefing and the performance of the 2A EDG monthly test. Operations personnel took the appropriate actions for the "out-of-service" 2A EDG stator temperature annunciato .0 Operator Knowledge and Performance 04.1 Review of Unit 1 Soent Fuel Pool (SFP) and Skimmer Surae Tank Level Problems (40b00) insoection ScoDe (92901)

The inspectors reviewed operator logs, applicable alarm procedures, deficiency cards (DCs) and MW0s dated back to early 1995 with res3ect to continued skinner surge tank low level alarm problems and S P pump trips. The inspectors reviewed procedure 34GO-0PS-030-1S. " Daily Inside Rounds", Rev. 30. and operator rounds which documented SFP level for each shift between May 16 to July 3. 199 Enclosure l

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b. Observations and Findinas On July 2, 1997, the IB fuel pool cooling pump trip)ed. The day shift PE0 discovered that the fuel pool level was a)out four inches low and added water to restore the level to within the normal rang The-IB ) ump was returned to service and a deficiency card was su)mitted to investigate why the low skimer surge tank level alarm did not actuat The inspectors reviewed MWO 1-97 1572, which required maintenance personnel to repair /realace the level switch. During calibratio it was observed that t1e switch setting was low at 47 psig (psig converted to indicate level) and outside of the acceptance criteria of 52 psig. This caused the skimmer surge tank low level alarm to not actuate. The switch was recalibrated to within acceptable limit Procedure 34G0-0PS-030-1S, indicated that the level SFP should be maintained between 22.25 feet and 22.42 feet. The inspectors conducted a review of past SFP level readings to determine the normal trends in level. The inspectors review of a printout of the SFP level for both units was taken from PE0 inside rounds information from May 16, 1997 to July 3. 1997. The inspectors observed that both units' SFP level generally decreased about two inches every six to eight days from normal evaporation. Operator log entries, required by the operator log keeping procedur indicated water was added to maintain an acceptable leve The inspectors observed from operator logs that about two inches of water was added to restore the Unit 1 SFP level to 22.42 feet on June 24. The PE0 inside rounds information indicated that level was maintained for two days. On June 27. the level was recorded at 22.33 feet for one reading and 22.25 feet for the second reading that day. For 11 consecutive readings between June 27 and July 2. the_ level was recorded for no change at 22.25

, feet cr had increased to 22.3 feet for both readings on July 2, with ro water being added. The level was recorded at 22.3 feet about six to eight hours arior to the IB pump trip on July 2. The operators' recording of t1e SFP level was not consistent with the past evaporative rate of the SF The inspectors were later informed that the IB pump had actually tripped twice on July 2. One trip occurred prior to the day shift assuming duties. The irspectors observed that the pump trip was not recorded in the operators' logs. Operators' corrective actions for the first pump trip were to dispatch a PE0 to restart the pump. No investigation was conducted--into why the pump tripped. ' The pump was placed back in service. The SFP decrease of approximately four_ inches _ was not a concern for spent fuel shieldin Enclosure

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The inspectors discussed the pump trip with engineering personne The system engineer suspected that air had accumulated in the piping and may have caused the pump trip. The inspectors reviewed documentation for the maintenance work and observed that a cause for the pump trip was not identifie There were several instances of spurious pump trips and problems associated with level switches. Engineering had recommended )rocedural changes for system fill and vent to correct some of t1e problem The inspectors reviewed o)erator logs and determined that the IB pump had also tripped on iay 16. Water had been added to the SFP and the pump was restarted. The inspectors did not find that a deficiency card was written for this proble The inspectors discussed operator and PE0 performance with operations management. The inspectors discussed the PE0s'

responsibility for monitoring and maintaining the SFP level and that they did not detect a level decrease that resulted in SFP pump trias. Additionally, o)erators returned to service a tripped pump witlout investigating w1y the pump had tripped or documenting the trip in the operators log Operations management stated that the operators' actions did not meet their expectations and initiated a review of the problem. As part of the corrective actions, each shift was briefed on the problem and management expected actions were discusse The discussion included PE0 monitoring of SFP level and when water should be added, operator log keeping, and actions to be taken prior to returning tripped equipment to service. These actions were to be applied to any system problem, Conclusions Overall PE0 performance, with respect to monitoring and maintaining spent fuel pool level was considered a negative observation. Additionally, operator documentation for SFP pump trips was poor. Managenent actions to correct the problems were appropriat Hiscellaneous Operations ?siues (92901)

0 (Closed) Violation 50 321/96-06-04: Failure to Meet TS Surveillance Requirements Prior to Withdrawal of a Control Rod While in Cold Shutdown. The licensee responded to this violation on July 10, 1996, and identified that a less than adequate procedure was the caus Procedure 43G0 0PS-066-05 " Single Control Rod Withdrawal in Shutdown." Rev. 6 was revised to clarify re The inspectors reviewed the revised procedure.quirements. Based upon the inspectors' review of licensee actions, this violation is close Enclosure

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08.2 (Closed) Violation 50-321. 366/96 06-05: Ineffective Corrective Actions to Strengthen the Technical S>ecification Surveillance Program. The licensee responded to t1is violation on July 10, 1996, and identified that a less than adequate policy regarding performance of Operations Department surveillances was the caus The licensee implemented new policy requirements and strengthened existing policies. The inspectors reviewed the policy changes and observed that no recent surveillances were missed. Based upon the inspectors * review of licensee's actions, this violation is close .3 (Closed) Violation 50 321/96 10 02: Late 10 CFR 50.72 Notification. The licensee responded to this violation on September 23, 1996, and denied that the violation occurred. After further NRC review and communication with the licensee, the licensee withdrew its violation on March 28, previous 1997. Thedenial and provided licensee responded to the additional guidance to the Operations and Training Departments with respect to reporting requirements. Based upon the inspectors' review of licensee's actions, this violation is closed 0 (Closed) Violation 50-321/96-10-05: Failure to Correct a Safety Related Alarm Deficiency. The licensee responded to this violation on September 23, 1996, and denied that the violation occurred. After consideration of the licensee's res)onse and subsequent further review of this issue, the NRC wit 1 draws this violation. This item is close II. Maintenance M1 Conduct of Maintenance M1.1 General Comments Insoection Stone (62707) (62700)

The inspectors reviewed the applicable procedures, work packages and observed or reviewed all or portions of the work activities under the following Maintenance Work Order (MW0) or Repetitive Task (RT) numbers:

• MWO 1-97-0546: determine reason for vacuum breaker 1T48-323F failure to close

• MWO 1-97-1490: diesel fire pump engine temperature regulator valve repair

. MWO 1-97-1552: reroute air bubbler tubing for river level indication

. MWO 1-97-1641: fuel pool skimer surge tank A spurious low level alarm

. MWO 1-97-1772: investigate loss of power to RPIS Enclosure

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. MWO 1-97-1900: adjust packing on MOV 1E11-F119B per 52CM-MME 001-05. " Repacking Valves and the Adjustment of Valve Packing." Revision (Rev.) 11

. MWO 2-97-1613: adjust to) left limit switch on 2B21 F028C outboard islV

. MWO 2-97-1744: replace action pack signal converter 2011-K026B e MWO 2-97-1768: tape circuit with Siltemp per engineering instructions

. RT N1T48R0741: calibration of Beckman 742 oxygen analyzer indicating alarm

. RT N2831R6251: chart recorder calibration Qbservations and Findinos The inspectors found that the observed work was performed with the work packages present and being actively use The inspectors reviewed the work packages and discussed the work activities with maintenance personnel. The work instructions were appropriately filled out and functional tests were accomplished as required. The work procedures provided clear instructions to accomplish the work activit The inspectors observed during MWO 1-97-1900 repacking activity that the craft noticed that the packing adjustment had not corrected the leakage problem and the valve would require repacking. The work package was returned to planning and control for additional instruction Conclusions on Conduct of Maintenance Maintenance activities were generally com)leted thoroughly and professionally. The maintenance work aaccage documentation for adjustment of packing on MOV 1E11-F1193 was complete and provided good craft feedback to )lanning and control for additional corrective action for t11s valve. No deficiencies were identified by the inspector M1.2 On-Line Maintenance Insoection Scoce (62700)

To evaluate the licensee's on-line maintenance activities, the inspectors reviewed procedures, observed work in progress, and s reviewed selected records. Observations were compared with a>plicable procedures and the Updated Final Safety Analysis Report ( JFSAR) .

