IR 05000321/1990014

Insp Repts 50-321/90-14 & 50-366/90-14 on 900512-0622.No Specific Strengths or Weaknesses of Licensee Programs Noted. Major Areas Inspected:Operational Safety Verification,Maint Observation,Surveillance Testing Observation & Events

ML20055H648
Person / Time
Site:	Hatch
Issue date:	07/12/1990
From:	Brockman K, Moore L, Randy Musser NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20055H646	List: IR 05000321/1990014 ML20055H645
References
50-321-90-14, 50-366-90-14, NUDOCS 9007270120
Download: ML20055H648 (13)

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• A40s, UNITED STOTES  !

p NUCLEAR REGULATORY COMM18SION  !

1. '~ (d REGION ll

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• fa 101 MARIETTA STREET,N ATLANT A.OEORGI A 30323

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t Report Numbers: 50-321/90-14 and 50-366/90-14

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Licensee: Georgia Power Company

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P.O. Box 1295 Birmingham, AL 35201 l Docket Numbers: 50-321 and 50-366 , e

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License Numbers: DPR-57 and NPF-5 Facility Name: Hatch 1 arid 2 '

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Inspection Dates: May 12 - June 22, 1990  ;

Inspection at Hatch site near Baxley, Georgia Inspectors: - ~ 7V2 '[O Randall A. Musser, Resident Inspector Date Signed

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A 7-/2 -fd LM. Moore, Reactor Inspector Date Signed Accompanying Person el: Lloyd Zerr Approved by: /wb K hneth E Mfh>544/ /2 T ut- 90 Date Signed Di9 vi sion 'o,.W.oqldfian, Chief, Project Section 3B f Reactor Projects SUMMARY Scope: This routine inspection was conducted at the site in the areas of Operational Safety Verification, Maintenance Observatio Surveillance Testing Observation, Operating Reactor Events, Plant Startup From Refueling, and Evaluation of-Licensee Self-Assessment Capabilit Results: No specific strengths or weaknesses of licensee' programs were identifie .

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9007270120 900713 FDR ADOCK 07000321 Q PDC

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t REPORT DETAILS _ Persons Contacted t Licensee Employees ,

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• C. Coggin, Training and Emergency Preparedness Manager .

D. Davis, Plant Administration Manager

• D. Edge, Nuclear Security Manager .

• P.-Fornel, Maintenance Manager  !

0. Fraser. Safety Audit and Engineering Review Supervisor -

G. Goode, Engineering Support Manager ,

• M. Googe, Outages and Planning Manager ,

• J. Lewis, Operations Manager

• C. Moore, Assistant General Manager - Plant Support H. Nix, General Manager - Nuclear Plant H. Sumner, Assistant General Manager - Plant Operations i'

S. Tipps, Nuclear Safety and Compliance Manager R. Zavadoski, Health Physics and Chemistry Managar

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Other licensee employees contacted included technicians, operators, mechanics, security force members and office personne ;

NRC Resident Inspectors t

• R. Musser

, *L. Zerr NRC management on site during inspection period:

K. Brockman, Chief, Reactor Projects Section 3B, Region II i L. Crocker, Project Manager, Hatch, Project Directorate 11-3, NRR G. Lainas, A/D for RII Reactors, Division of Reactor Projects I/II, NRR J. Rosenthal, Acting Deputy Director, Division of Reactor Safety. RII E. Rossi, Director, Division of Operational Events Assessment, NRR

• Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragrap . Operational Safety Verification (71707) Units 1 and 2 .

