IR 05000219/1987004

Insp Rept 50-219/87-04 on 870116-0308.No Violations Noted. Major Areas Inspected:Physical Security,Technical Support & Outage Repairs.Open Items Re Upgrading of Cold Weather Plans & Technical Support Identified

ML20206F703
Person / Time
Site:	Oyster Creek
Issue date:	04/08/1987
From:	Blough A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20206F681	List: IR 05000219/1987004 ML20206F677
References
50-219-87-04, 50-219-87-4, NUDOCS 8704140340
Download: ML20206F703 (20)

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U.S. NUCLEAR REGULATORY COMMISS10N

, 2 , REGION I Report N /87-04 Docket N License N DPR-16 Priority -- Category C Licensee: GPU Nuclear Corporation 1 Upper Pond Road Parsippany, New Jersey 07054 Facility Name: Oyster Creek Nuclear Generating Station Inspection Conducted: January 16 - March 8,1987 Participating Inspectors: W. H. Bateman W. H. Baunack J. F. Wechselberger Approved By: 7+ F2 A. R. BloDgh, Chief Date Reactor Projects Section 1A Inspection Summary:

Routine inspections were conducted by the resident inspectors and one Region based inspector (319 hours0.00369 days <br />0.0886 hours <br />5.274471e-4 weeks <br />1.213795e-4 months <br />) of activities in progress including plant opera-tions, radiation control, physical security, technical support and outage re-pair Particular attention was paid to licensee performance during two de-clared Unusual Events and corrective actions initiated in response to continu-ing intermediate range nuclear instrumentation performance problems. The inspectors also followed up licensee actions to close NRC related issues, made routine tours of the plant, verified implementation of several licensee commit-ments made to NRC licensing, and reviewed pipe wall thinning inspection activitie Results:

No violations were identified. Four unresolved items were opened. Licensee activities during this report period to address the various problems that pre-vented smooth plant operation subsequent to completion of the 11R outage appeared effective. A concern was raised by the inspectors about the need to improve technical support when difficult problems are encountered. Licensee performance during the Unusual Event involving the broken drain valve on the condensate storage tank was good. Performance of at least one key member of the emergency response team during the offgas sample gas leak Unusual Event was wea Based on the significant problems caused by inadequate freeze protec-tion, the inspectors emphasized the need for the licensee to upgrade their cold weather plan s PDR G ADOCK 05000219 PDR

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DETAILS 1. Verification of Systematic Evaluation Program (SEP) Action Items NRC Region I has been tasked with confirming licensee implementation of certain actions specified in NUREG-0822, Integrated Plant Safety Assess-ment Report (IPSAR). During this inspection several of these items were verified as follows:

. The item number is that assigned in the IPSAR.

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Item 4.1(6) - Licensee proposed to update Emergency Procedures and to identify the alternate water sources and flow paths if the intake struc-

ture becomes flooded, and to identify the priority of water sources and flow paths to be used to ensure a safe shutdow The licensee has provided procedural instructions in Station Procedure

2000-ABN-3200.31, High Winds, for the actions to be taken in the event of high water level in the intake structur The instructions include actions to be taken in shutting down the circulating water pumps and the service water pumps. In addition, Station Procedure 307, Isolation Con-

. denser System, provides instructions for providing makeup to the isolation condenser using the fire protection system should the preferred condensate transfer system not be availabl Item 4.5.2 - The licensee agreed to formalize as part of shift turnover procedures the shift inspection of the intake structure, and to modify the screen wash system to prevent buildup of sea lettuc The licensee has in place an intake area tour sheet which is required to be completed each shif Also, SDD-0C-533 Div II (Budget Activity i

1. 402188) describes the modifications performed on the screen wash system during the Cycle 10 refueling outage to prevent buildup of sea lettuc Item 4.18 - Licensee agreed to implement generic guidelines for emergency procedure The licensee has replaced the previously existing emergency procedures with General Emergency Operating Procedures developed in conjunction with the BWR Owners Group and the TMI Action Plan requirement These items are considered close . Plant Operation Review I

2.1 Routine tours of the control room were conducted by the inspectors during which time the following documents were reviewed:

Control Room and Group Shift Supervisor's Logs;

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Technical Specification Log;

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Control Room and Shift Supervisor's Turnover Check Lists;

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Reactor Building and Turbine Building Tour Sheets;

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Equipment Control Logs;

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Standing Orders; and,

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Operational Memos and Directives.

. Operations management initiated a new dress code for licensed control room operators which has resulted in a more professional appearing environment. This action is part of an overall effort to improve the professional atmosphere in the control room. Additional steps taken include additional restrictions on access to control room panels and the area directly in front of the major panel The large discrepancy in the reading indicated by the GEMAC reactor water level indicators discussed in Inspection Report - 50-219/86-38

were corrected during this report period. A 3-5" level discrepancy still exist .2 Routine tours of the facility were conducted by the inspectors to make an assessment of the equipment conditions, safety, and adherence to operating procedures and regulatory requirement The following areas are among those inspected:

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Turbine Building;

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Vital Switchgear Rooms;

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Cable Spreading Room;

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Diesel Generator Building; and

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Reactor Buildin The following items were observed or verified: Fire Protection:

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Randomly selected fire extinguishers were accessible and inspected on schedul Fire doors were unobstructed and in their proper position.

