IR 05000155/1987011

Insp Rept 50-155/87-11 on 870424-0616.No Violations or Deviations Noted.Major Areas Inspected:Previous Insp Findings,Operational Safety,Maint,Reactor Trips & LER Followup.Item Re Emergency Condenser Leakage Resolved

ML20235J564
Person / Time
Site:	Big Rock Point File:Consumers Energy icon.png
Issue date:	06/30/1987
From:	Jackiw I NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20235J514	List: IR 05000155/1987011 ML20235J510
References
50-155-87-11, NUDOCS 8707150640
Download: ML20235J564 (10)

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U.S. NUCLEAR REGULATORY COMMISSION l

REGION III l Report No. 50-155/87011(DRP)

Docket No. 50-155 License No. DPR-6 l Licensee: Consumers Power Company 212 West Michigan Avenue Jackson, MI 49201 Facility Name: Big Rock Point Nuclear Plant Inspection At: Charlevoix, MI 49720 I Inspection Conducted: April 24 through June 16, 1987 Inspector: Stephen Guthrie

[e, Approved By: //fffk[/ W) Chief I. N. J ki r', 6/30/57 Projects Section 2C Date Inspection Summary Inspection on April 24 through June 16, 1987 (Report No. 50-155/8"011(ORP))

Areas Inspected: Routine, unannounced inspection conducted by the Senior Resident Inspector of Licensee Actions on Previous Inspection Findings, Operational Safety, Maintenance, Reactor Trips, and Licensee Event Report i Followu Results: Of the five areas inspected, no violations or deviations were identified. One significant safety item dealing with E;nergency Condenser leakage was resolve %$ .

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DETAILS l

l'. Persons Contacted

• • T. Elward, Plant Superintendent  ;

.G. Petitjean, Planning and Administrative Services Superintendent

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• G. Withrow, Engineering Maintenance Superintendent

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• • R. Alexander,-Technical Engineer .

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• • R. Abel, Production and Plant Performance Superintendent i

• L. Monshor, Quality Assurance Superintendent

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R. Barnhart, Senior Quality Assurance Administrator '

P. Donnelly,. Senior Review Supervisor, Nuclear Activities Department D. Staton', Shift Supervisor

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• • W..Trubilowicz, Operations Supervisor

• J. Beer, Chemistry / Health Physics Superintendent E.. Evans, Senior Engineer D. Kelly, Maintenance Supervisor D. Ball, Maintenance Supervisor W. Blosh, Maintenance Engineer J. Toskey, General Engineer ,

G. Boss, Reactor Engineer '

L. Darrah, Shift Supervisor J. Horan, Shift Supervisor R. May, Shift Supervisor R. Scheels, Shift Supervisor J. Bradshaw, Property Protection Supervisor-E. Raciborski, Planning and Scheduling Administrator J. Werner, Chem / Rad Supervisor y

• Bielinski, Senior Engineer .

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R. Bucker, Nuclear Plant Training Administrator

The inspector also contacted other licensee personnel in the Operations, {

Maintenance, Radiation Protection, and Tecnnical Department i

• Denotes those present at exit intervie ** Denotes those present at the Management Meeting of May 26, 198 < Licensee Action on Previous Inspection Findings (Closed) Open Item (50-155/86006-01), related to minor emergency condenser primary to secondary leakage. Resolution,of the concern is. discussed in Section 4.c. of!this repor . Operational Safety Verification

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The inspector observed control room operations, reviewed appiicable logs, 4 and conducted discussions with control' room operators during the inspection period. The inspector verified the operability of selected emergency systems, reviewed tagout records, and verified proper return to service of affected components. Tours of the containment sphere and turbine building i

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were conducted to observe plant equipment conditions, including potential fire hazards, fluid leaks, and excessive vibrations and to verify that maintenance requests had been initiated for equipment in need of maintenance. The inspector, by observation and direct interview, verified that the physical security plan was being implemented in accordance with the station security pla ,