Unit 1 began the reporting period in the condenser retubing/ refueling outage that commenced on February 17, 199 Control rod withdrawal for the startup of Unit 1 from the outage consnenced at 1723 on June 1,199 Criticality was achieved at 2340 on June 1, 1990. Following the completion of all main turbine testing, Unit I was synchronized with the grid at 0416 on June 6, 1990. On June 10, 1990, Unit 1 was' operating at ,

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4 reduced load due to problems in the off-gas system. At 0926 Unit I was manually scrammed from 25% rated thermal power when off-gas carbon vessel i temperatures displayed a were continually increasing trend. (This Unit I scram is discussed in paragraph 5). At approximately 1430, a gas sample ,

taken downstream of the seventh adsorber vessel confirmed that the carbon ~

was smoldering. At 1438, an NUE was declared based on a fire lasting more that 10 minutes. On June 16, 1990, at 1425, the fire in the offgas system was declared out and the NUE was terminated. Rod withdrawal for the restart of Unit 1 commenced at 1543 on June 16, 1990, with the unit attaining criticality at 1743. Unit I was synchronized with the grid at 0048 on June 18, 1990. On June 19, 1990, with Unit I at approximately 90%

RTP, the unit began aperiencing problems maintaining normal condenser vacuum. Inicstigation revealed that the "A" condenser hotwell was operating with a water level of approximately 12 feet while the "B" ,

condenser hotwell was operating with a water level of approximately 3-4 *

feet (3-4 feet being the normal operating level). At 1745 on June 19, 1990, in an effort to determine the cause of the level differential .

between the two condenser hotwells. Unit 1 commenced a controlled power reductio On June 20, 1990 at 0200, due to high main turbine vibration and the sustained differential in hotwell water levels, Unit 1 entered the normal plant shutdown procedure. While in the process of reducing powe Unit I scrammed on low reactor vessel water level. (ThisUnitIscramis discussed in paragraph 5 of the report). Rod withdrawal for the restart ,

of Unit I connenced at 0600 on June 22, 1990 with the unit attaining -

criticality at 0846. Unit 1 ended the reporting period at approximately 22% RTP in preparation for synchronization with the grid. Unit 2 operated at power throughout the reporting perio The inspectors were kept informed on a daily basis of the overall plant status and any significant safety matters related to plant operation Daily discussions were held with plant management and various members of-the plant operating staff. The inspectors made frequent visits to the control room. Observations included control room manning, access control, ,

operator professionalism and attentiveness, adherence to procedure l adherence to limiting conditions for operation, instrument readings, )

recorder traces, annunciator alarms, operability of nuclear '

instrumentation and reactor protection system channels, availability of 1 power sources, and operability of the Safety Parameter Display system, i These observations also included log book entries, tags and clearances on I equipment, temporary alterations in effect, ECCS system lineups, ,

containment integrity, reactor mode switch position, conformance with l technical specification safety limits, daily surveillances, plant chemistry, scram discharge volume valve positions, and rod movement controls. This inspection activity involved numerous informal discussions with operators and their supervisor The proper configuration of selected safety-related systems was confirmed on essentially a weekly basis. These confirmations involved verification of proper valve and control switch positioning, proper circuit breaker and fuse align ~.t, and operability of related instrumentation and support ,

systems. riajor components were also inspected for leakage, proper l

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lubrication, cooling water supply, and general condition. On May 17-18, 1990, the inspector walked down the Unit 2 Standby Gas Treatment Syste ,

Proper electrical, valve, and switch alignments were confirmed using i Attachments 1, 2 and 3 to procedure 3450-T46-001-25. On May 24, 1990, the ;

inspector walked down the Unit 2 Remote Shutdown Panel. Proper switch ;

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alignments and labeling was confirined using Table 1 of procedure 34SV-082-001-25 and Technical Specification Table 3.3.6.3-1. On May 29, !

1990 the inspector walked down the Unit 1 "1A" and "1C" emergency diesel generators. Proper switch, breaker, and valve lineups were confirmed using procedure 3450-R43-001-15. On May 31, 1990 the Unit 1 nuclear instrumentation was walked down. Proper switch positions were verifie On June 14, 1990, the inspector walked down portions of the Unit 1 off gas '

system. Proper switch, breaker, and valve lineups were verified ~using ;

procedure 34S0-N62-001-1 :

i General plant tours were conducted on, at least, a weekly basi Portions i of the control building, diesel generator building, intake structure, turbine building, reactor building, and outside areas were toure .

