IR 05000321/1993026

Insp Repts 50-321/93-26 & 50-366/93-26 on 931031-1127.No Violations Noted.Major Areas Inspected:Operations, Surveillance Testing,Maintenance Activities,Warehouse Storage,Self Assessment & Mods

ML20059B699
Person / Time
Site:	Hatch
Issue date:	12/20/1993
From:	Christnot E, Holbrook B, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20059B568	List: IR 05000321/1993026 ML20059B564
References
50-321-93-26, 50-366-93-26, NUDOCS 9401040221
Download: ML20059B699 (24)

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UNITED STATES NUCLEAR REGULATORY COMMISSION yb

/gy n q\.' a REG!oN11

,Qi g 101 MARIETTA STREET, N.W., SUIT E ?XO ir; f{9g , ATLANT A, GEORGI A 30323 0199

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..o Report No /93-26 and 50-366/93-26 Licensee: Georgia Power Company P.O. Box 1295 Birmingham, AL 35201 Docket Nos.: 50-321 and 50-366 License Nos.: DPR-57 and NPF-5 facility Name: Hatch Nuclear Plant Inspection Conducted: October 31 - November 27, 1993 Inspectors: [/-V Jr., Sr. Resident Inspector

/ M/ t//f3 gLesard K , DateSytned

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W Edward

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.Cgri riot, Resident Inspector

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/' p/14/f3 o Mio es,ident Inspector Dgte Signed Approved by: lu

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would not function as ' described in the Final Safety Analysis Report. The licensee's corporate office staff had identified the problem and performed a review. However, communications to the onsite organization did not convey the necessity for procedural changes and training to address the issue. Consequently, onshift .

i operators were not aware of the problem and procedure revisions l l had not been initiated (paragraph 2c). '

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I REPORT DETAILS Persons Contacted Licensee Employees

• L. Adams, Nuclear Security Supervisor

• J. Ammons, Plant Operator D. Bennett, Chemistry Superintendent  !

• J. Betsill, Unit 2 Operations Superintendent

• E. Burkett, Engineering Support Supervisor

• Coggin, Training and Emergency Preparedness Manager *

• Curtis, Operations Support Superintendent

• Davis, Plant Administration Manager

• Duvall, Plant Engineering Supervisor

• Eason, Safety Audit and Engineering Review

• P. Fornel, Maintenance Manager

• 0. Fraser, Safety Audit and Engineering Review Supervisor a G. Goode, Engineering Support Manager

• M. Googe, Outages and Planning Manager 1

• J. Hammonds, Regulatory Compliance Supervisor

• J. Heidt, Manager-Hatch Project Nuclear Engineering and Licensing B. Howard, Building and Grounds Foreman *

W. Kirkley, Health Physics and Chemistry Manager C. Moore, Assistant General Manager - Operations '

• J. Payne, Senior Engineer D. Read, Assistant General Manager - Plant Support

• K..Robuck, Manager, Modifications and Maintenance Support i

• H. Sumner, General Manager - Nuclear Plant  !

J. Thompson, Nuclear Security Manager

• S. Tipps, Nuclear Safety and Compliance Manag *J. Watts, Operations Shift Supervisor '

• P. Wells, Operations Manager  :

Other licensee employees contacted included technicians, operators, mechanics, security force members and staff personne NRC Resident Inspectors  !

• L. Wert

• E. Christnot 1

• B. Holbrook -

NRC management / officials on site during inspection period:

J. Jaudon, Deputy Director, Division of Reactor Safety, Region II ->

B. Mallatt, Deputy Director, Division of Radiation Safety and l Safeguards, Region II

• Attended exit interview  :

Acronyms and abbreviations used throughout this report are listed in the -

last paragrap j

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2 , Plant Operations (71707) (92701) (93702) Operations Status and Observations Unit I was manually scrammed at 9:52 a.m. EST on November 11, 1993. At 5:15 p.m. on November 10, the unit had begun a controlled shutdown due to an EHC system piping leak. The leak had previously been identified as a " pencil lead size" stream coming from a cracked weld on a line to a turbine bypass valv During attempts to place a temporary clamp device on the leak, the .

leak increased and a shutdown was required to repair the pipin j The unit was maintained in a hot shutdown condition during the '

repair and testing activities. A reactor startup was commenced at 4:15 a.m. EST on November 13. Criticality was achieved at 10:22 a.m. on November 13, and 100 percent RTP was obtained on November 15, 1993. The unit was maintained at approximately 100 percent i RTP for the remainder of the inspection period. There were several other instances in the past year in which significant EHC i leaks were identified. Some EHC leaks resulted in unit shutdown ]

The cause of the failures have been attributed to vibration of the '

EHC piping. The licensee plans to install modifications during upcoming outages to reduce the vibration level !

Unit 2 initiated a shutdown at 3:00 p.m. EST on November 7, due to an increase in unidentified DW leakage. The increased DW leakage had been identified and was being closely monitored by the licensee. Inspection Report 50-321,366/93-17 discussed this .j issue. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> average leakage rate had increased to I approximately 3.20 gpm. The source of the leakage was identified early on November 8, as the pressure seal of valve 2E21-F006B (Core Spray B loop testable check valve). The unit was placed in cold shutdown and repairs were completed. Paragraph 4c contains j additional details of the valve repairs. Paragraph 5 describes observations involving the installation of the reactor vessel

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water level indication keepfill system, in response. to NRC

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Bulletin 93-03. Unit criticality was achieved at 3:36 p.m. EST on November 14 and returned to 85 percent RTP The unit is being maintained at approximately 85 percent RTP due to an identified fuel leakage problem. Several control rods remain fully inserted to suppress neutron flux in the area of the fuel lea Activities within the control room were monitored routinel Inspections were conducted on day and on night shifts, during weekdays and on weekends. Observations included control room manning, access control, operator professionalism and attentiveness, and adherence to procedures. Instrument readings, I recorder traces, annunciator alarms, operability of nuclear