Enclosure

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Specific areas examined included: procedure approval, post maintenance testing, inspection points, reference materials, fire-protection, cleanliness and housekeeping, equipment control and tagging process, functional testing, measuring and test equipment (M&TE) calibration and control, at.d special process contro Observations and Findinas During the performance of MWO 19701641, the inspectors observed that the Instrumentation and Control (l&C) technicians drained a plastic hose containing water from the spent fuel pool into a floor drain. During the process. several drops of potentially radioactively contaminated water from the spent fuel pool were spilled on the floor drain grate. The technicians took no actions until prompted by the inspectors. The technicians then wiped up the spill and left the radiological controlled area. No survey was taken to determine if the floor drain had become contaminate The failure to assure that the drain cover was free of contamination could have resulted in the spread of radioactive contamination. This was ident1fied as an example of a poor work practice associated with contamination contro During the performance of RT N1T48R0741. the ins)ectors observed that calibration procedure 57CP-T48-001 N1, "Beccman 742 0xygen Analyzer Indicating Alarm." Rev. 2. paragraph 7.2.1, states, in part, " expose the sensor to a suitable dry air, such as bottled or instrument air." The technician 3erforming the calibration, used breathing air which comes from tle service air system. Service air is not dry. It appeared that the technician was not aware that breathing air was not dry. The inspectors consulted the vendor manual for the Beckman 742 0xygen Analyzer, and the system engineer responsible for this instrument, and determined that for this specific set of circumstances, breathing air / service air was acceptabl When questioned, the system engineer stated that it appeared that-calibration procedure 57CP-T48-001-N1 was not as clear as it could be with respect to the source of air, and the procedure would be reviewed for possible enhancement Except as noted above. the on-line maintenance work observed by the inspectors was performed in accordance with work instructions, procedures, and applicable clearance controls. Safety related maintenance and surveillance testing evolutions were well planned and execute Enclosure 1 .. . . .. ..

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13 Conclusions The observed balance of plant (BOP) on-line maintenance was generally performed in accordance with work instructions, procedures, and applicable clearance controls Safety-related maintenance and surveillance testing evolutions were well planned and executed. One example of a poor work practice associated with contamination control was observe M1.3 liain Steam Isolation Valve (MSIV) Limit Switch Observations Insoection Scone (62707) (37551)

'r The inspectors observed the job staging and support activities associated with the Unit 2 steam chase entry for the adjustment of a limit switch on the 2C outboard MSIV. Subsequent to the limit switch adjustment, the inspectors observed the control room operators perform the MSly closure instrumentation functional test. The applicable MWO, TSs. and procedures were reviewe Observations and Findinog On July 20. the inspectors observed job staging / support activities associated with adjusting a limit switch associated with MSIV 2B21 F028C. A problem with this limit switch was identified on June 22 during the performance of procedure 34SV-821-001-2S "MSIV Exercise and Closure Instrument Functional Test." Rev. S. Edition (ED) The 2C71A-K3F relay on control room back panel 2H11-P611 de-energized when the MSIV traveled in the closed position but failed to re energize when the valve traveled back to its full open positio A second attempt was made to re-energize the relay without success. This relay provides MSIV trip signals to the reactor protection system (RPS) Trip "B" actuation logic for the respective MSly when it is less than full open (< 90% open). The RPS actuation logic is made (half scram) for the associated RPS sub channe The inspectors observed the presence of management representatives from maintenanca. health physics (HP), and security. A site senior safety specialist was also presen Site security was tasked with providing emergency response in the event of personnel injury while performing the work activity w1 Gin the steam chas Ice vests were worn by personnel entering the steam chase, where the reported temperature within the area of work activity was approximately 130 degrees fahrenheit ('F).

The inspectors ot' served that telemetry dosimeters were used by_

personnel entering the steam chase. The monitoring station received dose ar.d dose rate information from the built-in Enclosure i

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transmitters _of each digital alarming dosimeter (DAD) and provided outputs of this-information to a notebook compute Additionally, the inspectors observed the use of wireless radio communication equioment between personnel entering the steam chase and support personnel at the entry to the steam chase. A television monitor connected to a camera with panning capabilities within the steam chase allowed sup) ort )ersonnel to observe the

- movement of the team-personnel wit 11n tie steam chas Maintenance personnel found, upon entry into the steam chase, that the C outboard MSIV was in the fully open position and the problem with the limit switch on the 'C' outboard MSIV was corrected by adjustingit. This activity was documented in HWD 2-97-1613, which the ins)ectors reviewed. The inspectors also reviewed TS 3.3.1.1. "leactor Protection System (RPS) Instrumentation." and-the loss of Function Diagram (LFD-2-RPS-10) associated with the RPS instrumentation for MSIV closure. No discrepancies were identified with licensee action Subsequent to the limit twitch adjustment, the inspectors observed the performance of procedure 345V-821-001-2S from the main control room. The outboard MSIVs_and the 'A' inboard MSIV tested

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_ properly. Upon testin 'g' the 'B' inboard MSIV, one relay did not re energize when the B inboard _MSly was returned to its full open position. A second attem)t was made to re-energize the relay without succes Because the (3D relay remained de-energized when the 'B' inboard MSIV was returned to its full open position, the RPS MSIV trip logic sub channel B2 continued'to receive one half of its trip signal inputs. The failure of this relay to re-energize is similar to the earlier failure of the relay associated with the "C" MSIV. The licensee declared _the failed relay inoperable and implemented a temporary modification (TM 2-97-26) for ensuring that the relay remained de-energized for compliance with TS 3.3.1.1-(A.1).

Because adjustment / repair of the limit switch on the 'B' intoard MSIV would require a drywell entry, the licensee developed a detailed contingency plan for a forced outage. This plan was to be used in the event that another inboard MSIV limit switch -failed while completing surveillance procedure 34SV B21-001-2S for the remaining inboard MSIVs-for steam lines *C' and 'D'. The remaining test for steam line 'C' and 'D' was performed on July 31 and the HSly limit switches and relays functioned as designe TSs require that the MSIV closure testing be performed every 90 days. The licensee 'will maintain this contingency plan through the next MSIV closure surveillance testin Enclosure

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Engineering and other designated plant personnel continued to investigate the causes for the problems with the 'C' outboard MSIV and the 'B' inboard MSIV. Some of the possible contributing causes considered were thermal growth and adjustment method Maintenance engineering informed the inspectors that a final root cause would not be determined until an evaluation of the actual problem limit switch is performe Conclusions The job staging and support activities at the entrance to the Unit 2 steam chase were thoroughly planned and organized Maintenance management's active involvement and support from H Security, and Plant Safety were excellent. Contingency planning and pre job coordination for a )otential Unit 2 forced outage to repair inboard MSIV limit switcles were detaile M1.4 Diesel Fire Pumo Temoerature Reaulator Valve insoection Scone (62700)