Observations included general plant / equipment conditions, fire hazards, fire alarms, fire extinguishing equipment, emergency lighting, fire barriers, emergency equipment, control of ignition sources and flammable .

materials, and control of maintenance / surveillance activities in progres '

Radiation protection controls, implementation of the physical security i program, housekeeping conditions / cleanliness, control of missile hazards, and instrumentation and alarms in the main control room were also observe The inspectors observed selected operations shift turnover briefings to confirm that all necessary information concerning the_ status of plant systems was being addresse Each briefing was conducted by the oncoming ,

50S. The inspectors noted that each SOS discussed existing plant problems, activities that were anticipated for the shif t, and any new standing orders or management directives. Radiological and industrial safety were generally stressed. The STAS discussed any.recent procedure I revisions that impacted on the attendees. The inspectors attended shift turnover briefings on the following dates and shifts: May 20, 1990 -

Night; May 21, 1990 - Day; May 27, 1990 - Day; May 27, 1990 - Night;

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May 28, 1990 - Day; May 29, 1990 - Day; June 1, 1990 - Night; June 3, l 1990 - Da i l

Several safety-related equipment clearances that were active were reviewed to confirm that they were properly prepared and placed. Involved circuit breakers, switches, and valves were walked down to verify that clearance tags were ir, place and legible and that equipment was properly positione Equipment clearance program requirements are specified in licensee procedure 30AC-0PS-001-0S, "Lontrol of Equipment Clearances and Tags." On i May 23, 1990, Unit 1 equipment clearance 1-90-1299 was walked down. This ,

clearance was pieced to comply with the requirements of the RHR system I operating procedure, 34S0-E11-001-15, for the shutdown cooling mode of

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operation. On June 12,1990 Unit 1 equipment clearance 1-90-1504 wes j

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walked down. This clearance was placed to support maintenance on glycol refrigeration machine IN62-8004 Implementation of the licensee's sampling program was reviewed by the inspector. This review involved observation of sampling activities

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(reactor coolant and tank sampling) and chemistry surveillance. Related records were also reviewed. During this inspection period, the inspector monitored the following activities. On May 29, June 5, and June 6. 1990, the inspector observed the tritium sampling of the main stack, the particulate, iodine, and noble gas sampling of the Unit I and Unit 2- ,

reactor building vents, recombiner building vent, and the main stack in ~

accordance with the applicable portions of procedure 64CH-SAM-005-05. On June 5, 1990, the inspector observed the sampling of the Unit I reactor coolant system during plant startup in accordance with 64CH-ADM-001-0 The licensee's deficiency control system was reviewed to verify that the system is functioning as intended. Licensee procedure 10AC-MGR-004-05, i

" Deficiency Control System " establishes requirements and responsibilitie for the preparation, processing, review, and disposition of deficiency reporting documents. This procedure applies to all deficiencies affecting equipment, procedures, or personnel. Deficiencies are reported on Deficiency Cards. On May 24, 1990, the inspector reviewed DCs that had been generated the previous day. The inspector verified that DCs had been ,

i prepared as required by the controlling procedure and that the deficiencies that were noted in the Shift Supervisors' logs.had been documented on DCs. More specifically, it was noted that DC 2-90-1566 had been generated to document the failure of NUMAC fission product monitor 2D11-K630. It was also noted that DC le90-3510 had been prepared to document tne failure of the IB recirculation seal line isciation valve 1B31-F014B. On June 19, 1990, the inspector also reviewed recently prepared DCs and verified that problems observed in the plant had been i properly documented. The inspector observed that DC 1-90-4299 had been i generated to document the freezing of the nitrogen vaporizer, 1T48-B001, it was also noted that DC 2-90-1752 had been prepared to document the missed surveillance of the IB Diesel Generato Selected portions of the containment isolation lineup were reviewed to confirm that the lineup was correct. The review involved verification of proper valve positioning, verification that motor and air-operated valves '