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Ignition sources and combustible materials were controlled in accordance with the licensee's approved procedure . .

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Appropriate fire watches or fire patrols were stationed when equipment was out of service and proper compensatory measures were implemente During this report period, several water-supplied fire protection systems were found to be out of service because of frozen line Additionally, temperatures were observed on the turbine floor to be at the freezing point, although there was no evidence of frozen line The inspectors expressed a concern to the licensee regarding apparent inadequacies in the cold weather protection pla The licensee intends to upgrade their cold weather protection plan to preclude similar events in the futur Equipment Control:

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Jumper and equipment mark-ups did not conflict with Tech-nical Specification requirement Conditions requiring the ~ use of jumpers received prompt licensee attentio Administrative controls for the use of jumpers and equip-ment mark-ups were properly implemente Vital Instrumentation:

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Selected instruments appeared functional and demonstrated parameters within Technical Specification Limiting Condi-tions for Operatio Housekeeping:

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Plant housekeeping and cleanliness were in accordance with approved licensee program No violations were identifie . Observation of Physical Security During daily entry and egress from the protected area, the inspectors verified that access controls were in accordance with the security plan and that security posts were properly manned. During facility tours, the inspectors verified that protected area gates were locked or guarded and that isolation zones were free of obstructions. The inspectors examined vital area access points to verify that they were properly locked or guarded and that access control was in accordance with the security pla No concerns were identified.

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5 Review of Operational Events The following operations related events, concerns, and questions were pursued by the inspectors:

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During this report period, the offgas sample pump stopped working due to equipment failure. A question arose at this time as to the impli-cation of Tech Spec requirements in paragraph I. of Table 3.1.1 that states the offgas system isolation function must be operable in the shutdown mode unless the reactor temperature is less than 212 F and the vessel head is removed or vented. In this particular case the vessel temperature was greater than 212 F and the head was in place and not vented. Because there is no redundant offgas sample pump, failure of the single pump when in shutdown results in inability to comply with Tech Spec requirements. A review of the purpose and design of the offgas sample system, however, leads one to conclude it is only needed to be operable when the steam jet air ejectors (SJAEs)

are in service. When the SJAEs are in service there is sufficient motive force created by the condenser vacuum to move a sufficient amount of offgas through the detectors without a need for the sample pump and, in fact, when the plant is running the pump is of The SJAEs are in service in the startup and run modes, not in shutdown or refuel. An examination of these facts led the licensee to ccnclude the Tech Specs were overly conservativ The resident inspectors agreed with this conclusion after determining the apparent need for the sample pump. (It appears the offgas sample pump would be used if the single source of vacuum from the 'B' condenser to drive the off-gas sample flow was lost.) Additionally, BWR Standard Technical Specifications (NUREG-0123), in Table 3.3.7.1-1, Item 7, require the function to be operable in only the startup and run modes. Prelimi-nary discussions between GPUN and NRC Licensing indicated agreement that the offgas system isolation function was not required in shut-down and the licensee intends to submit a Tech Spec Change Request to correct the apparent discrepancy. The need for the offgas sample pump when not in startup or run is an unresolved item pending revis-ions to paragraph I of Table 3.1.1 of the Oyster Creek Tech Spec (50-219/87-04-01)

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On January 19, 1987 a plant startup was stopped and rods reinserte The shutdown resulted because of problems with intermediate range monitor (IRM) #17. The instrument problems were investigated and the plant restarted again on January 20. The plant operated at near full power until an unplanned trip on February 1 This trip resulted when a loose lead was inadvertently moved and became detached while verifying a temporary variation / lifted lea The electrical open circuit that resulted caused an erroneous feed flow signal that resulted in a turbine trip and anticipatory reactor scram. The NRC inspectors reviewed the licensee's post trip review, interviewed con-trol room operators, and followed up other issues relating to this

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l tri In general, operator response to the challenges presented by this trip were good. There were several factors that complicated the trip and the subsequent plant respons These included a 13" GEMAC level discrepancy, excessive feed regulating valve closure time, incorrect setting of the feed pump run out trip automatic reset, failure of the wide range pressure recorder to respond, and sequence of event recorder problem The most significant result of these problems was the inability of the operator to control water level properly. Had the equipment functioned properly there would not, in all li kelihood, have been a tri The NRC inspectors expressed a concern about the number of discrepancies that were revealed upon review of this event and were assured by the licensee that the problems have been correcte Following the trip on 2/14/87 and subsequent repairs, a plant restar commenced on 2/18/87. This restart was unsuccessful due to problems with IRMs 12, 13, and 17 and the plant was shutdown. Due to the significant number of problems experienced with IRMs, a licensee decision was made to bring in technical expertise from the IRM instrument manufacturer, Reuter-Stokes. These technical representa-tives determined the cause of the IRM problems to be damage to the detector caused by vibration induced by the drive mechanism that moves the detector in and out of the reactor vessel. Subsequent to this determination, the licensee replaced / rebuilt the drive mechan-isms for SRMs 21, 22, and 23 and all IRMs except 14. Additionally, all SRM and IRM detectors except SRM 24 and IRM 14 were replace Upon completion of these activities, vibration measurements of the drive mechanism were taken and adjustments made to reduce vibration to a minimum. A special committee was formed by GPUN to fully research and correct the long-standing IRM problems. This committee determined a 1979 General Electric Service Information Letter (SIL)