The inspector observed plant housekeeping / cleanliness conditions and

) verified implementation of radiation protection controls. During the inspection period, the inspector walked down the accessible portions of the Liquid Poison, Emergency Condenser, Reactor Depressurization, Post Incident, Core Spray, and Containment Spray systems to verify operabilit The inspector also witnessed portions of the radioactive waste system controls associated with radwaste shipments and barrelin During the annual emergency exercise on April 7, the inspector noted that although the stockroom had segregated area for Quality listed stock items that included a locked door, access to the area and components stored within the area was available from the uncontrolled portion of the room. Access was available through the stack of open shelves forming one wall, creating the possibility'of mingiing quality and non quality items and loss of inventory control over Q-listed items stored in the segregated area. At the time of the observation, 5 the licensee was involved in refurbishment of other warehouse space and movement of inventory to the new facility. Delays in that project resulted in increased potential for mixing quality listed components with commercial grade items, and on May 15, the licensee, at the inspector's request, erected a temporary, but substantial barrier to segregate Q-listed components in the stockroom. The temporary walls are expected to be replaceo upon completici of warehause refurbishmen b; On May 5, the inspector observed loading of barrels and boxes of radioactive waste being shipped for burial. Appropriate methods for thipment contents accountability and monitoring of contamination on containers was evident. Barrels were security closed and no leakage was evident. Barrels were conspicuously marked with radiation exposure informatio . During a plant tour on May 12, the inspector noted the removal of several personnel contamination detectors (friskers) from locations throughout the plant. The licensee informed the inspector that, in conjunction with recently implemented contamination control measures that limit egress from the radiologically controlled areas to the access control point on the second floor of the administration

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building, friskers outside the sphere were removed. Friskers previously located within containment were removed because high background radioactivity made accurate indication of personnel contamination difficult. The inspector expressed a concern that removal of the friskers from the lower control rod drive / recirculation ;

pump room area increased the likelihood that a contaminated individual would travel from the point in the sphere farthest removed from the

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closed frisking station to the personnel air lock where, after-exiting the sphere, a frisker would be available.- The-license responded with the decision that should the need arise, they would prefer to decontaminate the route traveled by a contaminated individual than maintain the frisker statio The inspector expressed a concern that this approach was not in keeping with the licensee's initiative to reduce contamination incidents and referred the matter to a. regional specialis Later in the inspection period, the licensee replaced the frisker at the lower control rod drive area for use as a gross check on contaminatio d. On May 13, during normal plant operation, operators received the Instrument Air low pressure alarm at 84 psig. Normal air pressure is approximately 100 psig. Loss of instrument air pressure eventually results in opening of the scram valves and subsequent plant scram, failure in the as-is position of the feedwater regulating valve, closure of the scram dump tank vent and drain valves, and closure of the feedwater bypass valv Prompt operator response to the alarm and diagnosis of the air failure prevented a plant scram as pressure fell to~a low point of 52 psig. Actuation of'the standby compressor and bypassing of prefilters had no effect, but bypassing the instrument air dryer corrected the proble The operators diagnosed the cause to be malfunction of the four-way valve which automatically directs air flow through either the north or south tower of the instrument air ,

drye Failure of pins which couple the valve to the operating '

mechanism resulted in the air dryer failure in the mid position between the two tower Repairs were completed and the dryer returned to servic '

e. On May 18, the reactor was shutdown to permit repair of Reactor Depressurization Valves SV-4984 and SV-4985, pilot actuated depressurization valves in the A and B trains.of the Reactor Depressurization Syste Depressurization valves have exhibited leakage due to erosion of the pilot valve for many years and installation of newly designed pilot valve top assemblies during the 1987 outage was expected to remedy the proble However, beginning in early March, the plant's unidentified leak rate steadily increased from its normal value of approximately 0.3 gpm to approximately 0.76 gpm. Big Rock Technical Specifications prevent operation above gpm of unidentified leakage and Big. Rock Administrative Procedures require power reduction and investigation at 0.8 gp During the three day outage the licensee replaced the A and B valve top assemblies with rebuilt assemblies of'the old design. No spare assemblies of the new design were available. The reactor'was returned  ;

to service at 10:58 a.m., May 21. Leak rate calculations after i startup and for the period leading up to the next shutdown May 29, were approximately 0.20 gp During the shutdown a reactor trip occurred. The trip is discussed in j Section 5 of this repor ]

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_ On May 26, representatives of licensee management participated in a !

