IR 05000219/1986038
| ML20205H066 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 03/23/1987 |
| From: | Blough A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20205H013 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, TASK-2.B.2, TASK-TM 50-219-86-38, NUDOCS 8703310614 | |
| Download: ML20205H066 (29) | |
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{{#Wiki_filter:___________ ___ __ _______________ O T U.S. NUCLEAR REGULATORY COMMISSZON
REGION I
Report N /86-38 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: November 17, 1986 - January 16, 1987 Participating Inspectors: W. H. Bateman W. H. Baunack R. Borchardt L. Doerflein R. Freudenberger R. Fuhrmeister D. Florek J. F. Wechselberger Approved By: / [[,g A. R. Blough, Chieff' Reactor Projects Section 1A b Date Inspection Summary: Areas Inspected Routine inspections were conducted by the resident and Region based inspectors (606 hours) of activities in progress including outage management, radiation control, security, housekeeping, drywell shell thinning investigation, prepara-tions for plant restart and restart activities, and resumption of normal plant operation. The inspectors also made tours of the plant, witnessed performance of surveillance tests, verified the correct valve lineup of various safety systems, followed up on completion and closeout of various system modification packages, reviewed licensee action on previous inspection findings, and inves-tigated corrective action associated with descrepant electrical cable splice Additionally, the inspectors reviewed closecut action on one Systematic Evalua-tion Program (SEP) item and followed up various plant problem Results One violation was identified involving three examples of failure to follow procedures as discussed in paragraph 5. Based on the types of problems that occurred during plant restart, it appears the overall quality of work per-formed during the 11R outage was somewhat improved over previous outages. In-spection activities did not identify any commonality in the restart sequence problems, although key problems resulted from either operator error or equip-ment malfunction. Actions taken to define the scope and address the drywell shell thinning problem were thoroug PDH ADOCK 05000219 G PDR
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i DETAILS Augmented Inspection of Prestartup, Startup, and Post-Startup Activities The Oyster -Creek 11R outage was officially completed on 12/20/86 when final signatures were made in the licensee's Restart Certification Book-le The original completion date for the outage when the plant was shut-down in April 1986 was October 12, 1986. The delay was due in large part to last minute identification and subsequent resolution of a drywell shell thinning problem discussed elsewhere in this report. A plan for augmented NRC inspection coverage during the last few weeks of the outage before restart and for approximately one week of plant operation was implemented to verify licensee preparations for restart, and to verify a safe, well-controlled return to operation The augmented coverage included twelve-to-sixteen hour shif t coverage during startup and power ascension by site and Region based NRC inspector Various subjects discussed in this re-port serve to highlight and document the augmented inspection activit . Surveillance Testing The inspectors observed performance of and reviewed final documentation of results of the following surveillance tests to determine if the tests were included on the Master Surveillance Schedule, performed in accordance with procedure requirements, were technically adequate, and were performed at the required frequency:
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602.4.003, Electromatic Relief Valve Operability Test
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619.3.013, Reactor High/ Low Level and Calibration
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625.4.001, Turbine Overspeed Test and Calibration l
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675.1.001, Inspection of Bergen Patterson Hydraulic Snubbers
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665.5.001, Torus to Drywell Vacuum Relief Valve Leak Rate Test (Reactor Head in Place)
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610.3.205, Core Spray System 2 Instrument Channel Calibration and Test
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645.4.001, Fire Pump Operability Test
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610.4.003, Core Spray Valve Operability and In-Service Test
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619.3.011, Scram Discharge High Water Level Test
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609.4.001, Isolation Condenser Val.e Operability and In-Service Test
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609.4.006, Isolation Condenser Valve Position Indication Check and ) In-Service Test
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610.4.012, Core Spray Pump In-Service Test
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619.3.007, Low Pressure Main Steam Line Functional Calibration Test While Shutdown The following observations were made:
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602.4.003: EMRV 'D' required 6 actuations prior to properly reseat-ing. Based on a downstream temperature reading noted in subsequent plant operation, it appears there is slight leakage past the valve disk / sea .4.001: The turbine overspeed setpoint was found slightly higher than acceptable and was reset and retested three times to ensure proper setting as required by procedur .1.001: As a result of failure of one snubber during performance of this procedure, the Oyster Creek Technical Specifications require the inspection frequency be changed from every 18 months to every 12 month .4.001: Paragraph 5.1 of this procedJre requires that 3 stop-watches be used but only one stopwatch serial number was recorde The NRC inspectors observed adequate licensee adherence to procedural requirements while performing the tests. However, review of the completed surveillance procedures indicated a general problem involving incomplete data sheets. In some cases, the NRC review was prior to licensee manage-ment review and subsequent re-reviews of the surveillance procedures after licensee management review indicated most of the discrepancies had been addressed. No safety concerns were identified with these examples. Atten-tion to detail in surveillance documentation will continue to be routinely reviewed by the resident inspector . Safety System Walkdowns The inspectors directly reviewed the Core Spray and Liquid Poison systems to verify each system was properly aligne This intpection included:
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Verification that each accessible valve in the flow path was in the correct position by either visual observation of the valve or remote position indication;
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Verification that power supply breakers were aligned for components that must actuate upon receipt of an initiation signal;
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Visual inspection of the major components for leakage, proper lubri-cation, cooling water supply, and other general conditions that might prevent fulfillment of their functional requirement No discrepancies were identifie . Plant Operation Review 4.1 Routino tours of the control room were conducted by the inspectors during which time the following documents were reviewed:
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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 Directive The reviews indicated that the logs were generally complete. Control room housekeeping and behavior were observed to be acceptable. A nine inch difference in reactor water level readings on the GEMAC indicators on the SF panel in the control room was noted by the NRC inspectors. Although there are other control room indications of reactor water level which are in much closer agreement, this discre-pancy is still excessive and needs to be corrected. This concern was discussed with the licensee and it was determined Technical Functions is continuing to study the problem prior to making a recommendation for a final solution. This problem also existed for the majority of Cycle 10 operation.
i 4.2 Routine tours of the facility were conducted by the inspectors to i make an assessment of the equipment conditions, safety, and adherence ' to operating procedures and regulatory requirements. The following
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Turbine Building
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Vital Switchgear Rooms
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Cable Spreading Room i
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Diesel Generator Building
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Reactor Building
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These tours identified an outdated copy of Station Procedure 415, Scram Brush Recorder Assurance Check, in the 480 Volt room where the recorder is located, an excessive number of gas bottles on elevation 75' in the reactor building, and a small hole in the base of the north fire wall just outside the 480 volt room. The inspectors iden-tified these discrepancies to the licensee who took appropriate corrective actio The following additional items were observed or verified: Fire Protection:
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Randomly selected fire extinguishers were accessible and inspec- , ted on schedul l
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Fire doors were unobstructed and in their proper positio 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 servic Equipment Control:
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Jumper and equipment mark-ups did not conflict with Technical Specification requirement Conditions requiring the use of jumpers received prompt licensee attentio Administrative controls for the use of jumpers and equipment mark-ups were properly implemented, Vital Instrumentation:
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Selected instruments appeared functional and demonstrated parameters within Technical Specification Limiting Conditions for Operatio Housekeeping: Housekeeping improved throughout the plant restart period. At the end of the outage, many areas of the plant were in need of cleanu Emphasis was placed on improving housekeeping and, although, the rate of improvement was slow it was effective. At the end of the report period, most areas were cleaned up and fresh paint applied to the -
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floors. During this report period, the inspectors toured the