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addressed the particular problem of vibration induced damage to de-tectors but that the SIL was not specifically quantitative in terms of vibration limit The NRC inspectors followed licensee actions throughout the IRM work activities and concluded efforts were effec-tive in identifying and correcting the problems. To ensure detector operability in the future, plant procedures were upgraded to require a current / voltage check on all intermediate range detectors prior to startu Inadequate cold weather preparations resulted in frozen fire water I lines, a broken drain valve on the condensate storage tank, and I inoperable level instrumentation on the condensate storage tan I Additionally, inspection of the heat tracing on the emergency service water piping at the intake structure disclosed several deficiencie These problems resulted because of inadequate or non-existent heat tracing on outside pipes and valves, a lack of heat inside certain

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areas of the power plant (many portions of the plant heating system have, for some time been non-functional because of their low priority in the maintenance backlog), and lack of proper workmanship and supervision regarding heat tracing and insulation at the intake

structur The licensee intends to improve cold weather planning in the future and the inspectors will follow their actions as part of l j the routine inspection progra Several equipment problems occurred that could not be repeated and the causes, therefore, remained unidentifie In particular core spray booster pump NZO3A failed to start during a routine surveil-lance, emergency service water pump 528 started but failed to pump at rated flow, and a recirculation pump tripped. The inspectors empha-sized their concerns to the licensee regarding the apparently weak

technical support directed at solution to the problems. Admittedly, q identification and correction of a problems that doesn't repeat it-i self is difficul The inspector indicated a prudent approach for these situations, given the importance of the equipment involved, should include steps to eliminate potential causes. The inspectors also discussed with operations management operations management's philosophy on accepting a piece of equipment for use that malfunc-tioned but no problems was found and no steps were taken to eliminate potential causes of the malfunction. As a result of this discussion, the inspectors concluded operations management needs to be more

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demanding of the technical support services available to ensure adequacy of this suppor During an emergency service water (ESW) system performance test, the licensed shift operators discovered an apparent inconsistency between

the actual system performance and what they believed system behavior to be. During the ESW system test with the facility shutdown for maintenance, a core spray system surveillance test was conducted introducing a 10-10 level signal into system logics. At the time the containment spray system /ESW system was in " dynamic test"; with the addition of the 10-10 signal the running " Automatic" pump (ESW 52C)

i tripped and the system valves lined up to spray the drywell . The operators, perplexed at this occurence, repeated the scenario to verify the problem and proceeded to determine that the system logics indicate this type of system performance was correct. The concern develops when the containment spray manual pumps (518 and 510) are running, since they do not receive an automatic trip as the '

" automatic pumps" do in this situation. This would result in the drywell being sprayed when the valves repositio Another concern

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involves the ability to conduct torus pool cooling should circum-stances require cooling the torus, followed by a lo-lo level signal

, actuation. In this event, torus pool cooling would be inhibited 1 until the 10-10 level signal could be overridden in some fashion, if l

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not operating and the drywell was not sprayed nor was torus pool l

cooling required.

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Some previous concerns have been developed by the licensee regarding the containment spray /ESW system logics. As a result, the licensee is currently analyzing the system logics to submit a technical spec-ification change request to address the previous concerns, but would not address this recent potential proble The licensee has made temporary procedure changes to address this area and to ensure the licensed operators are familiar with this aspect of system operatio This will remain an unresolved item pending licensee resolution of the proble (50-219/87-04-02)

No violations were identifie . Management Action to Address Poor Plant Performance After failure of the plant to restart on February 18, licensee management reflected on the recent poor performance of the plant and concluded cor-rective action was required. Three committees were immediately formed and the decision made not to operate until the committees completed their assigned tasks. This was a new management initiative that indicates an improved approach to operating Oyster Cree The first committee was tasked with solving the IRM problems that had per-sisted since restart form the 10R outage. The second was tasked with investigating loose electrical connections, and the third with identifying backlogged work that should be completed to improve plant reliabilit The IRM committee's activities were discussed in paragraph 4 above. The loose wire committee was formed because of several recent problems with loose wires that appeared to be related to work accomplished as part of a modification to install the Safety Parameter Display System. By the time this committee's work was complete, all electrical terminations in the control room and many others in panels throughout the plant were visually inspected and tested for tightnes Approximately 25 deficiencies were identified and corrected and several long-term recommendations made. The plant reliability committee reviewed a total of 2864 tasks and recommended )

approximately 3% of these be accomplished on a priority basis )