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instrumentation and reactor protection system channels,  !

availability of power sources, and operability of the SPDS were '

monitore Control Room observations also included ECCS system lineups, containment integrity, reactor mode switch position, l

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scram discharge volume valve positions, and rod movement control During a routine tour of the control room on November 9, one of ,

the inspectors noted that a tracking LC0 had not been initiated for an inoperable containment isolation valve. Since Unit 2 was in cold shutdown, the valve was not required to be operable by T Procedure 34SV-B21-006-02S: Feedwater Check Valve Operability l Test, had been completed unsatisfactorily at 11:32 p.m. on November Valves 2B21-F077A and 2B21-F076B did not close when the CR switch was placed in "close." Procedure 31G0-0PS-006-0S:

Limiting Conditions for Operations (LCO), required that a ,

tracking LC0 be initiated to address such an instance. Valve j 2B21-F077A is listed in TS Table 3.6.3-1 as a containment

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! isolation valve. The inspector's concern was that repairs to I these valves might not receive proper emphasis prior to plant i startup. The inspector verified that maintenance activities (MWO ;

2-93-4545 and 2-93-4546) had been initiated on the valve !

Operators had apparently overlooked the fact that these valves are '

containment isolation valves and the tracking LC0 was not i initiated. The Unit 2 shift supervisor initiated a LC0 i immediately after being informed of the issue. The inspectors .l verified that the valves had been returned to a operable status 1 prior to reactor startu ]

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During the controlled shutdown of Unit 2, due to the 2E21-F006B !

leak, an entry into TS 3.0.3 was made. At 5:00 a.m. on November q 8, the "A" loop of RHR was placed in alignment for SDC operatio '

In accordance with procedures, an LC0 was initiated. TS 3.5. permits operation for a period of 7 days, provided that both CS loops are operable. At 8:56 a.m., the shift activated a clearance on the "B" CS loop to support maintenance activities on the 2E21-F006B valve. This required entry into TS 3.5.3.1, which allows one CS subsystem to be inoperable for 7 days, provided both LPCI subsystems are operable. Because the requirements of these TSs could not be met, the shift entered TS 3. One of the ;

inspectors attended the shift turnover at 7:00 a.m. that day, and d noted that management had directed that the unit be maintained in hot shutdown. The entry into TS 3.0.3 was made with the knowledge ;

of operations management. The inspectors concluded that operations department management's direction that the unit was to be maintained in hot shutdown played _ a major role in the entry into TS 3.0.3. Immediately upon being informed of the entry into TS 3.0.3, the plant manager discussed the issue with operations management. The plant manager concluded that it would have been l more appropriate for the unit to have been placed in cold shutdown prior to isolation of the CS header. The inspectors have previously noted that Hatch is usually conservative regarding the operability of the CS system during shutdown periods. The inspectors concluded that TS requirements were not violated. The unit was placed in cold shutdown at 1:16 am on November ,

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4 l Plant tours were taken throughout the reporting period on a l routine basis. The areas toured included the following: j Reactor Building Diesel Generator Building Fire Pump Building Intake Structure Station Yard Zone Turbine Building During the plant tours, ongoing activities, housekeeping, security, equipment status, and radiation control practices were observed. No significant deficiencies were noted. On November 2, during a routine tour of the intake structure, one of the !

inspectors noted that valve 1E11-F904A (RHRSW air release valve)

was leaking. RHRSW was in operation for torus coolin Subsequently, the inspector determined that a deficiency card describing the problem had been initiated by a PE0 earlier that day. The inspector also informed the system engineer, who promptly confirmed that the RHRSW loop was not rendered inoperable due to the leak. Inspection Report 50-321,366/92-15 contains discussions of a longstanding problem involving the air release valves. In response to repetitive failures, the floats in the >

valves were replaced. During the next scheduled outage, the licensee plans to implement modifications on the RHRSW piping to ;

reduce the severity of surges when the pumps start. This will also reduce the chances of future RHRSW strainer failures. The i inspectors concluded that the leaking valve had been promptly !

identified and the appropriate actions were completed. The ;

inspectors will continue to monitor the air release valve operation ,

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b. Unit 2 Station Service Battery Inspection Report 50-321,366/93-17 described the licensee's ongoing activities concerning the identification of small cracks in several cell jars of the Unit 2 Station Service Batteries. A total of five cell jars were identified as having cracks. Three of the cells have been replaced and tested. Portions of these replacement and testing activities were observed by the inspecto At the end of this reporting period, only two cells (numbers 16 and 89) of the 2B battery have cracks and have not been replace The licensee has initiated a monitoring process to check the cells for crack growth and electrolyte leakag In recent weeks, investigation by the licensee identified the most .

probable cause of the cell cracking to be expansion of the lead in the cell plate Information indicates that a combination of high {

ambient temperatures and increased temperatures during discharge ;

contributed to the expansion of the plates. Although the seismic !

capability of cracked cells had been previously addressed and communicated to the inspectors, no review of the effects of expansion of the plates during a discharge had been provided. At the request of the inspectors, the licensee provided documentation j

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supporting operability of the battery which specifically addressed the plate expansion issue The documentation concluded that the batteries should meet all their intended safety functions at least.until the Unit 2 spring 1994 refueling outage. The documentation included the results of i

a detailed examination of several cracked cells conducted by the New Jersey Polymer Extension Center. Additional important

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information which supported operability included:

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Discharge testing (which bounded the accident loading of the batteries) had been performed on the batteries (including the cracked cells) and only slight growth was noted in the crack None of the cracks had penetrated the jar walls and no electrolyte leakage had been observe A recent assessment of seismic implications of cell-corner cracking concluded that a DBE event would not cause a catastrophic failure of the battery jar Appropriate monitoring of the cracking was initiated to eliminate the possibility of cracks growing unacceptably long or flaws expanding into crack No cracks, only flaws, have been observed on the 2A batterie !