In the last year, the licensee has replaced the temperature regulator valve on the 1X43-C002A diesel fire pump engine approximately five times. The pump was out of service for the majority of the time between June-16 and July 11, 1997. for maintenance wor To evaluate the licensee's actions related to the fire pump engine temperature regulator valve replacements, the inspectors interviewed licensee personnel and reviewed selected records and procedures. Observations were compared with a>plicable procedures. Fire Hazardous Analysis (FHA) and the U:SA Observations and Findinos In 1996, the original temperature regulator valve was replaced due to a damaged strainer. Identification markings on the temperature regulator valves on both engines had been lost. As a result, a valve similar in appearance to the one removed was procured from the warehouse and installed. Following installation during operation, an increase in engine operating temperature was noted by the licensee. The licensee discovered that opening the temperature regulatin temperature decreas Thisby-pass led the licensee valve resulted in ananengine to suspect internal valve problem. During disassembly of the valve. the licensee determined that the replacement valve had a smaller orifice-than the original valve. Several other similar valves obtained from the warehouse were tried and the same results occurred. One valve was drilled until the orifice size matched the original valve. This did not correct the problem. Eventually the proper replacement valve was procured and installe Enclosure

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During post maintenance testing. it was noted that the engine still operated at an increased temperature which was outside the procedural acceptance criteria. Following trouble shooting activities, the technicians determined that the engine temper,ature indicating gage was reading 10 to 15 'F high. The licensee determined that, even though the orifices on the replacement temperature regulating valves were smaller than the orifice on the original valve, had the engine temperature indicating gage been accurate, the engine would have operated within the acceptable temperature range, after the replacement of the original valve for the damaged straine The inspectors reviewed the 0)erating Requirements of the FHA -

section 1.3.1, and verified t lat all applicable Fire Action Statements were met for the out of-service times during the maintenance activities. The inspectors also verified that the applicable FHA required surveillance was me The inspectort discussed the maintenance activities with maintenance rod engineering personnel. The inspectors were informed that, because the system responsibility was assigned to fire protection engineering personnel, the sco>e and direction of the maintenance work activities were directed )y that departmen It was not until mechanical engineering personnel became actively involved in reviewing the system parameters and response, did the problem get resolve The inspectors evaluated the diesel fire pumps to determine whether those pumps should have been included in the scope of the licensee's 10 CFR 50.65 " Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants [the Maintenance Rule) program. The diesel fire pump's emergency mitigation function is to )rovide an alternate water source for-Reactor Pressure Vessel (R)V) water level control, as delineated in Emergency Operation Procedure 31E0-E0P-110 2S. " Alternate RPV Water Level Control." Rev. 2, observations were compared with NUMARC 93 01 " Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." Rev. 2, which was 2ndorsed in Regulatory Guide-1.160 "Monitorin of Maintenance at Nuclear Power Plants " Rev.2.g the Effectiveness Licensee personnel indicated that the diesel fire pumps do not provide a significant. fraction of the mitigation function of alternate water source for RPV' level control and therefore were not included within the scope of 10 CFR 50.65. When the inspectors asked to review the documentation discussing this

. position, licensee personnel indicated that they only had conclusive type statements for the systems that were excluded from their 10 CFR 50.65 progra Licensee personnel subsequently provided a calculation that supported the conclusive type Enclosure

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statement. The licensee indicated that they would revisit other l items excluded from the 10 CFR 50A5 program and assure that ;

appropriate documentation to support their exclusion was  ;

availabl Conclusions The review by fire protection engineering personnel for a replacement diesel fire pump temperature regulator valve and temperature gage resulted in maintenance rework and prolonged repair for the fire protection syste The diesel fire Jumps were appropriately excluded from the scope of licensee's 10 C:R 50.65 program. Fire Action Statements and surveillance requirements of the Fire Hazardous Analysis were me M1.5 leactor Coolant leak at the 2A Reactor Water Cleanuo (RWCU) Heat IEhaD. ' Insoection Scooe (62700)

The inspectors reviewed the-leak repair on the 2A RWCU heat exchanger. The inspectors observed licensee actions, reviewed the results of a Significance Occurrence Report (SOR) for the 2A RWCU heat exchanger leak repair, and interviewed licensee personne Observations were compared with applicable procedures, work packages, and the UFSA Observations and Findinas The inspectors observed that a repetitive leak occurred on the 2A RWCU heat exchanger. On two recent occasions, the leak resulted in actuating main control room alarms for Primary Containment Isolation System (PCIS) Leak Detection. Operators used the applicable alarm procedures and Abnormal' Operating Procedur AB-T22-003 25, " Secondary Containment Control". Rev. 3, to assess the leak. The leak did not result in a PCIS isolatio HP personnel informed the inspectors that the steam from the reactor coolant leak was exiting the RWCU room via penetration This resulted in portions.of three elevations of the reactor building being designated as contaminated areas. Several personnel contaminations occurred (primarily feet). This area wes also contaminated with fission gasse ;

i Enclosure

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The inspectors observed that the Unit 1 RWCU heat exchanger did not have a recent history of leakage problems. The inspectors conducted a review of the past work and leak history for both units' RWCU system to identify why Unit 2 had repetitive leaks and Unit 1 did not. The inspectors also included a review of As low-As Reasonably Achievable (ALARA) considerations with respect to the maintenance work activities. The inspectors observed the following:

• For Unit 1. from 1984 to 1990 the licensee installed " Belly" bands or injection-sealant clamps. When this proved to be-unsuccessful, the licensee welded Omega seal assemblies to encapsulate the head flange to shell flange junction and the head studs and nuts on-the three RWCU regenerative heat exchangers. The installation of the in1ection sealant clamps used 54.6 person rem. Theinstallationofthethree Omega seals used 65.4 person rem. The Unit 1 RWCU heat exchangers are leak fre * In an effort to reduce radiation dose when the 2B RWCU heat-exchanger started to leak in June 1992 the licensee took a different approach. The gap between the Unit 2B RWCU heat exchanger head and shell flanges was seal welded and injection washers were installed on the head stud On seven occasions between February 1993 and July 1996, the 2B RWCU heat exchanger injection head studs were injected and reinjected. In April 1995, the gap between the Unit 2C RWCU heat exchanger head and shell flanges was seal welded and injection washers were installed on the head studs. -In January 1997, an injection sealant clamp and injection Washers were installed on the head studs of the Unit 2A RWCU heat exchange * -On 11 occasions-between February 1997 and May 1997. the 2A RWCU heat exchanger injection head studs were injected and reinjected to stop primary coolant leaks.- The total dose expended through June 1997 was 74.5 person-rem. As of mid-July 1997, the 2B and 2C.RWCU Heat exchangers were not

. leaking. The 2A RWCU heat exchanger continued to leak. The-inspectors verified that the sealant usc4 for injection, which comes in contact with reacter coolant, was approve The decision to scal weld the 2B anC2C RWCU heat exchangers :

instead-of installing a welded 0mega seal assembly was based on dose considerations. -Because the initial leak on=the 2A RWCU heat ~

exchanger was only 60-drops per minute, a decision was made to use-the injection clamp. : After eleven injections, a decision was made

.to seal weld the 2A-RWC Enclosure

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The 28 and 2C RWCU heat'exchangers were seal welded prior to-Linjecting sealant.- = The welding in the accessible areas, was apparently acceptable: however, only a portion of the circumferencc- of- the gap between the flanges was acccasible fu, welding . As a result, the installstion of an-injection! sealant clamp wa necessary, in addition to the injection washF s, to address the leakage path around the stud ;-The-2A RWCU. heat exchanger was sealant-injected n + '

di cision to seal weld the flange gap.. The inje- .