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were not mechanically blocked and that power was available (unless blocking or power removal was required), and inspection of piping upstream of the valves for leakage or leakage paths. On May 23, 1990, the inspector reviewed the following Unit 2 containment isolation valves:

2G11-F004A, 2T48-F311, 2T49-F004A and 2T49-F004B. On June 20-21, 1990 the inspector reviewed the following Unit 2 containment isolation valves:'

2D11-F050, 2011-F052, 2E11-F041B, 2E11-F041D, 2E11-F028A, 2E11-F028B, 2E41-F121, 2E41-F122, 2E51-F105, 2P33-F004, 2P33-F007, 2P33-F012, 2P33-F015, 2T48-F104, 2T48-F115, 2T48-F318, 2T48-F363A, and 2T48-F363 On June 22, 1990, the inspector verified that all required notices to i workers were appropriately and conspicuously posted pursuant to j

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t-5 10 CFR 19.1 Related posting requirerrents are delineated in Section 8.1 of licensee procedure 00AC-REG-00105, " Federal and State Reporting Requirements." This procedure establi;hes posting locations at the Waste Separation and Temporary Storage Facility, Simulator Building near the breakroom, Service Building outside the breakroom, and the Plant Entrance Security Building. The inspector reviewed the postings at these ,

locations (with the exception of the Waste Separation and Temporary Storage Facility) and observed no discrepancie No violations or deviations were identifie . Maintenance Observation (62703) Unit 2 During the report period, the inspector (s) observed selected maintenance activities. The observations included a review of work documents for adequacy, adherence to procedure, proper tagouts, adherence to technical specifications, radiological controls, observation of all or part of the actual work and/or retesting in progress, specified retest requirements, and adherence. to the appropriate quality controls. The primary maintenance observations during this month are summarized below:

Maintenance Activity Date Repair / Calibration of the Unit 2 05/23/90 ;

Fission Product Instrument, in

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accordance with procedures 575V-D11-023-2S and 57SV-D11-002-25 Repair of the "B" Unit 2 Reactor 05/29/90 Building Vent Radiation Monitor, in accordance with MWO 2-90-1537 -

and procedure 57SV-D11-022-2S Repair of control room annunciator 06/20/90

"L0 Temp Hl/LO, Jacket Temp HI/LO Crankcase Pressure HI," in accordance with MWO 2-90-1709 Replacement of packing follower bolts 06/21/90 on valve 2P41-F3002, in accordance l with MWO 2-90-570 Calibration of the Post Accident 06/22/90 l Sampling System Hydrogen Analyzer, in accordance with procedure 62CI-CAL-018-0N .

No violations or deviations were identified, l

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4. SurveillanceTestingObservations(61726) Unit 2 The inspector (s) observed the performance of selected surveillances. The ,

observation included a review of the procedure for technical adequacy, ;

conformance to technical specifications, verification of test instrument ;

calibration, observation of all or part of the actual surveillances, removal from service and return to service of the system or components affected, and review of the data for acceptability based upon the t acceptance criteria. The primary surveillance testing observations during L this month are sunnarized below:

Surveillance Testing Activity Date MSlv Leakage Control System 05/18/90 Valve operability, in accordance .