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condenser bay and observed a substantial amount of graffiti on walls and equipment. Additionally, the overall cleanliness was not up to the same standards as other portions of the plant. Although recent efforts have been successful in upgrading the cleanliness in the condenser bay, additional effort is required to complete the jo The NRC interest in this area stems from a concern that too many secondary side equipment failures are challenging both plant opera-tors and nuclear safety systems. Cleanliness is one indicator of the degree of attention paid to the balance of plant. This concern was discussed with the licensee who agreed to consider available options to continue to improve condenser bay cleanlines . Review of Operational Events The 11R outage was officially completed 12/20/8 The first post outage criticality was achieved at 0247 on 12/21/8 Before the end of this report period, two unplanned and one planned trip occurred as well as some other events. The inspectors reviewed these events to ensure they were thoroughly resolved. A summary of the significant items follows:
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The NRC, in light of the drywell shell thinning problems, had con-curred in a plant restart with power limited to 15's until the NRC:NRR review of the licensee's analyses was completed and all questions resolved. On 12/24/86 NRC informed the licensee that the 15% restriction was no longer require A reactor trip occurred at 0249 on 12/24/86. It was the result of an equipment idiosyncrasy and operator error. The trip resulted when a feedwater pump discharge valve partially opened and allowed cold water feed to the core. This caused power to increase to the trip setpoint. The plant power was in the intermediate range at the time of the trip. The equipment idiosyncrasy involved a lockout feature on a feedwater regulating valve controller that occurs when the con-troller is placed in a certain position. Operators are aware of the problem and normally avoid the improper position. Associated with each feedwater regulating valve controller is a valve position indi-cator that shows the percent the valve is open. Should the control-ler be inadvertently placed in the improper position and lockout occurs and the valve starts to open, the valve position indicator would indicate the actual valve position. The operator error in-volved placement of the controller in the lockout position and fail-ure to note that the valve was not closed prior to bringing the feed-water string on line. A NRC inspector attended the post trip review of this event which he considered to be adequate. Plans are to re-place the controllers with a different model that does not exhibit the lockout characteristi O *
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During the plant startup on 12/27/86, the licensee encountered dif* ficulties with Intermediate Range Monitor (IRM) nuclear instrumenta-tion. As a result, the licensee declared the IRMs inoperable and the average power range monitors (APRM) operable in the startup mode to avoid shutting down the plant. This occurred while performing Sta-tion Procedure 1001.9, IRM Calibration to Reactor Power which re-quires IRMs to be calibrated in both IRM Ranges 9 and 10. IRM 16 was declared inoperable in Range 9. Later in the startup sequence, IRM 18 exhibited erratic behavior and was bypassed. According to Technical Specifications, this rendered the IRM System II (RPS II input) in-operable requiring either the insertion of control rods or the in-sertion of a trip on RPS II. The insertion of a trip on RPS II would result in a full reactor scram if an initiation signal on RPS I occurred. The licensee inserted the trip on RPS II for approximately one half hour, while downscale reading Local Power Range Monitors (LPRMs) were bypassed tc, render the Average Power Range Monitors (APRMs) operable. To citrify the meaning of APRM operability in this discussion reference to the Technical Specification basis is appro-priat In the basis for the Limiting Safety System settings a description is provided for APRM operability in reference to a loss of feedwater heating transient. It discusses that once LPRM down-scales have cleared that the operability of the APRMs are ensure It is not until the LPRM downscales have cleared that APRM opera-bility is ensured as prior to this, the downscale indication does not attest to operability or non-operabilit The following LPRMs were bypassed: APRM Channel 1 28-49A 44-33A APRM Channel 2 04-33A APRM Channel 5 Entire channel bypassed APRM Channel 6 12-410 04-33B 20-49B APRM Channel 7 20-098