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some i prior to restart. This committee also recommended this type of review be '

performed periodicall The inspectors reviewed the activities of these three committees and observed work in progress to complete the recommended actions. The inspectors sensed enthusiasm from many people at the site regarding this initiative and its potential impact on improving plant performanc . LER Review Licensee Event Report (LER) 86-35 was submitted to identity problems with torus vent and purge valves V-28-18 and V-28-47. It was a partial LER in that the causes for the problems had not been identified and a follow-up LER was promised. It was not clear from reading the LER that tampering

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could be ruled out as a cause, therefore, the NRC inspectors reviewed progress of the licensee's investigatio This effort enabled the inspectors to conclude tampering was not the cause for the leaking con-tainment isolation valve However, the licensee's investigation did disclose other problems that will require corrective action. The problems include an improperly conducted local leak rate test of these containment isolation valves, improper signoff of QC holdpoints, lack of a technical manual to describe overhaul, repair, and adjustments to a containment isolation valve, poor maintenance, and inadequate communications. Correc-tive actions will be reviewed as part of closeout of this LER in a future inspectio . Review of Information Notice 87-08 At u.e request of NRC Region I management, the resident inspectors ques-tioned the licensee as to the status of their review of Information Notice 87-08 (IN 87-08), Degraded Motor Lead in Lindtorque DC Motor Operator This review determined the licensee had received IN 87-08 and was in the process of performing a search of their records to determine if any of the subject motor operators were installed or in warehouse storage. It was determined the motor operator on an isolation condenser containment isola-

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tion valve (V-14-35) may contain the Nomex-Kapton insulated leads. An inspection of V-14-35 motor operator leads as well as those in another motor operator in warehouse storage was performed. Because a conclusive determination could not be made by visual inspection, a sample of the insulation material from both motor operators was sent to Limitorque for evaluation. The Limitorque evaluation determined the insulation on the V-14-35 leads was acceptable as well as the insulation on the motor power leads on the operator in the warehouse. However, it was found the insula-tion on the power leads to the heater inside the motor operator in storage was suspect. This insulation material is currently undergoing qualifica- )

tion by Limitorqu . Results of Inspection to Follow Up Region I Temporary Instruction 87-02, Steam, Feed and Condensate Survey This Region I Temporary Instruction (TI) was issued to provide guidance to the resident inspectors for follow up of Information Notice 86-106, Feedwater Line Brea In particular, the TI inquired into the status of the licensee's current or planned assessment of secondary system pipe wall thinning. The inspection results as are follows: Information Notice 86-106 was received but an action item had not been assigne _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - _ . _ _ _ _ _ _ _ _ _ _ _ _

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8. Action taken since Survey: An opportunity occurred in January 1987 to take some thickness readings on the 'B' feedwater pump suction and discharge reducers. Data indicated there was no significant erosio C. Criteria used to determine what to inspect for potential wall thin-ning:

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High steam moisture content (>5%)

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High steam velocity (>150 feet per sec)

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Unusual pipe geometry, e.g., elbows, reducers, tees l

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D. Future Plans: Extensive inspection being planned during 12R outag E. History of Wall Thinning Inspections:

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In 1978 the 'C' feedwater pump (FWP) discharge 8" reducer leaked and was replaced. At this time all 3 FWP discharge reducers were replaced. Thickness data on the 'B' FWP discharge reducer that was replaced in 1978 was recorded. Subsequent inspection data on the new 'B' FWP discharge reducer taken in 1980, 1984, and 1986 indicates no erosio In 1979 General Physics was contracted to do a pipe wall thin-ning stud They concluded additional inspections should be performe Inspection results of 'B' FWP suction reducer indicate no eros-ion since beginning of plant operatio Based on recommendations of Ger.eral Physics study, Tech Func-tions and Plant Materiel evaluations using the criteria in C above, recommendations in INPO SOER 82-11, and as target of opportunity arose, various inspections were performed during the l 10R and 11R outages. Many planned for 11R were delayed until l 12R due to lack of fundin Portions of the following systems were inspected: main steam, feedwater, extraction steam, heater drains, and various other systems not referenced in this TI.

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During 10R, thirty-four total inspections were conducted. One I problem was found, involving 14" to 16" increasing elbows up-l stream of all 3 high pressure feedwater heaters at welds. These l were repaired by weld overlay. The licensee is not sure of the