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with procedure 345V-E32-001-2S Battery Pilot Cell Surveillanc /22/90 in accordance with procedure 52SV-R42-001-25 ApRM Functional Test, in accordance 05/27/90 ,

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with procedure 345V-051-002-2S

Diesel Generator 2A Monthly Tes /28/90 in accordance with procedure 345V-R43-001-2S Diesel Generator 2C Semi-Annual 05/28/90 Test, in accordance with procedure

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34SV-R43-006-2S No violations or deviations were identifie . OperatingReactorEvents(93702) Unit 1 The inspectors reviewed activities associated with the below listed reactor events. The review included a determination of the cause, the safety significance of the event, the performance of personnel and systems, and the correctivo action (s) generated. The inspectors examined instrument recordings, computer printouts, operations journal entries, scram reports and had discussions with operations, maintenance, and j engineering support personnel, as appropriat ]

On June 10, 1990, Unit 1,was operating at reduced load due to problems in I l the off-gas system. At 0926 Unit 1 was manually scranned form 25% rated l thermal power when some of the carbon vessel temperatures were observed to

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br continually increasing. Immediately following the scram, the SJAE was isolated and off gas-flow was stopped. It was not apparent, at this point, whether the carbon was smoldering but discolored paint on the vessels and vessel piping did indicate that the system had overheate This overheating was believed to have been caused by a hydrogen ignition,

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1 At approximately 1125 a nitrogen purge to the off gas system was initiated i in accordance with abnormal operating procedure 34AB-0PS-038-15. " Failure i of Recombiner and Control of Sustained Combustion in the Off Gas System." )

Subsequently, at approximately 1430, a gas sample taken downstream of the !

seventh adsorber vessel confirmed that'the carbon was smoldering. At

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1438, an NUE was declared based on a fire lasting more than 10 minute At 0245 on June 11, 1990, the licensee increased the rate of nitrogen 3 purge of the off gas adsorber vessels to approximately 70 SCFM (from a- ;

previous purge rate of approximately 12 SCFM). Nitrogen purge flow j continued to the off gas system and at 1425 on June 16,~ based on the !

analysis of the exit gases and exit gas temperatures, the fire was declared out and the NUE was terminate '

Licensee investigation revealed that the cause of the carbon fire was a hydrogen ignition. Hydrogen level in the off gas system was greater than 4% for approximately 17.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> prior to the event. The licensee estimated that, at times, the process flow may have been as much as 30%

hydrogen. Normally, hydrogen is removed in a catalytic recombiner. The catalytic elements, however, had become wetted as a result of a lack of heating by the upstream off gas preheater. The major problem with the preheater was that neither condensate return pump was capable of pumping sufficient condensate from the preheater tube side back to the off gas boiler. Thus, the preheater overfilled and lost the ability to heat and dry the process flo On June 19, 1990, with Unit 1 at approximately 90% RTP, the unit began experiencing problems maintaining normal condenser vacuum. Investigation >

revealed that the "A" condenser hotwell was operating with a water level

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of approximately 12 feet while the "B" condenser hotwell was o)erating with a water level of approximately 3-4 feet (3-4 feet being t1e normal operating level). At 1745 on June 19, 1990, in an effort to determine the cause of the level differential between the two condenser hotwells, Unit I commenced a controlled power reductio On June 20, 1990 at 0200, due to i high main turbine vibration and the sustained differential in hotwell water levels, Unit 1 entered the normal plant shutdown procedure. While

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i in the process of reducing power, Unit 1 scramed at 0345 on June 20, )

1990, due to low reactor vessel water level. The unit was operating at approximately 25% RTP at the time of the scram, j While in the process of reducing load, the IC Condensate Booster aump was i removed frcm service at approximately 0340 on June 20, 1990. Wit 11n 30 ;

seconds of removing the IC Condensate Booster Pump from service, reactor i vessel water level began a slow, steady decrease. Feedwater flow spiked I down when the booster pump was removed from service as expected, however, I feedwater flow did not recover to its previous level. As water level ;

continued to decrease, it became evident to the operators that the j feedwater master controller was unable to increase the speed of the '

operating 1B RFP. At this point, the operators took manual control of the l 1B RFP using its individual controller. A 100% demand signal was given to the 1B RFP, but after initially increasing the speed of the IB RFP from I approximately 2800 rpm to 3200 rpm, the pump began to slowly decrease in I l