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The LPRMs provide the necessary flux signal to the APRMs for indica-tion and protection while operating the reactor in the power range (0-100% power). The bypassing of the downscale LPRM inputs to the APRMs was performed in a manner to conform to the APRM operabil'ity requirements of the Technical Specifications. The APRMs were then declared operable in the startup mode and the half trip from RPS II was remove The plan.t was operating low in IRM Range 9 when this occurred. The licensee usually transitions from the IRMs to APRMs at a much higher reactor power in IRM Range 10 and when all conditions are met to place the mode switch in "Run." In order to effect declaring the APRM operable in the "Startup Mode" the licensee interpreted a foot-note to Technical Specification Table 3.1.1, Protective Instrumenta-tion Requirements, as permitting the IRM/APRM transition in the startup mode. The fnotnote requires, "The IRM shall be inserted and operable until the APRMs are operable and reading at least 2/150 full scale." As written in the Technical Specification, this footnote applies to the IRM scram function in the refueling and startup modes only and not in the run mode. The intent of the footnote for normal operating conditions, is to provide assurance of proper overlap be-tween the IRM system and the APRM system so that there are no gaps in the power level indication In other words, to assure that the power level is continuously monitored from beginning of startup to full power and from full power to shutdown. Further, the technical specifications define the "startup mode" as: "The reactor is in the startup mode when the reactor mode switch is in the startup mode positio In this mode, the reactor protection system scram trips initiated by condenser low vacuum and main steam line isolation valve closure are bypassed when reactor pressure is less than 600 psig; the low pressure main steamline isolation valve closure is bypassed; the IRM trips for rod block and scram are operable; and the SRM trips for rod block are operable." This definition reflects that the IRM trips for rod block and scrams are operable in the startup mode, which is inconsistent with the licensee's technical specification interpre-tatio In addition, the nuclear instrumentation has a rod block and a reactor scram incorporated in its design to assure proper overlap between the IRMs and APRMs and properly functioning instrumentatio The IRM upscale and corresponding APRM downscale rod block is effec-tive in the startup and refueling mode The scram function asso-ciated with an IRM upscale and its corresponding APRM downscale is effective in the run mod The coincidence for this circuitry is as follows:
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RPS Channel No. 1
. IRM Channels Corresponding APRM Channels 11, 12 1, 2 * ,
13, 14 3, 4 RPS Channel No. 2
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IRM Channels Corresponding APRM Channels 15, 16 5, 6 17, 18 7, 8 In this case in RPS Channel 2, IRM 18 was bypassed and exhibiting erratic behavior, IRM 16 was declared inoperable as a result of a failed calibration test, and ApRM 5 was bypassed. (Note: As dis-cussed later in this report, IRM 16 was later found to actually have been operable, lessening the significance of this event.) The licen-see elected to continue reactor operation in the startup mode with a declared inoperable IRM system with reactor power decreasing, not establishing the proper overlap between the two nuclear instrumenta-tion systems. The licensee, thinking their interpretation of foot-note (d) of table 3.1.1 was correct, felt that they were strictly adhering to the literal Technical Specification requirement while a different interpretation as spelled out in various plant procedures would suggest either inserting a half trip in RPS Channel 2 or inser-ting control rod It is implicit that when reactor power reaches the level at which APRM instrumentation is monitoring reactor power, that within some short period of time, the mode switch be placed in run and power increase continued. In this case a rod block had been inserted, there was no plan to increase power, and at least 5 hours passed while the mode switch remained in startup and power continued to decreas The IRM system in conjunction with the APRM system provides protec-tion against excessive power levels and short reactor periods in the intermediate power ranges. For a boiling water reactor a high start-up rate is equivalent to a short perio Protection for short periods is provided by a rod block and reactor scram at the high end of the scale of the 10 ranges of IRM instrumentation. As reactor power is increased, avoidance of these protective features is accom-plished by upranging the instrumentation to the next range as reactor l power increases at a reasonable rat If a short period occurs, the operator will not be able to uprange all the IRMs (total of 8; 4 in each RPS channel) simultaneously and a trip will occur, thus provid-ing startup rate protection. In this case, while in the startup mode in IRM range 9, the licensee's actions would have essentially by- . passed the plants startup rate protection had IRM 16 been truly ' inoperable. Although not as significant in IRM Range 9 as in a lower IRM range, this could have been avoided had all station procedures been observed,
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During the course of declaring the IRMs inoperable and the APRMs operable in the startup mode, the licensee violated the following two station operating procedures: 2000-RAP-3024.01, Alarm Response Pro-cedures Reactor Neutron Monitors, and 402.2, IRM Operation During Startup. The 2000-RAP-3024.01 requires,
"If more than one IRM channel per trip system becomes inoperable when the reactor mode switch is in STARTUP and the necessary conditions are met, place the mode switch in RUN. If the made switch cannot be placed in RUN, place the administrative switch on Panel 4F in the rod block position and shutdown the reactor."