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The inspectors were informed that replacement of the 2A and 2B station batteries was being actively pursued for the Unit 2 (spring) refueling outag Because the cracking was, at least partially, attributed to high ambient temperatures in the area of the battery, the inspectors reviewed the vendors specifications in this area. The inspectors noted that the vendor manual for the station service batteries stated that an ambient temperature of 75-77 *F will result in optimum battery life. It also stated that operation of the batteries at higher ambient temperatures will result in reduced !

life. During the warmer seasons, the temperature in the Hatch i battery rooms is often higher than 87 *F. The inspectors concluded that the vendor's temperature. restrictions addressed battery lifetime and were not specific restrictions for battery i operabilit The licensee is considering the temperature effects I in their selection of a replacement batter The inspectors verified that appropriate battery monitoring was being conducted by knowledgeable personnel. The inspectors also ;

discussed this issue with a regional inspector knowledgeable in !

battery requirements. Based on these reviews, it was concluded I that the licensee's actions regarding the degraded condition of l l

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6 L the battery met the expectations of NRC Manual Chapter 990 r Information indicates that the 2A and 2B station service batteries should continue to meet operability requirements until the spring .

1994 refueling outage. The inspector will continue to monitor the !

licensee's activities in this are ,

c. Plant Service Water System Turbine Building High Flow Isolation :

During review of a routine system status report, the inspectors noted that the licensee had identified a condition in which plant

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equipment would not function as described in the FSAR. During '

reviews of the PSW system associated with GL 89-13, the licensee had identified, in August 1993, that the PSW turbine building isolation function would not isolate the nonsafety-related portions of the PSW system for some postulated service water line :

breaks. Although this does not function as presently described in ,

the FSAR, the license had initiated an evaluation and assessment !

to allow a change to the FSAR. This evaluation and assessment was ;

reviewed by the inspectors. The revision to this section is scheduled to be submitted during the next update of the FSA During LOSP, LOCA, high PSW TB flow, or TB flood conditions, a logic system is designed to isolate the nonsafety-related portions of the PSW system. Differential pressure provides the high PSW i flow (line break in the TB) signal. The licensee determined that J some PSW TB line breaks would not produce sufficient differential pressure to initiate the high service water flow isolation. The licensee' had classified the problem as a degraded and i nonconforming condition. With assistance of the architect l engineer group, a review of the issue was conducted. The i inspectors reviewed the summary of the licensee's assessment and I applicable regulatory requirement Because LOCA or LOSP initiates a separate isolation signal to the PSW valves, the assessment focused on the purpose and effects of the high PSW flow isolation function. The assessment stated that l the purposes of the high PSW flow (line break) isolation system

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are to limit the volume of a TB flood and prevent PSW pump cavitation due to inadequate NPSH in the case of a large PSW line break. The summary stated that limiting the size of a TB flood (without a simultaneous LOCA or LOSP) was not a safety-related function. The architech engineer group's review concluded that

! operation for periods as long as 20 minutes with reduced NPSH I l would not result in significant damage to the PSW pumps. Twenty !

l minutes was considered adequate time for CR operators to identify !

and shut the isolation valves following a line break. The 1 assessment also noted that the Hatch IPE stated that the TB flood !

and high flow signals did not provide safety benefit to the plan l The licensee concluded that the safety-related TB isolation l function was operable and that no loss of safety function or ,

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reportable condition existed. The assessment summary recommended :

that the high flow isolation signal be modified to a high flow l

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alarm. Unit 1 TS 4.5.J.1 and Unit 2 TS 4.7.1.2.e.1 both contain ,

requirements for testing and operability of the PSW TB isolation ;

functions / signals. The TS and the TS bases do not specify which isolation signals are required to be tested. However, the surveillance procedures states that the procedures will satisfy i the TS requirements for testing the high flow isolation portion of .

l the isolation logic circuit. The inspectors noted that Procedure 42SV-P41-001-IS: Plant Service Water System LSFT, and procedure ;

42SV-P41-001-2S: PSW Pump and Isolation Valve Auto Function Functional Test, tested the high flow isolation signal '

Additional procedures test the remaining 1:;olation functions of the system. The FSAR description of the isolation system

specifically includes the isolation on a high flow signal. The -

l inspectors did not identify any regulatory requirements (other than the FSAR description) regarding the automatic isolation specifically on a high flow signa '

The inspectors identified that the plant operators were not aware of the issue and that revisions to procedures involving the isolation system had not been initiated. Additionally, the inspectors noted that a formal 10 CFR 50.59 evaluation of the issue had not been completed. Usually, procedural revisions or modifications generated after identification of such an issue would result in a 10 CFR 50.59 evaluation. The inspectors informed plant management of their concerns and also held discussions with corporate personnel involved in the issue. In response, the operators were promptly informed of the issue and procedural revision recommendations, as well as formal 10 CFR 50.59 reviews were initiate The inspectors concluded that although a letter summarizing the issue had been sent to plant management, corporate office communications with site personnel did not adequately address some appropriate actions. The inspectors noted that the licensee had identified the issue and performed an engineering assessment. The inspectors also concluded that although a detailed 10 CFR 50.59 evaluation had not been performed, the resolution of whether an unresolved safety question existed or a TS change was required had most probably been addressed in the assessment. It was noted that the communications aspects of this issue were similar to deficiencies noted involving resolution of a single failure vulnerability in the intake structure ventilation syste Inspection Report 50-321,366/92-15 contained a discussion of that problem. This inadequacy inform plant operators of the issue and initiate procedural revisions to address the problem are considered weaknesse Because the inspectors were not aware of this issue until late in the inspection period, a detailed review of some technical aspects of the issue has not been complete The inspectors will continue to review the issu No violations or deviations were identified.