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speed. At this speed, sufficient discharge head was not developed and feedwater flow was, therefore, inadequat Following the scram, reactor vessel water level decreased to approximately 35 inches below instrument zero. The High Pressure Coolant Injection and Reactor Core Isolation Cooling systems automatically started and injected as designed. HPCI flows were reported by the operators to be erratic during its start and brief (less than two minutes) run. The 1A RFP was started, both HPCI and RCIC were manually tripped by.an operator, and reactor water level was restored in a controlled manner. In addition to the initiation of HPCI and RCIC, both recirculation pumps tripped, the reactor water cleanup system isolated (only the inboard valve closed) and the 1A standby gas treatment system auto-starte As noted, the "B" trains (Units 1 and 2) of the standby gas treatment system did not auto-start and one half of the Group 5 PCIS valves did not isolate. Since the nominal reactor vessel water level setpoint for these actuations is minus 35 inches, the failure of the actuations to occur was initially questioned. However, due to level turning at the setpoint (minus 35 inches) for the actuation of the SBGT and Group 5 PCIS valve 1G31-F004, one of the level transmitters (N0810) did not pick up. The level transmitter was operable and would have picked up if the level had decreased another inch, or so. Given that the transmitter did not pick up, the response of the plant was prope I The source of the initial vacuum loss was excess trash in the condenser hotwell. Seven bags of debris were recovered from the "A" hotwell by the licensee. The licensee is currently investigating-how and why this material was lef t in the condenser following the condenser retubing projec Review of these events by the resident inspectors will remain open pending review of the full Event Review Team Reports, the LERs, and the licensee's corrective action Within the areas inspected, no violations or deviations were identifie . PlantStartupFromRefueling(61707and71711) Unit 1 Prior to the Unit I startup, the inspector performed independent walkthroughs of selected systems to verify they had been returned to an operible status and that the restoration was conducted in accordance with the itcensee's approved procedures. More specifically, on May 29, 1990, the '1A" and "10" emergency diesel generators were walked down. The Unit I nuclear instrumentation was walked down on May 31, 1990. No significant discrepancies were noted. However, while conducting the walkdown of the L emergency diesel generators, two minor discrepancies were identified, Procedure 3450-R43-001-15 " Diesel Generator Standby AC System," contained f j

an editorial error in that it required valve IR43-F107C (D/G IC Jacket i Water Coolant Heater Drain Valve) to be open when it was actually closed

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and capped (closed and capped is the correct position). The inspector j also found that the labeling on.two valves, 1P52-F2217 and IPS2-F2215, had i been interchanged. These discrepancies were brought to the attention of 1 the Unit I shift supervisor. Action was immediately taken to correct the J deficiencies, i

The inspectors also reviewed two licensee training activities as part of the inspection. On May 24, 1990, the inspectors attended a training ;

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session for operations personnel on DCRs that had been implemented during the Unit I refueling / condenser retubing outage. The training was ;

conducted in accordance with instructor outline 50-IH-75203-00. The inspectors observed that the instructor was well prepared and effectively responded to a broad range of questions on the DCRs. The inspector also reviewed a training initiative that was undertaken during the period May ,

29-31, 1990. During this period, the-licensee conducted plant startup 3 training on the simulator for licensed operations personnel ("A", "B", +

"C", and "E" teams) scheduled for duty during the Unit 1 startup. The :

inspector reviewed the specifics of this refresher training as delineated l in simulator guide LT-SG-59318-05, and noted that the training was- i

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comprehensive and included potential equipment malfunction The inspectors witnessed port hns of the Unit I startua to verify that ;

control rod withdrawal < were properly controlled and t1at operations were ,

conducted in accordr. ace with approved procedures and the technical-specifications. Tne startup was performed in accordance with Revision 13 .

of procedure 34G0-0PS-001-15 " Plant Startup," which became effective on June 1, 1990. The status of plant systems and surveillances required for .

startup was confirmed in accordance with Revision 5 of procedure

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t 34G0-0PS-003-IS, "Startup System Status Checklist," which became effective ,

on May 29, 1990. The inspectors noted no discrepancies during the observation of operations personnel conducting the startup or the review ;

of related procedures and documentatio '