Management Meeting with Regional Management in Glen Ellyn, Illinois to review concerns related to personnel error and operator 4 inattentiveness presented in Report No. 155/87005(DRP). The licensee indicated they shared the staff's concern over what appears to be an emerging trend of operating events caused by personnel erro Specific licensee actions to address the issue will be included in I

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the written response to violation (155/87001-01(DRP)). At 11:46 P.M. on May 29, the reactor was shutdown to enter an I estimated 10-14 day outage for replacement of an estimated 3300 ft j of electrical cable for equipment qualification requirement No j spurious electrical noise trips occurred during the shutdow ]

I During the turbine shutdown, a small oil fire was discovered under the turbine near the No. 1 main shaft bearing. The fire was f'

discovered by an alert operator who noticed an unusual glowing reflection from the fire. The fire was quickly extinguished inside j the pipe tunnel beneath the turbine. Because the fire lasted much 1 less than ten minutes, the event was not reportable. Operators I promptly inserted control rods, notch by notch, in the prescribed sequence to reduce power in a successful attempt to avoid a plant j scram when the turbine was tripped. Investigation by turbine experts j on June 3, concluded that minor disruptions in the turbine shaft oil I seals, which resulted from incorrect turbine casing adjustments in 1985, had caused oil to leak along the shaft and accumulate in laggin The source of ignition was determined to be hot piping associated !

with the turbine. Oil soaked lagging was replaced. The seal l replacement and internal adjustment completed during the EEQ outage i is expected to remedy the proble ! On June 9, the inspector reviewed security measures taken in anticipation of a scheduled demonstration by a group of peace advocates on a statewide march. Additional personnel were posted at the plant's access road entrance and at other locations around the plant's perimeter. The security force was well versed on the requirements of the Security Plan pertaining to civil disturbance The insoector observeu the demonstration conducted by approximately 18 persons at the site access road entrance, which occurred without inciden No violations or deviations were identified in this are . Monthly Maintenance Observation

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Station maintenance activities of safety related systems and components listed below were observed / reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides, and industry codes or standards, and in conformance with technical specification _ _____

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The following items were considered during this review: the limiting conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and fire prevention controls were implemente Work requests were reviewed to determine the status of outstanding jobs and to assure that priority is assigned to safety related equipment maintenance which may affect system performance, On June 1, the licensee conducted tests of Steam Drum Relief Valve Serial No. A-4 to determine the as-found lift point. The test was conducted voluntarily as a conservative measure by the licensee to test the effectiveness of corrective measures taken during the 1987 outage. Routine testing during that outage had identified a problem with adhesion of seat to disc that caused reliefs to lift approximately 150 psig above set points. (Reference Reports No. 155/87002(DRP),

Section 4.s and 155/87005(DRP), Sections 4.d and 4.k.) The licensee ,

at that time considered the cause of the adhesion to be chemical bonding between seat and disc caused by residual lapping compounds not effectively cleaned during rebuil The results of the A-4 testing indicated the sticking problem continued to exist. Reliefs A-4, A-2, and A-0 tested cold on a test stand, lifted 173 psig, 23 psig, and 88 psig respectively, above set poin Valves A-1, A-3, and A-c were tes.ed on the test stand with the body temperature of the valve body raised by a warming device, resulting in lift pressures ranging from 116 psig below setpoint to 110 psig above setpoint. Relief valve A-2, which was tested cold initially and lifted 23 psig high, retested at 76 psig below setpoint when body temperature was raised. The licensee did not test any reliefs using live steam or with temperature / pressure conditions for seat and disc duplicating the installed condition The licensee revised their cleaning procedure to include use of acetone and changed the discs in all six valves from stainless steel 1 alloy to stainless steel 17.4 alloy. An identical change at the La Crosse Facility in 1976, resolved a similar issue. The valve vendor concurred in the approach. In addition, the licensee reviewed the performance of their test stand to evaluate the effects of hydraulic oil used in the test stand entering the valve body. Certain hydraulic oils, when subjected to elevated temperatures, leave a black residue suspected of causing a chemical bonding. Samples of the hydraulic fluid and affected discs were sent for laboratory analysis. The licensee conducted all additional testing using nitrogen only. At the close of the inspection period all relief valves were cleaned, rebuilt, and reinstalle ____- _ - _ _ _ _ _ _ _ _ _ _ - - _ _ __