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During the 11R outage, four items were inspected, including one with a known leak (main steam drain line). A portion of one main steam drain line was replace Present Program Philosophy The licensee uses nominal wall minus 12.5% to determine acceptability of results. No predictive erosion schedules have been set up. Plans are to use sweep technique and trend low reading Within the scope of this review, no violations were identifie . Damaged Core Spray System Hydraulic Snubber Assemblies In November 1986, toward the end of the 11R outage, the licensee found two core spray system hydraulic snubber assemblies to be damaged. The inspec-tors performed a review of the licensee's investigation into the cause of the damage during this report perio The first snubber assembly, NZ-2-S6, located on a 10" diameter system 1 line on elevation 51' in the reactor building, was found with a bent threaded rod on the rear end attachment and a base plate gap of 1/8". Inspections performed on NZ-2-S6 in July 1986 as part of Bulletin 79-02 reinspection, found the snubber assembly to be satisfactorily installed without any deficiencie The routine Tech Spec 100% hydraulic snubber visual inspection performed in November 1986 identified these new discrepancies. The snubber and assem-bly were replaced and the old snubber tested and determined operable. The second assembly, NZ-2-S10 located on the pipe between the system 2 main pumps and booster pumps in the torus room, was found in November 1986 dur-ing routine Tech Spec visual inspections with a bent threaded rod on the rear end attachment and a partially displaced spherical bushing in the snubber's front paddle. This snubber assembly had been previously inspec-ted in July 1986 as part of Bulletin 79-02 and was found to have a loose Jam nut on the turnbuckle. It was again inspected in November 14, 1986 as part of the Tech Spec visual inspection and found to be satisfactor Finally, it was reinspected by QC on 11/17/86 to close out the jam nut i discrepancy, whereupon, the jam nut was found to be loose, the spherical '

bushing in the front paddle was found to be displaced about 50% out of the  !

paddle, and the adjustment coupling was found to be bent. NZ-2-S10 was replaced along with the other discrepant parts of the assembl The inspectors were particularly interested in the cause of the damaged snubber assemblies. From discussions with Plant Materiel and Tech Func-tions personnel, it was clear the cause had not yet been identified. There are several hypotheses which include damage induced by water hammer due to inadequate venting of the system, damage caused by check valve slam during pump starts, stops, and shif ts; and damage caused by physical abuse. The determination of the cause is still under investigation and a preventive

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maintenance item has been incorporated into the program to perform a min-imum of 5 inspections of the 2 snubber assemblies during Cycle 11 to assure no recurrence of damage. In addition, a work order was written and is in the maintenance backlog to provide better vent capacity by routing

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the system 1 vent valve (V-20-106) hose to a floor drain in lieu of a.15 gallon bottl The inspectors raised questions about the following discrepancies:

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Was there a staking program in effect that addressed the concerns of l NRC Circular 81-05? This Circular addressed the concern of spherical bushings working out of paddles and required that licensees take action to prevent it. An answer was not available at the end of this report period.

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The Tech Spec visual inspection of NZ-2-S10 did not identify any of l the discrepancies identified by QC three days late Discussions with Plant Materiel disclosed that the Tech Spec snubber inspection is performed by MCF personnel -- not by QC -- and that there may be different inspection techniques, e.g., MCF turns the jam nut in the clockwise direction to determine tightness whereas QC turns it in the counter-clockwise directio On 11/22/86, during Bulletin 79-02 inspections, QC identified a loose base plate nut on the baseplate associated with NZ-2-S10. When the sleeve-type anchor bolt was torqued the sleeve backed out of the wall. MNCR 86-999 was issued to document this finding. A Tech Func-tions evaluation of this MNCR said to use-as-is, i.e., the base plate was acceptable with only 3 of 4 anchor bolts. The inspectors ques-

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tioned involved personnel to determine if the other 3 anchor bolts l

were properly torqued and this information given to Tech Functions prior to their evaluation. Although site personnel believed that the information had been provided, the documentation to support this answer was not available at the end of the report perio The unanswered issues raised as a result of the inspection activities include:

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The cause of the damage;

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The existence of a spherical bushing staking program or its equiva-lent and its implementation in the plant for all snubber assemblies;

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The apparent discrepancy between MCF and QC regarding verification of Jam nut tightness. Other discrepancies may also exist; and

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The availability to Tech Functions of information specifying the remaining anchor bolts in the NZ-2-S10 baseplate were satisfactorily installe The above issues are unresolved pending resolutio (50-219/87-04-03)

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10. Plant Computer System Field Wiring Problem Several unexplained events and computer tie in efforts led to the dis-covery that between 600 to 700 field connections were made to incorrect terminals. Each of the connections was off by one terminal point because of a vendor drawing change that was not, by GPUN's account, forwarded to them prior to completion of field wiring efforts that started in 1983 and finished in 1986. The surge cards for all the circuits were removed ef-fectively disconnecting the miswired points, to eliminate any potential

" cross-talk" between the incorrectly wired circuits. Action is underway to effectively modify the connectors so that the wiring will not have to be changed. The resident inspectors will continue to inspect this prob-lem as part of the routine inspection progra . Drywell Shell Thinning Inspection During a January 1987 shutdown, drywell shell thickness measurements were taken using ultrasonic testing (UT) techniques. The measurements were taken in two different locations in bays 5,17, and 19. Forty-nine read-ings per location for a total of 294 readings were taken. These readings were averaged and compared with the average of the readings taken in approximately the same locations in December 1986. A comparison of the averages indicated no corrosion had occurred over the brief period of time between measurements. One fact that became obvious to the inspectors when comparing the readings on a point-by point basis was that the readings were substantially dif ferent and a point-by point comparison to establish a corrosion rate could not be done. The reason fcr this was the licensee had not match marked the locations of the points measured in December, therefore, the points measured in January were not the same. This issue was discussed with NRC licensing and the licensee and it was agreed a template would be used to ensure the same points were measured each tim Unfortunately, a reference point for the template was not established in January and, therefore, no valid base line data for comparison purposed is available. This means the data that is scheduled to be taken in October 1987 will not be able to be compared on a point-by point basis with pre-vious data to aid in establishing corrosion rat The NRC position on this issue as explained to the licensee is that the values of shell thick-ness obtained by averaging may be used for stress calculations, however, a point-by point comparison is desired to aid in establishing corrosion rat Because no base line data is presently available, the licensee needs to ensure during the October 1987 inspection that a system is imple-mented to facilitate taking readings at the same point each time so that readings taken in the 12R outage can be compared on a point-by point basi !