clam ' supplier informed the licensee thot-the sealar n  ; remove and would not interfere with welding. The lit .. sered-that neither was true.- The licensee-~conductec cup welding for 2A RWCU flange-seal weld, but used typical dimensions.provided b

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the injection. sealant clamp supplier, which did not accurately y_

model the join'. configuratio The-mock-up did not include the backing ring that was to be used on the production weld.- As a result of the misinformation provided by the injection sealant clamp supplier, the sealant in the. weld area was not mocked up. The welders, during sea welding, discovered thatthe configuration of the mock-up was different than the production -joint: the backing ring was not ,

-installed properly because it wasn't mocked:up. The welders als discovered that the sealant was difficult to remove, _and that the sealant in the weld area' caused weid ,3

.(leading to wGld soundness pioblems). puddle cleanliness problems - "

In addition, these problems were-not well communicated-to the =

licensee's management during the welding process: thus,mid-job corrections were not made. Further.-the welders stated that they-felt pressured to complete the weld as soon as possible due to the high dose rate in the area. These_ problems led to poor seal weld: f*

. quality, and resulted in'a subsequent weld repair of the seal weld

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and' injection of. sealan The licensee indicated that.a. design change request (DCR) for'the _

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installation of a welded Omega seal ' assembly similar to the DCR-

implemented on the Unit 11' RWCU heat exchangers would be-implemented. During the week of August 11. the ~ additional-repairs

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were completed on the 2A heat exchanger;to stop the leak. The

' ALARA analysis initially estimated that about- 16 person-rem would be required to complete:the job. However, during the work

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HP and engineering personnel realized that accumulated dose was considerably' higher than initial estimates. A reassessment of # ARA issu" resulted in increasing the total dose estimate to-about 26 perso v am. About 28.33 person-rem were actually accumulatei during' that activity.1s a result.102.83 person-rem-has been accumulated to repair the Unit 2 RWCU heat'

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exchangers. The 2B heat exchanger is presently leaking again H plans are under way to initiate repair The inspectors questioned the licensee as to why there was a significant difference between the ALARA staffs estimated dose (15 person-rem) and actual dose (28.33 person-rem) for the work activity. At the end of. the inspection report period, licensee personnel had not completed their review to determine why this difference existed. The inspectors identified this issue as an inspector followup item (IFI) 50-321, 366/97-07-01: Review of Licensee's Assessment of the ALARA Process for tH *it 2 Reactor Coolant Leak Repair on the RWCU Heat Exchange The inspectors reviewed Significant Occurrence Report (SOR)

97-3164, which was issued to review the maintenance activities associated with the reactor coolant leak on the Unit 2 RWCU heat exchangers. The report identified, the problems discussed abov . In an effort to continue to reduce the time to perform the welding, to improve the quality, and to reduce dose, a

" backing ring" was installed in the gap to be welded. The

" backing ring" was not installed properly and actually protruded above the surface of the flange. "Instead of improving quality, the poor installation of the " backing ring" made it difficult for the welders to adequately perform a cartial penetration weld into the gap."

. "Wnrk Organization-Planning Did Not Consider Special Circumstances." There was a " mock up" used to help practice the weld but the " backing ring" was not installed on a

" mock up." If a " mock up" had been used, the welders would have understood how the " backing ring" was to be installed '

and would have notified their supervision that it could not be fit into the gap as planned."

. "Another contributor of the poor quality of the seal weld made on the 2A heat exchanger (2G318001A) was the sealant left in the gap following the unsuccessful attempt made by Kupple with the clamp."

. "The welders testified that they felt pressured to complete the weld as soon as oossible due to the high dose they were receiving. This feeling could have contributed to affecting the quality of the weld, More important was the fact that

- the Quality Control inspectors and engineers were present

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and available, but due to the high radiation area, an inspection of the installation of the " backing ring" was never performed and the incorrect installation was not identified."

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21 Conclusions

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7The ins)ectors observed that the SOR for the primary coolant leak

'on the Jnit 2-RWCU heat exchanger identified root causes and made

- s)ecific recommendations for corrective actions, The quality of t1e report was good, The recent' recurring reactor coolant leaks

"on the heat exchanger were due to a poor quality weld' caused by a

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lack of detailed review of the job scope and poor interface between craft and supervisory personnel. Operator-response to the

_ reactor coolant leak was satisfactor M2- Maintenance and Material Condition of Facility and Equipmen M Insoection of Unit 1- and Unit-2 torus areas

- Insoection Scooe-(62707)

-The inspectorc conducted a toui -of Unit 1- and Unit 2 torus areas to observe general-.-conditions of structures and components.-

. evidence of system-leakage, radiological controls of the contaminated areas and general housekees ing. The tour included the top of the-torus catwalk area and beneath the torus proper, Observations and Findinas The following are observatiens of the Unit 1 torus ~ area:

A wood torus manway cover wasL1.ing on top of.the torus. Two imetal beams about.3 feet long were observed on the catwalk._ The-R- -items-were not secured or attached. A~long length of tygon tubing ~

was: observed on the catwalk area. The equipment utilization tag -

-which was assigned to operations, was outdated. The equipment utilization tag expired in 1995. An electrical extension cord was 4 plugged into an outlet at'the 87 foot elevation of the torus are The inspectors observed two Torus area floor drain sumps. The cover for one sump was not in place (not in the-area) and a second metal sump _ cover did not completely cover the sum There were rags and paper debris in the immediate-vicinity of.both sumps. An electrical conduit-cover.Lfor an instrument probe: connection for-the torus.:had one screw missing-and the cover was hanging loosely. General--housekeeping in the areas was satisfactor Some small hand tools and pipe connections were observed in the

, area. Plastic tie wraps. . paper. small pieces of wire, rags and tape were observe The inspectors viewed the welded joints of,the torus and torus- I

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support structures. This included the torus circumferential welds, horizontal to vertical support welds and base plate to sup) ort welds and bolted connections. The upper steel support i mem)ers for the Torus were observed to be in excellent conditio Enclosur '

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Welded areas were well-coated with no peeling or degradation observed. There were some small areas (about one inch square) on the steel base to concrete structure interface, that were scarre These areas ap) eared to be where equipment had bumped or come in contact with t1e steel structure. Some scars revealed the primer

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coating and others extended to the bare steel. The inspectors observed one welded 3rea that was not coated, at the-junction of bays 15 and 16 at the horizontal to vertical steel base plate area. The uncoated weld area was about 0.5 inches by 8 inche Another uncoated scarred area (not a welded joint) in the same general location was about 2 inches by about 10 inches. An area about 4 inches by 12 inches in what appeared-to be a grinding mark, was not coated. There was a total of about 8 to 10 small areas (one inch square) on the torus that were not coated. There was no evidence of rust or corrosion. The spots appeared to be some type of test areas. This was discussed with maintenance and-engineering personne Unit 2 torus area observations were as follows:

The irispectors observed two fire protection header isolation valves, 2T43-F114 and 2T43-F115. on top of the torus area that were covered with corrosion and rust. The valves appeared to be open and there was no evidence of leakin A metal manway cover was observed secured to the catwalk handrai A long length of steel cable was hanging over the side of the torus at bay 6. Housekeeping in the general area was good. Some small pieces of plastic tie wraps, tape and wire were observe Two cloth gloves were observed in a cable tray at bay The upper steel support members of the torus were observed to be in excellent condition. Welded areas were well-coated with no peeling or degradation observed. There were scme small areas (about one inch squarel on the steel base to concrete structure interfcce that were scarred. These areas a]peared to be where .

equipment had bumped or come in contact witt the steel structur Some scars revealed the primer coating and others extended to the bare steel. There were small areas of the horizontal steel base support structures that had some small amounts of what appeared to ne-surface rust. The total areas combined was about 1.5 feet square. The inspectors observed that there was evidence of some

_ pot painting of the torus and support structures.