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On June 12, the relief valve issue was discussed in a conference call between the licensee, Region III, NRR, and the inspector. The licensee summarized their efforts to diagnose and correct the problem l with relief valve sticking. The staff was in general agreement with the corrective measures taken by the licensee. All parties agreed that the relief valves should be subjected to at least 90 days of  !

installed operation to adequately address the unknown factor of time to which the valves are subjected to elevated temperatures in a steam environment. The licensee committed to test one relief valve the first time that plant is taken to cold shutdown condition for any 4 other reason after the 90 day period of installed operation has passe Any testing would be performed during the period of cold ~ shutdown regardless of the duration of the shutdown. Testing of the first 4 valve, and any subsequent tests of additional valves based on failure of the first valve, would continue to be governed by applicable ASME code requirement b. On June 3, the inspector observed preparation of a shipping cask on the reactor deck. The shipment was one in a series that commenced during the January 1987 outage in which old vessel internal components long stored in the spent fuel pool were shipped to a burial sit Operators used procedure MRVI-11, handling Procedure for CNSI Transport Cask No. 1-13C. The inspector noted the closure of the cask and installation of the drain plug. An air test indicated the integrity of the inner vessel was intact. Decontamination of the shipping cask proved time consuming for technicians. The cask departed i the site late June 3, in a clean conditio On June 10, the licensee was notified by the State of South Carolina  ;

that a routine inspection of the cask at the entrance to the Barnwell site revealed contamination levels up to 90,000 DPM/100cm2 covering a two square foot area on the side of the cask below the lifting ear -

bolt holes, and in puddles on the truck bed. The licensee dispatched two individuals to the South Carolina facility to inspect the cas Inspection and photographs identified the contaminated area as being coated with a dried residue of liquid described as " green and slimy,"

and that some of the green water was observed in the bolt holes for the lifting ears and on the truck bed. That fluid appearea in the bolt hole of a separate cask in February, 1987, and was identified by a representative of the owner / operator of the cask as fluid used at the Barnwell facility to decontaminate shipping containers. The licensee inspection concluded that the quantity of green water on the truck and cask exceeded the volume of the bolt hole, thus raising questions about the integrity of the cask's outer can. The cask's inner can is not in question because of the successful air test conducted June ]

q Based on discussions with Barnwell site personnel and the cask owners, '

the licensee speculates that the bolt holes for attaching the lifting ears do not correspond with the blue prints, but instead penetrate into the lead between the two cans. If water from the utility's spent fuel pool was able to enter the leaded area between the cans, it could j result in contaminated fluid being trapped. The fluid would then be l subject to high and low temperature extremes which could cause internal

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stresses in freezing weather or expansion of the fluid in the bolt holes in hot weather. An isotopic analysis of -the water discovered on the truck indicates primarily Cesium 137 and closely matches the results of the licensee's analysis of water from the spent fuel poo The licensee kept the inspector informed. The inspector passed the licensee's findings on to NMSS, Transportation Branch,.for evaluatio On June 5, the inspector observed helium testing of the emergency condenser's south tube bundle. Testing satisfied a commitment made to Region III to resolve concerns over an apparent small primary to .

secondary leak into the emergency condenser. (Reference Report-No !

155/86006(DRP),and 155/87009(DRSS)). To perform the test,-water level was lowered in the condenser's secondary side until approximately .