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3. Surveillance Observations (61726)

Surveillance tests were reviewed by the inspectors to verify '

procedural and performance adequacy. The completed tests reviewed were examined for necessary test prerequisites, instructions, I acceptance criteria, technical content, authorization to begin ,

work, data collection, independent verification where required, handling of deficiencies noted, and review of completed work. The tests witnessed, in whole or in part, were inspected to determine that approved procedures were available, test equipment was calibrated, prerequisites were met, tests were conducted according to procedure, test results were acceptable and systems restoration was complete The following surveillances were reviewed and witnessed in whole or in part: SV-R43-003-IS: Diesel Generator IC Monthly Test i SV-C71-004-IS: Reactor Manual Scram F/T-The inspectors did not identify any problems during the l observation of the surveillance '

No violations or deviations were identifie .

4 Maintenance Activities (62703) Maintenance Observations Maintenance activities were observed and/or reviewed during ;

the reporting period to verify that work was performed by qualified personnel and that approved procedures in use !

adequately described work that was not within the skill of the trade. Activities, procedures, and work requests were examined to verify proper authorization to begin work, provisions for fire hazards, cleanliness, exposure control, proper return of equipment to service, and that limiting conditions for operation were me The following nintenance activities were reviewed and witnessed in whole or in part: MWO 2-93-3121 Increase Actuator Preload 2831-F019 and Perform High Pressure Leakage Test MWO 2-93-4418 Repair HPCI Turbine Steam Stop Valve 2E41-F3053 !

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, MWO 2-93-3122 Increase Actuator Preload 2B31-F020 and Perform High Pressure Leakage Test , MWO 2-93-2051 Complete Installation of DCR 92-121

' MWO 2-93-4516 Repairs to Pressure Sea (2E21-F006B)

Paragraph 4c addresses deficiencies noted during the review of the repairs to pressure seal 2E21-F006B. The inspectors ;

did not identify any significant problems during the observation of other maintenance activitie i b. Unit 2 HPCI Steam Stop Valve Repairs On November 2,1993, during an operational run of the Unit 2 HPCI, the hydraulically operated steam stop valve (2E41-F3053) stuck in the open position. The position indicated in the CR for the valve was dual indication. The valve is hydraulically opened, with pressure being supplied by the i HPCI control oil system. A spring is supposed to close the valve when hydraulic pressure is decreased. Initially, it was not recognized that HPCI had been rendered inoperable by the problem. Several hours later, the HPCI system engineer !

identified that the failure made automatic operation of HPCI ,

uncertain. The licensee then immediately declared HPCI inoperable and reported the event. The inspectors noted i that the conditions of the LC0 had_been met during the time the HPCI stop valve was stuck, even though the system had '

not been declared inoperable. Licensee management discussed this issue with the NSAC personnel who are often contacted i by the onshift operators with operability questions. System engineers can provide valuable assistance in the assessment of the effect of component failures on system operabilit The "on call" NSAC personnel will be furnished with a listing of system engineer The inspectors reviewed and observed the licensee's ;

activities concerning the valve repairs. The specific work t activities observed by the inspectors included:

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Uncoupling of the hydraulic operator from the valv *

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System engineer and maintenance personnel verifying that the valve was stuck approximately 5/16 inch from i full open, and could not be moved by han Disassembly of the valve disc / plug and valve cover guide section/ bushing in the hot machine sho . . .

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Buffing and machining the valve cover guide I section/ bushing and the disc / plug to increase the tolerance and to remove small grooves and scratche Disassembly of the disc flange to remove the pilot valve to inspect the pilot valve and sea The inspectors noted the following:

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The technical manual indicated that the closing ,

mechanism of the valve as having a 1000-pound spring .

force in the closing directio '

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The "as found" clearance tolerance between the disc / plug and the guide section/ bushing of the cover was 0.011 to 0.015 inches, as specified in the

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technical manua Once the coupling between the valve stem and the hydraulic operator was removed, the operator moved to its closed position. This indicated that the valve was stuck and the hydraulic operator was functioning _

normall When the valve disc / plug was removed from inside of the guide section/ bushing of the cover the inspector noted evidence of some type of scratches and small groves on the disc / plug as well as corresponding scratches and small groves in the guide section/ bushing. However, no debris was noted in the guide section/ bushin An inspector was present when micrometer / caliber readings were taken following repairs, to verify that '

the clearance between the disc / plug and guide section/ bushing was 0.014 inche The inspector did not observe any evidence of foreign material affects on the pilot valve disc or sea After repairs and retests, the HPCI system was returned to service on November 5, 199 The inspectors concluded that the licensee's assessment and resolution of the problem were appropriate. Apparently the valve stuck open when small particles of foreign material entered the valve and caused the clearance between the valve cover guide section/ bushing and the valve disc / plug to be reduced. The pilot valve was not affected. The inspectors noted that the valve contained a strainer basket. The strainer basket was reported to be in place and intact. The purpose of the strainer basket is to prevent small particles

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I of greater than 1/16 inch from entering and damaging the :

turbine. The source of the foreign material was not ;

determined because of its small size. It was postulated '

that this material may have been minute pipe flakes, from '

inside the steam piping, that had passed through the strainer basket. The licensee's resolution was to increase ,

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inspectors noted that the maintenance, operations and system engineering personnel worked well together as a team in i solving and ccrrecting the problem. All personnel involved :

used procedures and exercised good engineering and maintenance practices, c. Unit 2 Core Spray Valve Check Valve Pressure Seal Repairs