The inspector witnessed the shutdown margin demonstration that was )

performed in accordance with Revision 0 of procedure 42CC-ERP-010-0S The i demonstration was performed on June 1, 1990, soon after criticality was I achieved in Unit 1. The inspector reviewed the procedure for techr.ical adequacy, verified the licensee's calculations, and verified that data supplied in the Cycle Management Report was utilize No violations or deviations were identifie ;

1 Evaluation of Licensee Self-Assessment Capability (40500) Units 1 and 2

Evaluation of the licensee's self-assessment capability included review of self-assessment functions at various levels of plant activity from :

corporate to peer level review of line level function The following )

functions or activities were reviewed: onsite and offsite review i comittees, problem identification programs trending, QA audit and

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surveillance, Event Review Team,-department level self-assessment in maintenance, and the informal inter-departmental peer review progra J l

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1 These functions and activities demonstrate a generally adequate capability 1 to assess plant performance and contribute to the prevention of problem The Safety Review Board minutes for 1989 and 1990 demonstrated the offsite $

review comittee was accomplishing the safety review activities required ;

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by plant comitments. The minutes documented review of onsite review committee meeting minutes, LERs, QA audits. safety evaluations, plant- ,

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problems and plant events. The minutes demonstrated corporate management maintained involvement in plant issues and activities. Additionally, it was evident that the SRB assessed the effectiveness of plant activities on specific issues (e.g. Local Leak Rate Test failures, Waste Management,-

Drywell Cooling, and IB Diesel Generator operability).

Plant Review Board functions were' evaluated by. observation of PRB t meetings, review of PRB minutes, and discussions with PRB members. The conclusion of this evaluation was that the PRB effectively performed the Technical Specification required safety functions of the onsite review committee. An important safety function performed effectively by the PRB was the assessment of plant procedures prior to use to assure the incorporation of adequate safety considerations; 'The PRB has routinely reviewed individual LERs and Significant Occurrence Reports, assessing the thoroughness of root cause determinations and proposed corrective action Meeting minutes were adequately detailed and demonstrated PRB participation in plant activities and compliance with TS requirements for onsite review committee activities, ,

Corrective action programs at Hatch have been effective in processii.g i

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identified plant problems; however, trending of the different proble ;

identification mechanisms has produced inconsistent results. Trending of plant wide identified problems is performed by two groups using separate information sources. Nuclear Safety and Compliance trends Deficiency ,

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Cards and SORS, QA trends, QA audit findings, INP0 and NRC findings. The

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primary 1989 causes for identified deficiencies according to NSAC trending was design, procedures, and personnel respectively. The QA trend report

! for this period, which was based wholly on the findingzs of the QA organization, indicated the primary cause for identified deficiencies was personnel, procedure, and design, respectively. The. inconsistency in ,

cause trends demonstrated a discrepancy in root cause determination performance for the different problem identification activitie Trending at Hatch is pe' formed on a plant wide basis and does not establish departmental ae. countabilit For example, personnel error or ;

procedure deficiency crends reflect performance for the entire plant. A i more detailed breakdawn by departments would provide an indicator of which ;

departments were su;cessful in reducing these deficiency causes. This information would '>rovide valuable self-assessment information contributing to improvements in other department l A formal mechanism for overview of trending and self-assessment activity is being established in the third quarter 1990. This mechanism will be a management review committee which will provide an integrated review of d

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plant self-assessment information. This overview function is anticipated l to enhance the licensee overall self-assessment capabilit '

The QA organization, Safety Audit Engineering Review, performed compliance assessments of safety related activities. SAER aedit activities met TS requirements for.the monitoring of safety related cctivities and, additionally, performed special audits'in response to management requests l and recognized regulatory and nuclear industry issues. Special audit subjects in 1989 and 1990 included the E0P procedure upgrade program, the processing of INPO SOERs, the TS clarification program, vendor  :

information, and contract administratio SAER also performed real time !

surveillances of specific plant activities. QA findings were tracked to resolution and reported to management via audit reports and annual trend reports.. The SAER audits and surveillances provided licensee ,

self-assessment functions contributing to the overall self-assessment capabilit .