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12. Containment Spray / Emergency Service Water (ESW) Heat Exchanger Differential Pressure Increase

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Results of inservice testing regarding performance of the ESW system indi-

! cated an increase in the differential pressure (d/p) across the ESW side of the 1-3 containment spray /ESW heat exchanger. Based on previous prob-

lems with delamination of the coal tar lining from the inside of the ESW

, piping, plans were made to open and inspect the contents of the 1-3 heat l exchanger. The results of the inspection and subsequent chemical analysis i of the material determined it to be largely the coal tar material with some ferrous material. A visual inspection of the coal tar indicated it was old material from the hydrolazing operation and not freshly delamin-ated. The heat exchanger was closed and the ESW pumps run in both systems for just under 80 hours9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> in an atternt to reach a stable d/ After approximately 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br />, the d/p stabilized at a reasonably low value, thus indicating an operable ESW system. Licensee efforts in identifying and troubleshooting this concern were considered by the inspectors to be effectiv i l 13. Licensee Response to Regulatory Guide 1.97 The inspectors reviewed a letter from NRC Office of Nuclear Reactor Regulation (NRR) to GPUN dated 12/12/86 entitled " Draft Technical Evalua-tion Report for Conformance to Regulatory Guide 1.97 Revision 2." In the draf t conformance document included with the letter, there was a discuss-ion of the standby liquid control (SBLC) system flow and storage tank level (paragraphs 3.3.10 and 3.3.11). In both of these paragraphs it was i

clear the licensee was taking credit for the level indication system on the SBLC storage tan In paragraph 3.3.10 it is stated the level indi-cation in the tank gives indication that flow is occurring. In paragraph 3.3.11 credit is taken for the existence of the instrumentation. The

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problem the inspectors identified was that this tank level instrumentation

! has been out of service since 1985 and present plans indicate it will not be functional until mid-1987 at the earliest. . Because credit is being taken for this instrumentation, the inspectors felt the licensee should

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inform NRC:NRR licensing of its inoperability. The licensee agreed and '

stated a letter was in preparation at the end of this report period to l inform NRC licensing of this and other matters. The inspectors emphasized !

I the need to transmit accurate data to NRC licensing and expressed a con- I cern over the fact the licensee personnel in Tech Functions who took '

credit for the instrumentation did not know it was inoperable. The licen-see stated it was possible the tank level instrument was operable when the initial response was formulate If this was the case, the inspectors

suggested the licensee needs to devise some way to track commitments so that if parameters change, proper notifications can be made. The NRC inspectors will continue to review correspondence to determine whether I this is an isolated cas !

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14. Maintenance, Construction, and Facilities (MCF) Self-Assessment Following the 11R Outage In response to their 1985 SALP commitment, MCF prepared and presented to the resident inspectors a self-assessment of their performance during Cycle 10 and the 10M and 11R outages. The self-assessment discussed strengths and weaknesses and plans for improvement. The inspectors felt the self-assessment was accurate, especially in light of the fact that many of the self-identified weaknesses were similar in nature to those identified in the 1986 SALP. As discussed in the most recent SALP, progress has been made by MCF to improve their overall performance but more still needs to be done. The MCF self-assessment recognizes thi . Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted by the licensee pur-suant to Technical Specification requir, aments were examined by the inspec- -

tor This review included the following considerations: the report includes the information required to be reported to the NRC; planned cor-rective actions are adequate for resolution of identified problems; and the reported information is vali The following reports were reviewed:

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Monthly Operating Reports for November and December 1986 and January 1987;

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Special Report 86-15 dated 12/16/86 regarding degraded fire barrier penetration seals through the floor of the 4160V switchgear vault 1D and floor of the recirc pump MG set room;

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Special Report 86-16 dated 12/17/86 involving a non-functional fire barrier door between the monitor and control area stairwell and the 3 hall outside the cable spreading room; '

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Special Report 86-17 dated 1/23/87 discussing a non-functional por-tion of the fire barrier in the corridor outside the 480V switchgear room; and

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Supplement to Special Report 86-07 dated 2/20/87 regarding deficient fire barriers in the 4160V switchgear rooms and the 'C' battery roo In particular, it was identified that some of the pyrocrete had been removed from the roof of the 416CV switchgear enclosure, discrepan-cies existed in the installation of the rollup fire doors between ,

cubicles in the 4160V room, and two PVC drain pipes penetrating the l

'C' battery room floor were unseale .'