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The inspectors monitored portions of the maintenance i activities involving valve 2E21-F006B. Valve 2E21-F006B is a testable check valve on loop B of the Unit 2 core spray discharge header. It is a 10 inch Rockwell tilting disc pressure seal type valve. Because the valve's pressure seal is located upstream (toward the reactor vessel) of the disc, i the seal retains RCS pressure. A controlled shutdown was initiated at 3:00 p.m. on November 7, due to an increase in unidentified drywell leakage. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> average leakage rate had increased to approximately 3.20 gpm. A four hour

" estimate" leakage rate was 3.26 gpm. At about 4:30 a.m. on November 8, a leak on the bonnet of valve 2E21-F006B was identified as the cause of the increased leakag l During the initial identification and repair activities, several individuals were contaminated. Contamination levels in the area of the valve were extremely high. One worker received a small internal dose. The inspectors and the licensee discussed some of the radiological aspects of the repairs with Region II health physics inspector Additional review will be conducted during routine ,

inspections by the regional inspectors. The licensee applied glue to some of the internal portions of the valve ;

in order to seal the loose contamination. This reduced the '

probability of additional personnel contaminations. The i inspectors noted that the use of the glue was adequately assessed by the licensee and GE prior to its us Evidence of steam cutting was found on the pressure seal gasket and in the valve body adjacent to the pressure seal gasket and cover interface area. An area of damage *

approximately one inch wide and 0.25 inch deep was found on the gasket. The cutting on the valve body in the same area was about 0.01 inch in depth. Repairs were completed to the valve body and the gasket was replaced. The licensee's review indicated that a " low" spot had been noted on the bonnet (in the location where the steam cutting occurred)

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during the last reassembly of the valve. During that reassembly a judgement had been made that the area was well j clear of the sealing area and was not a proble Additionally, several very small "high" spots were noted on

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the cover in the area where the steam cutting occurred. The licensee postulated that these may have been caused by 3 improper clamping of the component during maintenance p activities. Over a period of time, the combination of the high spots on the cover piece and a low spot in the bonnet '

portion of the valve apparently allowed the high pressure coolant to damage the sea !

The valve is listed in FSAR Table 5.2-3 as a component of the RCS pressure boundary. The : latch IST Program lists the '

function of 2E21-F0068 as core spray injection pressure :

isolation. Section 2.10 of the IST program describes the leakage testing of pressure isolation valves. The inspectors reviewed the work history and testing of 2E21-F006B. Additionally, the inspector reviewed records and procedures which demonstrated that the leakage testing had been completed as described in the IST program. The <

measured leakage rates have been acceptable since 198 In ,

the past, the licensee relied upon disassembly and '

inspection of the valves to meet the valve exercise requirement (valve relief requests RR-V-13 and RR-V-16). ,

I The NRC's SER (December 10,1991) approved the relief requests on an interim basis. The NRC concluded that the !

licensee should be at least manually -(full-stroke)

exercising the valves. In a November 17, 1992 letter to the NRC, the licensee revised the relief requests such that the valves will be exercised manually. NRC review of the

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licensee's most recent submittal is still in progress. The ;

2E21-F006B valve was manually stroked after the maintenance work was completed. The inspector concluded that the licensee performed the required post maintenance testing on 2E21-F006 :

The inspector identified several deficiencies during review !

of the maintenance activities: .

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The cover retainer bolts had been torqued to 180 ft lbs instead of the 150 ft lbs listed in the vendor ,

manual. Work instructions specified the incorrect values. Apparently, the incorrect value had been carried forward from previous work packages. The bolting of the cover retainer to the pressure seal a cover compresses the seal gasket initially. As reactor pressure is increased, the pressure on the l cover further compresses the seal. The bolts are retorqued at 500 psig reactor pressure. The inspector noted that documentation indicated that the bolts on some of the other three core spray check valves were

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also torqued to 180 ft lbs. The licensee provided a letter from the valve vendor which documented that the overtorquing would not result in exceeding allowable stress value The visual examination record sheet, Attachment 1 of procedure 45QC-INS-011-OS: Visual Examination VT-2, had been inadvertently marked as " unsatisfactory" by i the examiner. The administrative error was not '

identified during reviews by other personne ,

Immediately after the NRC inspector identified the :

error, it was verified that the test results had been i satisfactory and the error was correcte The licensee's commitments in the IST program required manually exercising the valve after the maintenanc The engineer involved with the work identified the requirement for the testing. The inspector considered that since the licensee had used dam material to separate the area of maintenance activities from the I hinge / disc section of the valve as well as the core l spray piping, the cycling was primarily for IST l purposes, not just for functional testing after the '

maintenance. " Detailed engineering instructions" provided the directions for the manual stroking of the valve. These instructions consisted of two pages of l step by step guidance which were written by a ;

knowledgeable valve engine. e and reviewed by the I engineer's supervisor. In addition to overall work '

control directions, the instructions contained specific torque limits and acceptance criteria. .The inspecto s noted that the licensee's procedures regarding the development and approval of IST procedures include requirements for reviews including the ANI. The inspectors were informed that a procedure for the IST cycling of the valves was under development, but was not yet approved. The safety i significance of the deficiency is very small because engineers knowledgeable in IST requirements as well as the ANI representative had reviewed the MWO package, l including the testing results.