Event Review Teams provide a focussed self-assessment function for evaluation of significant events. ERTs have been used at Hatch since .

1977. Review of ERT reports in 1989 and 1990 indicated an improved :

capability of the teams to assess plant events and determina . cot caus Formal root cause evaluation training provided to the ;,lant staff since 1989 has contributed to the improvement in ERT capability. ERT recommendations are entered into an action item tracking system and are ,

formally scheduled for closure. Review of the tracking schedule demonstrated that the recommendations were followed up in accordance with the projected schedule. An ERT initiated to investigate the potential common cause factors for a number of personnel errors that initiated operational events in the previous year effectively identified a potential common cause related to non-routine evolutions involving off-normal system configurations, i

Self-assessment activity within the maintenance department included component and personnel performance. Trending of corrective maintenance on plant equipment identified components experiencing relatively high failure rates. Corrective action, including design changes and additional preventive maintenance, resulted in a decreased failure rate in recorders, reactor water clean-up pumps, and sample chillers. Post maintenance functional test failures were trended and accountability for test failures assigned at the line supervision level. Test failures trending provided ,

an indicator for assessment of maintenance performance. Accountability provided an incentive for performance improvemen The Quality Check program is an informal self-assessment activity conducted on an inter-departmental level. Quality checkers conduct a peer level review of department functions and report results of observations to their respective management. This activity did not result in documented findings, trends, or broad scope assessments of performance. The quality check program provided_a direct feedback to management of field-performance and therefore provided an additional element of plant ,

self-assessment capability, i

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e Within the areas inspected, no violations or deviations were identifie This evaluation generally demonstrated that the licensee has a adequate -

and effective self-assessment progra .

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8. ExitInterview(30703) l The inspection scope and findings were summarized on June 26, 1990, with those persons indicated in'partgraph 1 above. Particular emphasis was ,

placed on the operating reactor ovents discussed in paragraph 5, and.the 1 observations of the inspectors performing the Plant Startup From Refueling i and the Evaluation of Licensee Self-Assessment Capability modules. The '

licensee did not identify as or reviewed by the inspector (proprietary s) during any of theDissenting this inspection.- material provided to comments were not received from the license . Acronyms and Abbreviations -

A/D -

Assistant Director APRM - Average Pcwer Range Monitor CFR -

Code of Federal Regulations DCs - Deficiency Cards DCR - Design Change Request D/G -

Diesel Generator ECCS - Emergency Core Cooling System ERTs -

Event Review Teams ESF - Engineered Safety Feature i HPCI - High Pressure Coolant Injection INP0 -

Institute of Nuclear Power Operations LER - Licensee Event Report MSIV -

Main Steam Isolation Valve MWO -

Maintenance Work Order NRC - Nuclear Regulatory Commission NRR -

Office of Nuclear Reactor Regulation NSAC - Nuclear Safety and Compliance NUE -

Notice of Unusual Event PCIS -

Primary Containment Isolation System PRB - Plant Review Board QA - Quality Assurance -

RCIC -

Reactor Core Isolation Cooling ,

RFP -

Reactor Feed Pump RHR - Residual Heat Removal System RTP -

Rated Thermal Power ,

SAER - Safety Audit Engineering Review SBGT - Stand By Gas Treatment SCFM - Standard Cubic Feet per Minute SJAE - Steam Jet Air Ejector SOERs - Significant Occurrence Event Reports  ;

SORS - Significant Occurrence Reports i SOS - Superintendent on Shift  !

SRB - Safety Review Board STA -

Shift Technical Advisor TS - Technical Specifications I

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