1000 psig bubbles were observed at.the internal tube sheet header gasketed joint. . Tightening of the studs reduced leakage to an estimated eighty percent of origina In an attempt to obtain zero leakage during Helium testing, the licensee elected.to disassemble the gasketed joint and replace the flexible metal' wound gasket. 'After disassembly it was discovered that the new gasket would not fit throug the manway, leaving the licensee, using vendor guidance, to make two-attempts to disassemble the new gasket, pass the pieces through the manway, and reassemble the gasket inside the condenser using the old outer retaining ring. Both attempts were unsuccessful. After the second attempt on June 10, nondestructive testing performed on the flange faces in the gasket seating area revealed defects. Weld repairs were made on defects up to one half inch deep and extending through the stainless steel cladding and into the carbon steel flange body. On June 14, the licensee completed replacement of the flexible gasket with a graphical spiral round gasket. Testing with air'at-1350 psig revealed no leakage at the gasketed joint. Subsequent testing at 1350 psig using Helium showed minute leakage. Helium is of a small molecular structure, allowing it to pass through leak paths too small to pass water or air molecules. The air used in the first test is likely to more closely resemble the operating environment of the component during reactor operatio On June 16, the licensee conducted a' leakage test in accordance with the requirements of the ASME Boiler and Pressure Vessel Code,Section XI, 1980. The repaired joint showed zero. leakage at 1370 psig test H pressure. The licensee's corrective measures and verification of emergency condenser tube bundle integrity satisfies the staff's .

concerns over the reliability of the emergency-condenser at this tim l The inspector encouraged the licensee to review the engineering l information gained from problems with the south tube bundle and

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evaluate the need for inspection and/or repair of the north tube '

bundl No violations or deviations were identified in this are l Reactor Trips

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i During the normal reactor shutdown on May 18, with reactor power at ,

40 x 10-5Ti and some rods remaining to be fully inserted,-the reactor 1 l

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tripped on a spurious signal from the three power range picoameter. channel Spurious actuation of the trip due to electrical noise in the picoameter circuitry 'at very low power is a known operating characteristic of the facilit The appropriate notifications to NRC headquarters were complete All systems functioned normally on the scra While there was no appropriate short term corrective action beyond normal scram response, .long term corrective action to address the electrical noise is underway with the second portion of a facility change scheduled ,

to replace intermediate and power range nuclear instrumentation circuitry !

with modern equipment during the 1988 outage. The electrical nois reduction is a secondary benefit of the equipment change. Source range instrumentation was changed during the 1987 outage and significantly reduced electrical noise on those channel No violations of deviations were identified in this are . Licensee Event Reports Followup Through direct observations, discussions with-licensee personnel, and review of records, the following event reports were reviewed to determine that. deportability requirements were fulfilled, immediate corrective action was accomplished, and corrective action to prevent recurrence had been accomplished in accordance with technical specification By letter dated April 28, the licensee submitted LER 87-04, Revision 1,

" Inoperable Reactor Depressurization Snubbers" per Technical Specifications 3.1.5. The revision submits the results of further snubber testing. The testing of snubbers during the 1987 outage was the subject of Inspection Report No. 155/87007(DRS). The new failure data was reviewev by a Regional snubber specialist. The LER revision is considered close By letter dated April 29, the licensee submitted LER 87-03,. Revision 1,

" Inoperable Primary System Safety Valves." The Revision corrects a misinterpretation concerning multiple testing of safety valves identified by the inspector and discussed in Section 7 of Report No. 155/87005(DRP).

The LER revision is considered close By letter dated May 8, the licensee submitted informational LER 87-06 following discussion with Regional specialist. The LER discusses the staff's position that cable similarity arguments used by the licensee were-inadecuate and the licensee's contention that their analysis demonstrates the cables are expected to perform their intended safety function'. The LER details the licensee's commitment to resolve the differences by:

1) replacing certain cables inside containment, and 2) providing.an acceptable written justification to qualify certain cables located outside 1 containment. Details of the inspection findings are contained in Inspection Report No. 155/86013(DRS). This LER is considered close j l

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( 7. Open Items Open items are matters which have been discussed with the licensee, which will be reviewed further by the inspector, and which involve some action on the part of the NRC or Licensee, or both. Open items closed during the inspection are discussed in Paragraph . Exit Interview The inspector met with licensee representatives (denoted in Paragraph 1)

throughout the month and at the conclusion of the inspection period, and summarized the scope and findings of the inspection activities. The licensee acknowledged these findings. The inspector also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspector during the inspectio The licensee did not identify any such documents or processes as i proprietary, l

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