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health physics technician was monitoring the job on the refueling floor and took immediate actions to verify normal radiation levels and air sample activity levels and the absence of bubbles coming off the fuel l assembl The dose received by the operators was checked and confirmed to be normal for spent fuel pool wor The Exxon fuel assembly, UD3E (Cycle 4), was previously dropped in its spent fuel pool storage rack location from a height of approximately 12 l feet on 3/1/84. This may explain the reason for the failure of the

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assembl The licensee had previously completed an analysis on this assembly after the 3/1/84 drop, indicating some concern with permanent deformation of the lower tie plate and casting. The licensee had planned to slowly lift the assembly while conducting a video camera inspection of the assembly prior to placement into an adjacent fuel can. Plans were being made to accomplish this when the annotated move sheet for this assembly was inadvertently given to the operator for completion. The move sheet was annotated with the particular requirements as indicated above, to move the fuel bundle, but was somehow misread by the operators on the refueling bridge. When the assembly was lifted, the operator received a fuel grapple hoist loaded light indication which would normally be expec-ted if an entire assembly (600 lbs.) was lifted. The hoist loaded light did not extinguish until the upper tie plate and 8 tie rods was positioned in a storage rack locatio Possibly, this light should not have been

, illuminated as the weight on the fuel grapple should not have been suffic-l ient to makeup the hoist loaded limit switch. The Technical Specifica-l

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tions require the limit switch to be 5485 lbs. Therefore, depending upon where the limit switch was set would dictate whether or not the operator was receiving an accurate indication. The licensee plans to perform main-tenance on the hoist loaded light to determine if the limit switch is functioning properly. If all the precautions as specified by the core engineering group had been accomplished, the assembly would still have separated as a result of the 3/1/84 dro The licensee has formed a small " task force" to analyze the failure and to develop plans for the appropriate disposition of the assembly. a

criticality analysis and fuel pool temperature and radiation monitoring was performed to ensure the bundle is in a safe conditio In addition, the licensee has visually examined the fuel bundle by use of a video camera and is exploring the possible methods to safely remove the sepa-rated fuel bundle from the storage rack and has contacted the vendor for assistance. The licensee has agreed to identify other fuel assemblies that have been previously dropped. The inspector will review the licensee UD3E fuel bundle disposition procedure prior to implementation. This is an unresolved ite (50-219/87-04-04)

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- . s . Unusual Event; Condensate Storage Tank Leak The licensee declared an Unusual Event at 2345 on 1/26/87 as a result of discovering water leaking from the condensate storage tank (CST) drain valve, V-11-120. At approximately 2130, the licensee discovered water around the base of the CST (approximately 450,000 gallon capacity) which contains slightly radioactive water and commenced an investigation to determine the source. The leaking 4-inch drain valve had filled the valve pit area adjacent to the CST and thus overflowed onto the area around the CS The licensee declared the Unusual Event because of concern of a potential release to the environment and commenced a plant shutdown at 2350. At 0150 on 1/27/87, the licensee discovered a cracked valve body on V-11-120 as the source of the leak.and at 0210 started pumping water from the valve pit to the radwaste system which stopped the overflow onto the surrounding ground; thus preventing any further releas At this time, the plant power reduction was halted at 400 MWe.

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The licensee sampled and visually inspected surrounding storm drains to verify that water released from the CST was confined to the frozen water surrounding the CST. The ice was later removed from the ground, melted and processed through the radwaste systems. After the ice removal, the area was surveyed with negligible results and released for normal us <

The pump the licensee placed in the valve pit was used to return the water, initially to the radwaste system and later back through an open manway at the top of the CST, to avoid environmental release. The valve was replaced when a diver placed a plug in the drain line inside the CST and workers successfully removed the old drain valve and replaced it with

a new valve. After replacement of the valve, the Unusual Event was ter-

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minated at 2025 on 1/27/87. The valve failure is believed to have re-suited from the extremely cold weather and inadequate or nonfunctional I

heat tracing, although the licensee had reportedly checked the heat trac-ing and insulation and found them to be in proper working order at the i beginnina of winte Paragraph 4 discusses other inspector concerns

regarding proper cold weather preparation The senior resident inspector was notified of the event and responded to the site about midnight on 1/26/8 He and two other NRC inspectors observed the emergency response team, radiation protection and sampling, operations, and repair team throughout the event; 'and concluded that the licensee's overall coordination was effective in controlling the leak and repairing the valve.

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20. Unusual Event; Offgas Sample Pump Leak I

On 2/10/87 at 0610 the licensee declared an Unusual Event as a result of identifying the presence of radioactivity in-the feed pump room, requiring i increased awareness in accordance with the licensee emergency procedure.

! The source of the radioactivity was determined to be the offgas sampling

. system which was isolated at 1620 the same day. The problem was identi-

] fled as a result of individuals alarming the portal monitors at the main j security gate and an alarm on the continuous area monitor.

i i The licensee determined the location of the leak to be the filter at the discharge of the offgas sampling pump. Upon further investigation and

. additional sampling to confirm this, the licensee terminated the Unusual j Event at 2026 on 2/10/87. Subsequently, the licensee replaced the offgas l sample pump and repaired the leaking pump discharge filter.