This was not accomplished as the licensee declared the APRMs to be operable for neutron monitoring in the startup mode. Procedure 40 step 4.3 requires,
"During IRM operation monitor the IRM channels proper response and overlap (approximately one decade) into both the IRM and APRM range."
Again, this was not accomplished as indicated by nuclear instrumenta-tio Conducting plant operations contrary to the requirements of Station Procedures 2000-rap-3024.01 and 402.2 constitutes a failure of the licensee to follow procedures and forms part of a single vio-lation of Technical Specification 6.8.1 (86-38-01). The significance of this violation is the failure of the licensee to prudently conduct plant operations. Although finally resolved to be of minimal safety significance as indicated below, plant operations should be conducted in a careful, considered manner. Technical Specifications should be employed as guidance on which to base sound conservative engineering judgements and not as a means to justify less conservative plant operations to avoid a plant shutdow The licensee discovered approximately 5 hours after declaring the IRM 16 inoperable as a result of the IRM Calibration Procedure 1001.9, that in reality IRM 16 was operable and had been erroneously declared inoperable. Therefore, the IRM System II was operable the entire time and the safety significance of this occurrence was minima During the course of reviewing this sequence of events, the inspec-tors investigation was hampered by the sequence of alarm recorder missing approximately 7 hours of information. Apparently the opera-tors neglected to insert new paper tape when the recorder ran ou In addition, the lack of annotation on the IRM/APRM recorded traces was a hinderance. Improved licensee performance in attention to these types of details would upgrade control room records and ensure all data is available for a comprehensive post trip revie _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ s *
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The drywell/ torus inerting process took longer than normal and was not done in accordance wf th procedural requirements for one and a portion of another inerting cycle. Station Procedure 312, Reactor Containment Integrity and Atmosphere Control, Rev. 37, states in step 4.2.3:
" Monitor and maintain nitrogen temperature at 65-80 F (as read ; in the Control Room).
NOTE: The temperature range above is important to prevent brittle fracture and cracking of piping which can occur at temperatures less than 40 F."
The NRC inspectors noted during control room observations that nitro-gen temperature during the first and part of the second inerting cycle following plant restart from the 11R outage was about 55 , The inspectors questioned the operators as to why they were not main- ' tatning nitrogen temperature within the procedural limits. The oper-ators directed the inspectors to the note in step 4.2.3. The opera-tors interpreted this note as permission to drop the minimum tempera-ture during inerting to 40*F. In discussions with Plant Engineering, it was determined that the note was added in response to a torus cracking concern that arose several years ago and was not intended to i permit inerting at a lower temperature. The lower temperature was the result of a combination of factors including relocation to a more
- remote location of the liquid nitrogen storage tank during the 11R outage, inadequate performance of the heaters used to heat the liquid nitrogen, uninsulated piping from the tank to the penetration into the reactor building, and a low outside temperature to which the nitrogen gas was exposed during transit from the tank to the reactor building. These factors resulted in the nitrogen temperature just prior to entrance into containment being about 55 F which was 10*F less than the minimum specified in the procedur Part way through the second inerting evolution, the licensee tempor-arily changed Procedure 312 to lower the minimum nitrogen temperature from 65*F to 50 F. Although the NRC inspectors consider step 4. of Station Procedure 312 to be poorly written, the failure to adhere to the procedural minimum temperature of 65*F during the first and part of a second inerting cycle is considered a failure to follow procedures and forms part of a single viojation of Technical Specif-ication 6.8.1 (219/86-38-02).