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identified above, the overall repair and testing activities were conducted satisfactoril Although the individual j deficiencies noted above are not safety significant, they were considered weaknesses in the control of maintenance activitie ,

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14 i t Unit 2 Primary. Containment Isolation Valve Repair l l

The inspectors observed the maintenance activities and reviewed the work packages. associated with the repair of primary containment isolation valves 2B31-F019 and 2B31-F020. These valves are sample line isolation valves from reactor recirculation loop B to a sample station. This issue was reported and discussed-in detail in VIO 50-366/93-13-01 and IR 50-321,366/93-13. In preparation for the review the inspectors reviewed the following documents:

Unit 2 FSAR section 6 TS section 3. ,

l TS tables 3.6.3-1 and 3.3.2-1

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Procedure 52CM-MME-035-05: Fisher Diaphragm Actuator Type 667 Procedure 951T-0TM-001-OS: Maintenance Work Order l Functional Test Guideline

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Procedure 34SV-SUV-008-2S: Primary Containment Isolation Valve Operability

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I Procedure 42SP-081193-0V-1-2S: High Pressure Leakage Test of

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Valves 2B21-F019 and F020 In addition to the document review, one inspector observed >

portions of the post maintenance testing of the valve >

The inspector concluded, from the documentation review and observations, that the maintenance activities were conducted in a controlled manner. Maintenance and testing procedures were used as-required and supervisory oversight was provided.- Additionally, I the post maintenance tests were adequate. The valve stroke times met the TS acceptance criteria and the high pressure test of the valves indicated the leakage rates were within the acceptable value No violations or deviations were identifie i

Unit 2 Installation and Testing of Reactor Water Level KeepFill System i (NRC Bulletin 93-03) (37828, 92701, 62703) l l

Previous reports documented the licensee's activities involving Bulletin '

93-03, Resolutions of Issues Related to Reactor Vessel Level Instrumentation in BWR's. During the repairs to valve 2E21-F006B, Unit 2 was brought to cold shutdown. The licensee completed the !

installation of the keepfill modification (DCR 2-121) in accordance with l

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their commitment in response to the NRC bulletin. The effort largely involved the final connections to the instrumentation racks in the Unit 2 RB and post modification testing. The post modification test procedure, 175P-081693-00-1-2S: Reactor Water Level Cold Reference Leg KeepFill System Function Test, was issued. Two revisions to the procedure were necessary to complete the testin The testing procedure provided detailed instructions including the following activities: filling and venting the two systems, testing during cold shutdown, placing one of the systems in service with the other system secured, and testing during unit startup that included control rod movement and other CRD system manipulation The inspector reviewed and observed portions of the testing activitie Among the activities observed were the functional test of the excess flow check valve, system flow monitoring during control rod movement, placing a system in service at both cold shutdown and normal reactor pressure, and failure of the system pressure regulator. The inspector also observed data gathering during various plant conditions and system lineups. Among the items reviewed were general, abnormal, and system operating procedures. These procedures included 34GO-0PS-001-2S: Plant Startup, 34G0-0PS-004-2S: Nuclear Boiler Lineup and Reference Leg Back Fill, 34AB-B21-002-2S: RPV Water Level Corrections, and 34G0-0PS-030-2S: Daily Inside Rounds. As a result of the reviews and observations, the inspector noted:

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While the system was being placed in service, a brief spike downward of approximately 3 inches in water level was observe Use of the system resulted in an indicated level about 0.5 inches less than the previous indicated level. The licensee is reviewing alternative connection tap locations which may minimize these effect During normal operation, with a loss of a CRD pump or a system pressure regulator, a perturbation in water level of approximatel I to 2 inches occurred. The level returned to within one-half-inch of normal level (approximately).

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Testing which simulated a simultaneous loss of a system pressure regulator, a locked needle flow adjustment valve failing open and the reactor vessel pressure decreasing to atmospheric resulted in a 3 inch decrease in water level. However, the licensee determined that the tested condition was not a credible failur At normal system pressure, a loss of a pressure regulator test was performed. The test indicated that the flow would increase to greater than I gph with approximately one-half inch decrease in normal water leve As a result of the testing, it was concluded that when the unit is in cold shutdown, the system can be lined up with the pressure regulator maintaining one-half gph flow rate until the reactor

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vessel pressure reaches 950 psig. Afterwards, an additional small i adjustment would be necessary to maintain proper flo The inspectors concluded that the modification was installed and tested adequately. Also, plant procedures adequately controlled the keep fill ,

system lineup and placement in service. The inspectors observed the i operation of the keepfill systems during the Unit 2 power ascension and i did not detect any anomalie No violations or deviations were identified.

l Self Assessment (40500) j The inspector continued reviews and observations of self assessment !

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activities as documented in IR 50-321,366/93-20. These reviews and observations included: missed TS surveillances, management quality checks, blockage of RHRSW valve IEll-F068A, and PRB functions. In the l area of missed TS surveillances, management instituted a review group to t make recommendations. The recommendations included stronger oversight of the surveiliance scheduling. The blockage of the RHRSW valve  !

resulted in a r :ommended modification to the valve internals. The ,

management quality checks are being discussed at the morning management ;

meetings. The quality checks reviewed included the following: not performing safety tagging as required by procedure, use of temporary l

jumpers when performing surveillances, contaminated areas step off pad '

l 1 issues, and engineering assessments performed by system engineers. For these quality checks follow-up and corrective actions were performed by the group, workshop or department affected by the quality check The inspector concluded from these reviews and observations that the i quality checks, the daily management meetings, the follow-ups performed by plant personnel and previously documented activities are contributing '

to an effective self-assessment progra Paragraph 2c of this report contains a discussion of inadequate actions regarding a licensee identified nonconforming condition. While the licensee's actions in identification of the issue were good, some appropriate actions were not complete No violations or deviations were identified.