, The inspectors observed that radiological controls for high radiation areas and contaminated areas were satisfactory. High

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radiation areas were conspicuously posted with the correct markers. Contamination areas were properly identified and roped off. Facilities were in place to dispose of protective clothing when leaving the contaminated area. The inspectors identified two

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outdated radiological area survey sheets posted in bays 4 and 8 at the 87 foot elevation area of the Unit 2 torus. The survey sheets were datcj April 30. 1997. The inspectors brought this to the attention of HP technicians and HP management personnel for resolutio The inspectors did not observe any system or component leakag Conclusions The inspectors concluded that the overall material condition of systems and components and radiological controls of contaminated and high radiation areas in the Unit 1 and Unit 2 torus areas were good. The upper steel support members for the torus of both Units

'ctazy were in excellent condition with no signs of peeling or rust. The lower steel support members contained some minor scars that were not coated. No system or component leakage was observed. General housekeeping was adequat H3 Maintenance Procedures and Documentation M3.1 Surveillance Observations Insoection Scoce (61726)

The inspectors observed various Unit 1 and Unit 2 surveillance activities. The procedures to accomplish the activities provided instructions for demonstrating that the referenced safety-related eouipment functioned as required by TSs and the Inservice Testing progra Ob_servations and Findinas The activities observed and the Hatch surveillance procedures used were as follows:

. 34SV-R43-001-2 Diesel Generator 2A Monthly Test Rev. 22 e 34IT-0PS-003-0 Security Power System Test. Rev. 5

. 34SV-B21-001-2S. MSIV Exercise and Closure Instrument Functional Test Rev. 5. ED 1

+ 34SV-E51-001-15. RCIC Valve Operability. Rev. 15

. 34SV-E11-001-1S. Residua? Heat Removal Pump Operabilit Rev. 20. ED 1

. 57SV-011-022-2S. Reactor Building Vent Radiation Monitor FT&C. Rev. 6. ED 1 Enclosure

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24 Conclusions For the surveillances observed, the equipment performed satisfactorily and met applicable acceptance criteria. The performance of the operators and crews conducting the surveillances was professional and competent. No deficiencies were identifie M7 Quality Assurance in Maintenance Activities M7.1 Audits Insoection Scooe (62700)

The inspectors reviewed the licensee's BOP Audit Program as it relates. Observations were compared with applicable p1.cedures and the UFSA Observations and Findinos Audit Report 97-BOP-1 " Audit of Balance of Plant." findings included: incomplete documentation of information obtained during the work activity: station service air compressors not situated or constructed to avoid entry of non-radioactive contaminated air; and four air receiver valves not tested. Appropriate corrective actions were recommende Conclusions BOP maintenance was subjected to an independent audit, with appropriate action recommended for the identified weaknesse M8 Miscellaneous Maintenance Issues (92700) (92902)

M (Closed) LER 50-366/97-01: High pressure Coolant Injection System Inoperable Following Unplanned Engineered Safety Feature Actuatio This item is discussed in IR 50-321, 366/97-0 Paragraph M No new issues were revealed by the LER. This LER is close M8.2 (Closed) LER 50-366/97-03: Excessive Leakage Identified on Secondary Containment Bypass Valves. While performing a Local Leak Rate Test (LLRT) during the Unit 2 refueling outage, the licensee identified that two valves associated with the drywell floor drain system exhibited excessive leakage. The licensee determined the cause of the valve failure to be undersized valve operators and inappropriate valve operator orientation. The licensee implemented a design change prior to the unit startup to reroute piping to accommodate new valves and operator Enclosure

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Appropriate tests were completeo and the system was returned to service. Based upon the inspectors' review of the licensee's actions this LER is close M8.3 (Closed) VIO 50-321. 366/96-15-02 - Maintenance Personnel Failure to Follow Procedure during Valve Backseating Activities. The licensee responded to this violation in correspondence dated April 25, 1997. The licensee determined the cause of the violation to be personnel error. The inspectors revimed the response and observed that the corrective actions included the following:

• the involved personnel were counseled regarding exercising poor judgement in not obtaining the Shift Su)ervisor's signature in the work performed section of t1e MWO and failing to initiate another MWO to inspect the valve internals as required by the procedur . procedure 51GM-MNT-034-05, "MOV Electrical Backseating with Instantaneous Circuit Breaker Trip Protection" was enhanced to include an additional step in section 7.0 and a sign-off in the procedure attachment to insure that the requirement identified in step 4.3.2 was identified as a work activity which must be completed when a valve is backseate The procedure was revised, effective February 21, 199 .The inspectors reviewed procedure 51GM-MNT-034-OS. Revision dated February 21, 1997, and verified that the changes discussed above were included in the procedure In addition, the inspectors discussed management expectations regarding procedure usage with maintenance supervision and personnel. The inspectors noted that management reinforced the expectations for procedure use and adherence throughout the maintenance department, lhe inspectors reviewed formal and informal documentation which communicated these expectations. Based upon the inspectors' review of the licensee's corrective actions. this violation is close Enclosure

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III. Enaineerina El Conduct of Engineering On-site engineering activities were reviewed to determine their effectiveness in preventing, identifying. and resolving safety issues, events, and problem El.1 Review of Units 1 and 2 Inadeqp_ ate Cable Seoaration Issues Insoection Scoce (37551) (9?102).

The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR). Documentation of Engineering Judgement, a temporary modification 10 CFR 50.59 evaluations. and Maintenance Work Orders (MW0s) associated with the resolution of the cable separation issues -involving the IF and 2F 4160 volt alternating I current (VAC) switchgears. The inspectors also observed the installation of silicon dioxide (Siltemp) tape that was used as an electrical separation barrier for wiring that did not meet the separation criteria. The wiring taped with Siltem a maximum of 120 VAC or 125 volts direct current VDC).

(p was limited to Observations and Findinas As a result of a wiring-to-drawing inconsistency, the licensee discovered divisional separation problems. The divisional separation problems were determined by the licensee to be a fire protect. ion issue. The inspectors initially discussed these items in Inspection Report (IR) 50-321. 366/97-0 The inspectors reviewed-the Unit 1-UFSAR. Section 8.8.3.5. Separation of Electrical Equipment and Unit 2 UFSAR. Section 8.3.1.4.1.2.D. Control Boards and Other Panels. These sections of '

the UFSAR defined the requirements for the separation of wiring within an electrical enclosure such as a panel. The UFSAR stated that there must be a minimum of six inches of divisional separation between circuits. If it is imprcctical to provide the six inch separation, then the cables must be separated by a metal barrier or enclosed in metal condui An inspection of the Unit 1F and 2F 4160 VAC switchgears was performed by the licensee to determine the extent of the cable separation problems. The results of the inspection were submitted to corporate engineering for an analysis of the function and assessment of the circuits identified during the walkdown. -The results of the Unit 1 engineering analysis were documented in a Documentation of Engineering Judgement, dated July 17, 1997, file REA HT-97632. Unit 2 analysis was documented under Documentation of Engineering Judgement, dated July 10. 1997, file REA HT-9763 Enclosure