Initially, 3 skin and 9 clothing contaminations were reported as result of the gaseous decay products of xenon. These short lived daughter pro-i ducts decay off rapidly and presented no harmful radiological effects to the personne The offsite dose rate at the site boundary during the Unusual Event was calculated to be 6.14 x 10 6 mr/hr. This rate is below the normal dose rate from natural background for this area and was not a j concern.

I During the protracted course of events associated with this declared i Unusual Event, the inspector felt the licensee could have exhibited more

positive leadership in directing the various support groups to efficiently function as a cohesive, organized task force to prosecute the problem.

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Instead, for example, the technical support center at one time was engaged i

in providing direction and guidance to the Operations Support Center with-out the concurrence or approval of senior emergency management. Poten-

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tially more aggressive leadership could have terminated the event in a i

more timely fashion. The licensee has acknowledged this concern and is

considering methods to imorove in this area. NRC inspector observations of radiation protection, cerations, and repair team efforts did not

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identify any safety concern . Recirculation Pump Discharge Valves l

Inspection Report 86-38 delineated a problem with the failure of the 'E'

i recirculation pump discharge valve to close on demand from the control

! room and to close completely when valve control circuitry was overridden l j in the close direction from the valve breaker. A similar problem occurred

! during cycle 10 with the failure of a recirculation pump discharge valve to close upon demand from the remote control room switch. Although not l safety related, the recirculation discharge valves are required to be

closed should an operating recirculation loop become idle to prevent i

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reverse flow through the loop. Loop flow reversal at Oyster Creek pre-i sents a non-conservative aspect in relation to the power to flow protec-

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tion functions. Previously, the inspector had discussed with the licensee ,

a concern regarding a potentially generic problem with the valves. During i a recent shutdown, the licensee completed Motor Operated Valve Automatic

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Testing (M0 VATS) on the remaining four recirculation discharge valves to 4 ensure the proper closing thrust and to establish baseline conditions of i

! the motor operators. In addition, a modification was completed on the t i

limit switches to ensure positive indication in the control room. The 'E'

i recirculation pump discharge valve had been previously analyzed with '

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! M0 VATS when the problem occurred. The inspectors will continue to monitor

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recirculation system valve performance as part of the routine inspection progra . Unresolved Items l

Unresolved items are matters for which more information is required in i order to ascertain whether they are acceptable, violations, or deviations.

] Unresolved items are discussed in paragraphs 4, 9, and 18 of this report.

23. Exit Interview A summary of the results of the inspection activities performed during j this report period were made at meetings with senior licensee management j at the end of this inspection. The licensee stated that, of the subjects

discussed at the exit interview, no proprietary information was included.

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16. Radiation Protection During entry to and exit from the RCA, the inspectors verified that proper warning signs were posted, personnel entering were wearing proper dosimetry, personnel and materials leaving were properly monitored for radioactive contamination, and monitoring instruments were functional and in calibration. Posted extended Radiation Work Permits (RWPs) and survey status boards were reviewed to verify that they were current and accurat The inspector observed activities in the RCA to verify that personnel complied with the requirements of applicable RWPs and that workers were aware of the radiological conditions in the are During this report period, a substantial amount of radiation exposure was received as a result of the SRM/IRM work under the reactor vessel. As a result, based on a straight line projection of exposure versus time for the year, the licensee at this point is approximately 200% in excess of the goa The overall goal for the year is 300 man-rem and the total exposure as of 3/8/87 was 119.87 man-re . Feedwater Regulating Valve Controllers The licensee replaced the original GE MAC feedwater regulating valve con-trollers with TOSMAC controllers. The replacement was made as a result of the feedwater induced transients the plant has experienced recentl Licensee Event Report (LER)86-032 delineates this problem as well as LERs 85-06, 85-12, and 85-22, reporting similar occurrences. Apparently, a loss of signal condition to the feedwater regulating valves occurs when the GE MAC controller potentiometer is decreased to zero milliamp output with the controller in manual. This results in the loss of signal condi-tion and in a lockup signal with less than a 1 milliamp outpu The locked up feedwater regulating valves have a tendency to shift open and thus the potential to result in an overfeeding condition as reported in LER 86-032. Currently, the licensee has adjusted the output to a minimum of 5 milliamps on the new TOSMAC controllers, thus preventing an operator from inadvertently causing a lock up condition of the feedwater regulating valves from the manual control statio . Separated Fuel Bundle On 3/3/87 during fuel handling operation in the spent fuel pool, a fuel assembly separated into two sections as it was raised from its storage rack location. The fuel assembly (UD3E) apparently failed at the 8 tie rods / lower tie plate mechanical connection. As a result, the upper tie plate and the eight connecting tie rods formed one section and the remain-ing fuel assembly formed the other section of the original (8 x 8 array)

fuel assembly configuration. The upper tie plate and eight tie rods were safely placed in a storage rack location. The other section of the fuel assembly remained in the original storage rack location.