, Warehouse Storage (38702) (71707) (62703)

( The inspectors conducted a review of the licensee's receiving, storage and handling of parts and equipment. In preparation of the inspection the following procedures were reviewed:

ANSI /ASME N45.2.2 - 1978: Packaging, Shipping, Receiving, Storage and Handling of Items for Nuclear Power Plants

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20AC-MTL-004-05: Identification and Control of Material and Equipment 20AC-MTL-006-05: Control of Purchased Material 26MC-MTL-001-0S: Material Receiving 26MC-MTL-002-OS: Preservation, Storage and Handling of Material j'

and Equipment

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40AC-ENG-007-OS: Control of Special Nuclear Material

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50AC-MTL-003-05: Warehouse Preservation, Handling, Shipping &

Storage of Material & Equipment The inspectors also held discussions with warehouse personnel, foreman and supervisors. Additionally, the inspectors conducted a tour and inspection of two warehouse facilities. The areas inspected included level A and B class storage facilities. A review of material receiving, '

inspection and labeling of material was conducted. Also, the storage identification and inventory tracking programs were reviewe There was one minor deficiency identified with the level A storage are The special nuclear materials area was separated and identified with a rope barrier. A sign indicated that material within the areas was ,

radioactive material. However, the inspection of 14 crates containing a '

new type of TIP indicated that the material was not radioactive

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material. The warehouse and HP personnel stated they would arrange to '

have the crates removed from the radioactive material storage area. The inspection of the storage facilities verified the equipment was identified and organized. The areas were clean and well maintained. A review of chart recorders indicated the storage area temperature and humidity had been properly maintained. Administrative controls were in place to receive, identify, inspect, control, and track purchased materials. The inspectors concluded that, in the areas inspected, the warehouse storage facilities program had been well maintained an implemente l l

No violations or deviations were identifie j

' Inspection of Open Items (92700) (92701)

The following items were reviewed using licensee reports, inspections, record reviews, and discussions with licensee personnel, as appropriate: (Closed)_LER 50-366/92-14: Personnel Error Results in l Mispositioned Valve and ESF Actuation. This item was documented and discussed in IR 50-321,366/92-22. NCV 50-366/92-22-03:

Inadvertent ESF Actuation Caused by Mispositioned Valve, was issued. Corrective actions included discussing the event with operations personnel and reviewing procedures 34S0-G31-003-IS/2S:

RWCU System. The inspector reviewed the Unit 2 procedure and

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noted that section 7.4.2, Back Washing the RWCU Filter Demineralizers, step 7.4.2.12.1 stated CLOSED or confirm CLOSED, 2G31-F238 A(B), F/D Inlet Bypass Manual Valve. The Unit 1 procedure was also reviewed and the inspector noted that step 7.3.1.11.1 addressed the Unit I valves. Based on this review of the procedure revisions, this LER is close b. (Closed) LER 50-366/92-18: Blown Fuse Results in Partial Actuation of Group 5 PCIS. This LER addressed an event in which one RWCU system valve (2G31-F004), was affected by a blown fuse and resulted in a trip of the RWCU system pump. The fuse was located in a CR pane Although there were two work activities in progress in the panel when the fuse blew, the cause of the fuse blowing could not be conclusively determined. The fuse was replaced and the RWCU system was returned to norma Based on this review, the LER is closed, c. (Closed) LER 50-366/92-20: Primary Containment Penetrations Found with Non-Code Sealing Devices. IR 50-321,366/92-29 discussed this item in detail. NCV 50-366/92-29-01: Non-Conforming Spare Primary Containment Penetrations was issued as a result of the inspectors review. Based on the NCV and the activities documented ;

IR 50-321,366/92-29, this LER is close d. (Closed) VIO 50-321/92-15-01: Failure to Follow Procedure Resulting in Reactor Runback. This violation addressed an event involving a functional test procedure and was discussed in IR 50- ..'

321,366/92-15. As part of the corrective action, the licensee stated that procedure 42EN-ENG-001-OS: DCR Processing would be l changed to require the use of a special purpose procedure for functional tests having the potential to cause a plant transien '

The inspector reviewed the procedure and noted that section 7.4.1, subsection 4.7, was revised appropriately. Paragraph 6 of this report documents the use of a special purpose procedure to functionally test the reactor vessel level indication reference leg keepfill modification. Based on this revics, ar.d the recent licensee activities, this violation is close e. (Closed) IFI 50-366/92-15-02: Containment Isolation Vahes Not Properly Controlled. The inspectors had identified that procedure 345V-T49-002-2S: Primary Containment Hydrogen Recombiner System Functional Test (Heat up to 600 *F), did not contain directions ,

for controlling several containment isolation valves. This procedure and procedure 34SV-T49-001-2S: Primary Containment .

Hydrogen Recombiner System functional Test (Heat up to 1200 *F), .

were revised to provide instructions to the operators regarding i control of the valves. During observation of recent recombiner ;

testing, the inspector verified that CR operators were aware of the requirement to shut the valves if required. Based on this review, this item is close .

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f. (Closed) IFI 50-321/92-34-03: Resolution of Onsite Radio J Communications Problems. This item was identified during 1 observation of the fire brigade's performance during drills and a small fire in the plant. These observation were discussed in irs 50-321,366/92-15, 92-19 and 92-34. The licensee changed the fire ,

fighting radio communications equipment to include more powerful hand held radios. Additionally, in many safety related areas of :

the plant, specific areas have been designated (marked by paint on the floor) for use of the radios. Several fire drills have been observed since the equipment was changed (See IR 321,366/93-03), ,

including the drill during the most recent EP exercise, and no !

problems were identifie Based on the equipment change, and observations of recent fire brigade performance, this item is ;

close !

g. (Closed) VIO 50-321,366/92-08-01: Inadequate Design Control .