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T. -- e p 27 As a result of the analysis'of the walkdown'on the IB Residual Heat Removal Service Water Pump (RHRSW) the licensee discovered-

- that it was inoperable due to circuits H11-P652-C06A and H21-P201-RC05 not meeting the six-inch divisional separation criteria. The a entered for the ppropriate inoperable Technical RHRSW and Specification (TS)notification a 10 CFR 50.72 was was made to the NRC. The licensee implemented Temporary Modification (TM)- 1-97-13.- Implementation of-this.TM satisfied the barrier separation criteria and the IB RHRSW was returned to an operable status, -The ins)ectors reviewed the 10 CFR 50.59 evaluation asseciated with tie TM and identified no discrepancie Additionally, five MW0s for-- Unit -1 and seven MW0s for. Unit 2 were-initiated as a result of the corporate engineering analysis of the inspection results. The MW0s provided work-instructions-for 1 installing Siltemp tape as.a barrier between-the 120 VAC and-125 VDC cabling identified during the walkdowns that did not meet '

the divisional separation-criteria. The licensee initiated the MW0s for using the S11 temp tape under the 10 CFR 50.59 evaluation process. The licensee determined during the 10 CFR 50.5 evaluation process that the UFSAR needed to be revised to allow-the option of wrapping instrumentation and control cables (125 volts or-less) not subjected to harsh environments with an approved barrier material such as thermal and electrical insulation. The licensee stated that it plans to submit the UFSAR revision at the next scheduled- revision dat The licensee had evaluated Siltemp thermal tape and considered it !

to be an acceptable barrier for preventing the propagation of-damage between adjacent divisional- cables. The test results of Wyle Laboratories on samples of Siltemp was factored into-the

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licensee's evaluation for-the use of-S11 temp tape as 3 divisional barrier material. The licensee is recommending at this tim l that the Siltemp tape only be used on instrumentation or control

- circuits with a maximum of-125 VDC-or 120 VAC in non-environmentally qualified -(non-E0) environment On July 31. the inspectors observed the installation of S11 tem)

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tape on the 2F 4160 VAC switchgear. The inspectors observed tlat-the installation of _ the Siltemp tape.by craft-personnel was meticulous, methodical, and in accordance with the guidelines for the S11 temp tape installation- The inspectors also observed

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c engineering supervision monitoring the work activity, Conclusions-The initial actions taken in.the resolution of the cable separation issues were satisfactory. --The inspectors identifled no discrepancies in the 10 CFR 50.59 evaluation process for the-temporary modification associcted with returning the IB RHRSW to Enclosure I

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an operable status and the use of Siltemp tape as a barrier material. Adequate engineering oversight was provided for the installation of Siltemp tape on the 2F 4160 VAC switchgear cable E2 Engineering Support of Facilities and Equipment E2.1 Review of licensees resoonse and additional information with resoect to Generic letter (Gl.) 87-02. " Verification of Seismic Adeouacv of Mechanical and Electrical Eouioment in Ooeratina Reactors." Unresolved Safety Issue (USl) A-4 (37551) (92903)

In correspondence dated June 20, 1997, the NRC informed the licensee that the NRC had completed a review of additional requested information submitted on April 25. 1997, associated with GL 87-02. The NRC identified a potential violation involving a 10 CFR 50.59 evaluation. The potential violation was based upon the following:

. The NRC approved the use of the Generic Implementation Procedure (GIP) in a V ety Evaluation (SE) dated May 2 , issued with Suppu....cnt 1 to GL 87-02. The NRC's SE stated that a licensee may revise its licensing basis in accordance with 10 CFR 50.59 to reflect the acceptability of the USI A-46 (GIP) methodology for verifying the seismic adequacy of electrical and mechanical equipment covered by the GI . The NRC reviewed the licensee's information with respect to an implemented UFSAR change and observed that the revision would permit, as an alternative, the use of the GIP procedures for the seismic qualifications of all mechanical and electrical equipment in the plan . In applying the GIP, in lieu of previously ap3 roved UFSAR criteria, as a licensing basis criteria for t1e qualification of mechanical and electrical equipment could result in the eventual reduction to the licensing basis margins for components or systems affected by such changes and would not be consistent with the limitations of the 10 CFR 50.59 limitation Additionally, the NRC identified a potential deviation based upon the following:

. On September 16. 1992. Georgia Power Company (GPC) submitted the initial response to Supplement 1 to GL 87-02. In that submittal. GPC indicated its intent to incorporate provisions of the GIPS via a 10 CFR 50.59 evaluation upon receipt of a final plant-specific SE resolving USI A-4 Enclosure

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29-e .As'of Jane 20, 1997, the NRC has r.ot issued its final SE on

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the A-46 implementation-and Hatch has already incorporated the GlP into UFSAR Revision 14L for Units-1'and The NRC has requested a response from the licensee by August 2 , to resolve the above' concerns. This issue.is being identified as Unresolved Item (URI) 50-321, 366/97-07-02. Resolve

._. Concerns with Respect to GL 87-02, pending subsequent review by-the NRC:of the licensee's submittal ,

E2.2 Rod Block Monitor (RBM) Setooints - 'Insoection Scoce (92903)

On March 14. 1997, the NRC Special Inspections Branch completed an inspection at the General Electric (GE) Nuclear Energy facili The inspection report identified that a "GE memorar.dum to Southern Nuclear Operating Company (SNOC) dated October 31, 1994; stated that the 1 percent plastic strain is met. if one channel of the=

RBM (Rod Block Monitor) remains operable." _SNOC did not revise che Hatch TSs. On July 30. 1997, the resident inspectors visited-the SNOC corporate office to follow-up on licensee actions and 3revious inspection findings with respect to the RBM Systems for- ;

Joth units at the Hatch facility, j Observations and Findinas 1 h

NRC IR 99900003/97-01, dated May 20.~1997. Section 3.2 states, in

_part, that for Unit 1 Cycles 16 and 17. and Unit 2 Cycles 13:and

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14. GE-informed SNOC that the mechanical over power (MOP) limits would-be exceeded during a Rod Withdrawal _ Error (RWE) event if the .i RBM was not operable. A GE-memorandum to SNOC dated October-31.-

1994, stated that the one percent plastic strain is met if one-channel of the RBM remains operable. SNOC did not revise the Hatch TSs to incorporate this informatio The TSs at Hatch did not require the RBM to be operable.at all times to prevent-possible fuel damage associated with an RWEc The T5s allow the RBM.to be inoperable under certain conditions of reactor power and Minimum Critical Power Ratio (MPCR), eg., rated thermal power greater than or equal to 90_ percent and MCPR less than 1.40. However, in the GE core design procedures. GE' assumed that the RBM was operable under these condition During the inspection conducted'at the GE facility, inspectors

- determined that GE did not adequately inform licensees of the need

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to consider the fuel-cladding plastic strain limits ~ and associated MOP limits in addition to the minimum critical )ower ratio limits when considering RBM operability for potential RWE events. This inadequate interface between GE and licensees contributed to the Enclosure

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failure of licensees to ensure through their TSs that the RBM was operable to protect fuel cladding. A Notice of Nonconformance was issued to GE in IR 99900003/97-0 Corporate engineering requested GE to analyze the Unit 1 and

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Unit 2 fuel cycles to determine if a possible problem existe Where possible, the analysis used actual control rod patterns and concluded that in all cases sufficient margin existed such that the one percent plastic strain limit would not have been violated during a postulated RWE even Exceeding the mechanical over power limits did not mean that the one percent plastic strain limit would be exceeded during a RWE even The licensee submitted Licensee Event Report (LER) 50-321 h7-0 Rod Block Monitor Operability Requirements Do Not Match Rod Withdrawal Error Analysis, on A)ril 21, 1997. The LER indicated that a RWE transient would not lave resulted in fuel cladding damage or the release of radioactive material despite the core analysis procedure disparity with the TSs. The inspectors observed that the corrective actions identified in the LER were either completed or being implemente Based upon the inspectors'

review of licensee actions the LER is close GE implemented corrective actions for the problems. As part of the corrective actions. Hatch was informed of the disparity between GE procedures and the TS Licensee personnel immediately implemented administrative controls to ensure that the RBM remained operable. Additionally, a TS revision request was submitted on May 9, 1997, and is still being reviewed by the NR Conclusions The inspectors concluded that the licensees actions were appropriate for a disparity between the GE core analysis procedure assumptions and the Unit 1 and Unit 2 TS requirements regarding Rod Block Operabilit E2.3 Main Turbine Pressure Reaulator Failure and Power Reduction on Unit Insoection Scooe (92903)

The inspectors reviewed on licensee actions following a failed transmitter for the "B" Main Turbine Pressure Regulator on Unit Observations and Findinos On August 3. control room operators observed swings in the servo current indications for the main turbine control valves and corresponding oscillations in reactor pressure. Reactor power was Enclosure

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manually reduced to about 90% rated thermal power (RTP) and the reactor pressure oscillations stabilize Maintenance and GE personnel were contacted for assistance and a determination that the transmitter for the inservice pressure regulator "B" was ~

failing high was identified. As a result, reactor pressure was slowly decreasing. The operators manually reduced power to about 72% RTP. increased reactor pressure to allow the "A" pressure regulator to take control, and then disabled the failing pressure regulator. Power was returned to RTP on August During a review on August 4. the licensee determined that the unit o>erated outside its design basis for a short aeriod of tim T 1 1s was based upon the wording in the Unit 2 JFSAR since the Unit 1 UFSAR did not address this issue. The licensee reported ..

this event, as required by 10 CFR 50.72(b)(1)(ii)(B) at 8:07 p.m. , on August 4. as Event Notification32722. The EN stated, in part, that the UFSAR implied that the unit would be outside its design basis if a backup pressure regulator was not availabk when reactor power was below 80% RTP, The GE preliminary analysis of the event provided the licensee with recommended Unit I reactor core thermal power limits (thermal power penalty values) on August 4. Hatch management immediately implemented the GE recommcndations as administrative controls for the core thermal power penalties. The directions to operations personnel were to manually shutdown the reactor if reactor power decreased to below 80% RTP. The inspectors discussed the new core thermal power limits with engineering and operations )ersonne All personnel demonstrated a clear understanding of tie problem and the admir Lrative limits. Further review resulted in removal of the administrative requirement to manually shutdown the reactor. This was based upon the core thermal power ]rocess computer being programmed for the new specific core tiermal power restriction The inspectors reviewed the ap)licable sections of the Unit 1 and Unit 2 UFSAR with res)ect to t1e pressure regulator. The inspectors observed t1at Unit 2 UFSAR. section 15.1.6. Pressure Regulator Failed Closed, states, in part, that if the controlling pressure regulator fails in the closed Josition, the backup regulator takes over control of the tur)ine admission valves, preventing any serious transient. Because the UFSAR statements were not clear, the licensee contacted GE to obtain an interpretation and understanding of the assumption. The inspectors discussed this assumption with Nuclear Safety and Compliance (NSAC) personne The licensee received a final GE evaluation on August 6 that reached a conclusion that differed from the preliminary conclusion. This evaluation concluded that the operation of the Enclosure

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unit on August 3 was covered by all licensing limits in place 'n the event a secor.d pressure. regulator . failed while the primary one was out of service. The licensee subsequently concluded that the unit was not outside of its design basis and that the one hour NRC notification was not necessary. The licensee retracted EN 32722 on August 1 The inspectors reviewed the GE final evaluation which was provided to the licensee on August t D Conclusions The inspectors concluded that operator performance to detect and respond to the failing pressure regulator on Unit 1 was excellen Engineering and Nuclear Safety and Compliance actions to conduct a detailed review of the UFSAR and the analysis by General Electric, were appropriat E8 Hiscellaneous Engineering Issues (92700) (92903)

E8.1 .(rl.osed)- LER 50-366/96-01: The Safety Limit Minimum Critical P m Ratio (SLMCPR) for Hatch Unit 2 Fuel Cycle 13 Was Not Conservative. General Electric methodology to calculate the SLMCPR was not conservative. The licensee revised the applicable plant procedures and submitted a request for a Unit 2 TS Amendmen The NRC approved the Amendment by correspondence dated April 17, 199 Based upon the inspectors * review of licensee's actions, this LER is close E8.2 Closed) LER 50-321/97-01: Pressure Boundary Leakage Results in Condition Prohibited by the Technical Specifications. This item is discussed in IR 50-321, 366/97-01. Paragraph E2.2. As a result of the NRC's review: VIO 50-321/97-01-03. Failure to Translate Original Design Specifications Into Applicable Instructions, was identified. Based upon the inspectors' review of licensee's actions. and the issuance of the violation, this LER is close E8.3 Closed) LER 50-321/97-03:_ Rod Block Monitor Operability Requirements-Do Not Match Rod Withdrawal Error Analysis. This item is discussed in Section E2.2 of this report. Based upon the inspectors' review of licensee's actions, this LER is close Enclosure I 3. , _ . .. .. ..

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IV Plant Sucoort R1 Radiological Protection and Chemistry (RP&C) Controls R1.1- Observation of Routine Radioloaical Controls (71750)

General Health Physics (HP) activities were observed during the report period. This included inspection of locked high radiation area doors, proper radiological posting, and personnel frisking upon exiting the RCA. The inspectors made frequent tours of the Radiological Controlled Area (RCA) and discussed radiological controls with HP technicians and HP management. The inspectors also attended HP and chemistry morning work activity meetings. No deficiencies were identifie R1.2 Feed and Bleed Activities for the Unit 2 Reactor Buildina Closed Coolina Water (RBCCW) System Insoection Scone (71750) (92904)

The inspectors reviewed the receipt of a RBCCW surge tank level .,

alarm in the Unit 2 control room due to system feed and bleed activities. Additionally, the inspectois reviewed Annunciator '

Response Procedure (ARP) 34AR-650-248-2S. "RBCCW Surge TK Level Low or Exces5 !.eakage." Revision (Rev.) 2, Discussions were held with operatiuns and radiological chemistry (Radchem) personnel, Observations and Findinas The inspectors were informed by operations supervision that following the receipt of several alarms in the control room associated with the RBCCW surge-tank level, the RBCCW Corrosion Test Loop-valve 2P42-F144 was found o)en. The opened valve was found by a plant equipment operator ()EO) during a walkdown of the RBCCW system per ARP 34AR-650-248-2 The PE0 closed the valve and no further alarms were received. Operations su)ervision did-not knu.v why the valve was opened and recommended tlat the inspectors contact Radchem personne The inspectors discussed the opened corrosion test loop valve with Radchem engineerin The inspectors were informed that the RBCCW system was being purged of its cuntents due to the presence of sodium nitrite in the system A " feed and bleed" methodology was used for the sodium nitrite purging. This method consisted of keeping the RBCCW Corrnsion Test Loop Valve opened to allow approximately two liters per minute (approximately 0.53 gallons per minute or 32 gallons per hour) to drain out of the RBCCW system while the automatic makeup feature of the system prevented the level in the system frcm reaching the low level alarm setpoint. Calculations had been performed to verify that the asere 1 l

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34 required level in the system would 'ev maintained by the automatic makeup feature of the RBCCW system. ~ Hcwever.- Radchem engineering was not aware of the timer / counter feature which detects excessive leakage f*om the system. -The counter / timer feature causes an alarm in the control room if at least 134 gallons has leaked from-the system within the past'13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> (average of 10.3 gallons per hour).