Resulting in Incorrect Documentation and Configuration. This !

violation addressed two examples. The first example involved the ;

installation of bypass jumpers around T0Ls in essential MOV starters. The second example involved incorrect level switch instrument setpoint In IR 50-321,366/92-08, it was noted that the missing Unit 1 TOL i jumpers had been installed. It was also stated that 14 missing jumpers were to be installed in Unit ?. MOVs. The inspector reviewed the licensee's activities which included the installation of TOL bypass jumpers in the affe.:ted Unit 2 MOVs. These ,

activities were accomplished by implementing DCR 92-084: MOV overload Jumpers, and MW0s 2-93-3369 through 3373. A walkdown and i documentation search performed by licensee personnel and reviewed

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by the inspector indicated that a total of 292 essential MOVs (both units) were involved in the TOL jumper issue. Of this ;

amount 196 were documented as having TOL jumpers installed. A walkdown of these 196 MOVs indicated that five valves (three in ,

Unit 1 RHR system, one in Unit 2 RHR system and one in Unit 2 CS -

system), did not have bypass jumpers installed as required by e design documentation. The inspector closely reviewed the !

operability of the five valves and concluded that the lack of TOL bypass jumpers did not make the valves incapable of performing their safety function. Documentation indicated that all essential

, MOVs requiring TOL bypass jumpers have been addressed. A letter from the HNP Engineering Project Manager, dated May 5, 1993, indicated that updated correct documentation involving TOL bypass jumpers was being issue j The second example was originally identified as URI 50-321,366/92- f 05-01 and was later revised as the second example of the ,

violation. As part of the corrective action for the second example, the licensee stated that procedure 57CP-CAL-094-2S:

Robert Shaw Level Switch SL-200, SL-300, SL-400 and SL-700 ,

Calibration, was revised to correct reference setpoints for the l'

FDG day tank level switches. The latest setpoints for switch

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2R43-N005 (Day Tank' Alarm level Switch 2A), were 136 feet, 8.375 inches contact falling ind 137 feet, 5.375 inches contact raisin In IR 50-321,366/92-08 the inspector had stated that the correct setpoints should be listed as above 135 feet instead of the approximate 134 feet listed. The licensee performed a complete review of all elevation setpoint values listed in the Setpoint Index and the Level Setting Diagrams for both unit Discrepancies on several safety-related instruments were identifie Included among the discrepancies were: instruments IE41-N002 and 003 (CST Level Switches-HPCI), IE41-N662B and D (Torus Water Level Indicating Switches-HPCI), 2E41-N002 and 003 (CST Level Switches-HPCI), 2E51-N061 (CST Low Level-RCIC), 2E51-N062A and B (Torus High Level Switch-RCIC), and 2P70-N012 (Drywell Pneumatic Air Receiver Drain Line Level switch). The survey :

indicated that these instruments setpoints were all addressed by specific calculations. The errors involving safety related level i switch setpoints were in the conservative direction. Based on !

this review of the licensee's activities, Violation 50-321,366/92- '

08-01 is close !

! (Closed) VIO 50-321/92-21-01: Two Examples of Failure to follow i Operating Procedures. This violation addresses an event during ,

which operators, on two occasions, failed to follow procedure As part of the corrective actions, the procedures were reviewed ,

and changes were determined as not being necessary. .The involved *

personnel and their supervisors were counseled concerning the need f for procedure compliance and attention to detail. The licensee !

management has initiated concerted efforts to address the overall ;

personnel error issues. This included meetings a the resident inspector staff and Region II management. The w ,,ectors reviews of the licensee's actions in this area have been 61scussed in several recent inspection reports. Based on this review and the .

licensee's overall efforts in this area, this violation is close l Exit Interview The inspection scope and findings were summarized on December 2, 1993 with those persons indicated in paragraph I above. The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspectio i

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10. Acronyms and Abbreviations  !

ANI - Authorized Nuclear Inspector i BWR - Boiling Water Reactor l CFR - Code of Federal Regulations i CR - Control Room +

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CRD - Control Rod Drive '

CS - Core Spray CST - Condensate Storage Tank DBE - Design Basis Event DC - Deficiency Card i

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DCR. - Design Change Request i DW - Drywell i ECCS - Emergency Core Cooling System  ;

EDG - Emergency Diesel Generator i EHC - Electro Hydraulic Control System .

ESF - ' Engineered Safety Feature -

EST - Eastern Standard Time

'F - Degrees Fahrenheit F/D - Filter /Demineralizers  :

FSAR - Final Safety Analysis Report F/T - Functional Test i '

GE - General Electric Company gpm - Gallons per minute GL - Generic Letter J gph - Gallons Per Hour HNP - Hatch Nuclear Plant HP - Health Physics .

HPCI - High Pressure Coolant Injection System r IFI - Inspector Followup Item IPE - Individual Plant Examination IR - Inspection Report IST - Inservice Test LC0 - Limiting Condition for Operation LER - Licensee Event Report LOCA - Loss of Coolant Accident F LOSP - Loss of Offsite Power _

LSFT - Logic System Functional Test  !

MOV - Motor Operated Valve ,

MWO - Maintenance Work Order NCV - Non-cited Violation NPSH - Net Positive Suction Head i NRC - Nuclear Regulatory Commission

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NSAC - Nuclear Safety and Compliance .i PCIS - Primary Containment Isolation System a

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PE0 - Plant Equipment Operator PRB - Plant Review Board psig - Pounds Per Square Inch Gauge ,

PSW - Plant Service Water System  !

RB - Reactor Building RCIC - Reactor Core Isolation Cooling System .

RCS - Reactor Coolant System RHR - Residual Heat Removal  ;

RHRSW- Residual Heat Removal Service Water System  :

RPV - Reactor Pressure Vessel RTP - Rated Thermal Power  :

RWCU - Reactor Water Cleanup l SDC - Shutdown Cooling SER - Safety Evaluation Report  !

SPDS - Safety Parameter Display System i TB - Turbine Building  ;

TOL - Thermal Overload  :

TS - Technical Specifications URI - Unresolved Item

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