Radchem engineering stated that the feed and bleed activity was not coordinated with-operations arior to the opening of the valve because calculations indicated tlat the automatic makeup feature j of the.RBCCW systen was more'than adequate to account for the '

water drained from the system, Conclusions The flow impact upon the RBCCW System during feed and bleed activities was not thoroughly investigated by Radchem engineerin Radchem personnel failed to communicate and coordinate their work activities with operations personnel. This is identified as a negative observation.

c S2 Status of Security Facilities and Equipment-(71750)-

The inspectors toured the protected area and observed that the

. perimeter fence was intact and not compromised by erosion nor-disrepair. The fence fabric was secured and barbed wire was angled as required by the licensee's Plant Security Plan >(PSP).

Isolation zones were maintained on bcth-sides-of-the barrier and were free of objects which could shield or conceal an individua .

The inspectors observed that personnel?and packages entering the-  !

protected area were searched-either by special purpose detectors

.or by a physical'patdown for firearms, explosives and contraban Badge issuance was observed. as was the processing and escorting '

of visitors'.-Vehicles were searched. escorted and secured as described in applicable procedure On July 9. the inspectors observed portions of the security power system operability surveillance test. This test was for the Security Diesel Generator and Uninterruptible Power Supply-Syste On July 24. the inspectors reviewed the PSP related to a )hysical modification implemented in the plant entry and security )uilding

.(PESB). The modification was implemented as a preliminary measure for the future'implementetion of the " hand geometry" program for-entry;into the protected are The inspectors concluded that the areas- of security inspected met the applicable requirements. The operability test for the security power systems verified that the systems were mcintained

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in a reliableistandby condition. The physical modification-observed in the PESB was performed in accordance to the guidelines -

of the PS V.-Manaoement Meetinas  !

, Review of UFSAR Commitments A.recent discovery of; a licensee operating its facility in a manner contrary to the-Updated Final Safety Analysis Report-(UFSAR) description highlighted the need for-a special focused review that compares plant 3ractices, procedures and/or parameters to the UFSAR description. 4hile performing the ins)ections-discussed in this re) ort, the inspectors- reviewed t1e applicable portions of the UFSAR that related to the areas inspected. -The inspectors verified that the UFSAR wording was consistent with the

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o observed plant 3ractices. procedures, and/or parameters, except as noted above in 3aragraph E1.1.b. -The licensee's UFSAR states that >

if it is impracticar to maintain a six inch separation-between divisional electrical cables then the cables must be separated by i a metal barrier or anclosed in metal conduit. The-licensee installed-Siltemp tape as an electrical barrier. The licensee has implemented actions to revise the UFSAR to address the use of Siltemp as a barrier separation material.

Exit Meeting Summary L :The inspectors presented the inspection results to members of the licensee's management at the conclusion of the inspection on August 26, 1997. The license-acknowledged the findings presente An interim exit was conducted on July!11.199 The inspectors asked the licensee whether any materials examined during the inspection should be considered-proprietary. No proprietary information was identifie Other NRC Personnel On Site

.On August 7-8. Mr P.H. Skinner. Chief Reactor Projects Branch Division of Reactor Projects, visited the site. He met with the resident inspector staff to discuss licensee performance, and regulatory issues. .He toured the facilities to observe equipment

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in operation'and general plant conditions. He attended the

. morning management meeting for plant status and later met with the-plant general manager to discuss plant performance and other- i regulatory issue . .

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Enclosure

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. PARTIAL LIST OF PERSONS CONTACTED Licensee--

Anderson, J., Unit Superintendent Betsill.'J., Assistant General Manager - Operations Breitenbach. C. . Engineering Support Manager - Acting Curtis. S., Unit Superintendent Davis. D. , Plant Administration Manager-Fornel. P., Performance Team Manager Fraser.-0.. Safety Audit and Engineering Review Fupervisor -!

Hammonds. J., Operations Support Superintendent Kirkley, W. Health Physics and Chemistry Manager Lewis, J., Training and Emergency Preparedness Manager Madison, D.. Operations Manager Moore C. Assistant General Manager - Plant Support Reddick. R., Site Emergency Preparedness Coordinator Roberts.-P., Outages and Planning Manager-Thompson, J., Nuclear Security Manager Tipps. S., Nuclear Safety and Compliance Manager Wells. P., General Manager - Nuclear Plant INSPECTION PROCEDURES USED-IP 37551: Onsite Engineering IP 40500: Effectiveness of Licensee Controls in Identifying Resolving, and Preventing Problems-IP 61726: Surveillance Observations-IP 62707: Maintenance Observations-IP 62700: Maintenance Implementation-IP 71707: Plant Operations IP 71750: Plant Support Activities 1 IP--92700 f Onsite Follow-up of Written Reports- of Nonroutine -1 Events at Power Reactor Facilities IP 92901t Followup - Operations IP 92902: Followup.- Maintenance / Surveillance IP 92903: Followup - Followup Engineering:

IP 92904: Followup - P1 ant-Support ITEMS OPENED. CLOSED, AND DISCUSSED Ooened 50-321, 366/97-07_-01 _IFI Review of Licensee's Assessment of-the ALARA-Process' for the Unit 2 Reactor Coolant Leak Repair on the-RWCU Heat Exchanger (Section M1.5)

Enclosure

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50-321. 366/97-07-02 URI Resolve Concerns with respect to GL 87-02, Verification of Seismic Adequacy of Mechanical and Electrical Equipment in Operating Reactors Unresolved Safety. Issue (USI) A-46 (Section E2.1)

Closed 50-321/96-06-04 VIO Failure to Meet TS Surveillance Requirements Prior to Withdrawal of a Control Rod While in Cold Shutdown (Section 08.1)

50-321, 366/96-06-05 VIO Ineffective Corrective Actions to Strengthen the Technical Specification Surveillance Program (Section 08.2)

50-321/96-10-02 VIO Late 10 CFR 50.72 Notification (Section 08.3)

50-321/96-10-05 VIO Failure to Correct a Safety Related Alarm Deficiency (Section 08.4)

50-366/96-01 LER The Safety Limit Minimum ,

Critical Power Ratio (SLMCPR)

for Hatch Unit 2 Fuel Cycle 13 Was Not Conservative (Section E8.1)

50-321/97-01 LER Pressure Boundary Leakage Results in Condition Prohibited by the Technical Specifications (Section E8.2)

50-321/97-03 LER Rod Block Monitor Orerability Requirements Do Not Match Rod Withdrawal Error Ar.alysis (Section E2.2 and t8.3)

50-366/97-01 LER High pressure Coolant Injection System Ino)erable Following Unplanned Engineered Safety Feature Actuation (Section M8.1)

Enclosure

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50 366/97-0 LER Excessive Leakage Identified on Secondary Containment Bypass Valves (Section M8.2)

50-321, 366/96-15-02 VIO Maintenance Personnel Failure to follow Procedure during Valve Backseating Activities (Section M8.3)

Discussed 50-321, 366/97-03-05 IFI Review of 4160 VAC Wiring Separation Deficiencies (Section El.1)

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Enclosure