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On 12/29/86 steam was observed leaking from a stainless steel bellows located in a relief valve discharge line that connects to the main condense The relief valve causing the steam flow and rupture of the bellows should not have lifted. Attempts to repair the leak with the plant on line were unsuccessful and the reactor had to be man-ually scrammed from about 2% power. A shutdown was not possible due to the low condenser vacuum trip feature. Repairs were made and the plant restarted. An inspection of the bellows and relief valve by the inspectors showed that the bellows convolutions had been filled with a sealant in an effort to reduce air inleakage to the condenser through cracks in the stainless steel bellow Also, the relief valve was noted to have been installed with two of the eight flange mounting bolts loos In addition, a valve associated with a re-heater adjacent to the relief valve had hangers missing from the air line and electrical conduit leading to the valve. The hangers had been obviously removed during a previous maintenance activity and had never been replaced. These are indication of lack of attention to quality and to good workmanship in balance of plant equipmen An elevated trunnion room temperature persisted for a major portion of the plant operating time during this report period. A Main Steam Isolation Valve (MSIV) closure signal results when trunnion room temperature reaches 185* The temperature reached a maximum of about 162 Troubleshooting activities identified a loose sheave on one of the fans that was allowing the drive belt to slip off. Addi-tionally, penetration sealing work accomplished during the outage blocked previously existing flowpaths for cooler air from the torus room and insulation was missing from portions of the MSIVs. These problems were addressed during the various shutdowns and their effec-tiveness will be judged during future plant operatio Speed control problems with both the 'C' and 'E' recirculation (recirc) pumps were noted early in the restart period. The licensee investigated and attempted to correct the cause but initial efforts were not successful. Problems with the 'E' pump became worse and on 1/13/87 the 'E' recirc pump was shutdown and the loop isolated by closing the pump discharge valve. Additional troubleshooting con-tinued and on 1/16/87, an attempt was made to bring the 'E' pump back on line. A reactor scram from about 75*; power occurred during this evolution due to flow past the indicated closed discharge valve (see next paragraph). All systems performed as designed and recovery from the trip was uneventfu During the ensuing shutdown, repairs to both speed controllers were completed and subsequent satisfactory operation of the 'C' and 'E' pumps indicates the repairs were ef fec-l tiv The NRC inspectors expressed a concern to the licensee regard-ing the number of performance problems with the recirculation pump l driving and controlling equipment that occurred during the previous ' operating cycle and the early part of this operating cycle and asked if any investigation was in progress to evaluate the need for a major overhaul / upgrade. A response was not available at the end of this report perio '
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As mentioned in the above paragraph, the discharge valve allcwed, flow to pass when the 'E' pump was started. This was inexpected , as the valve position indication in the control room indicated the valve vas closed. When the 'E' loop was initially isolated, the discharge valve could not be closed from the control room and had to be closed by overriding the valve control circuitry locally at the electrical breake When this was accomplished, it appears the overr' ding action continued only until the valve position indicating light in i the control room indicated the valve was closed. Because this light comes on when the valve is about 95% closed, the valve remained about 5% open. Normal automatic closing action involves continued clost/e of the valve until a predetermined torque value on the motor operatur is reached. This ensures the valve disc is driven into the seat In this case the manual override action should have continued under - ' monitored conditiens to ensure total valve closure. The Limit.urque motor operator for the 'E' loop discharge valve was inspected during the ensuing shutdown and the closing thrust increased as well as the torque switch setting to ensure functior,ality of the valve control switch in the control room. The apparent reason the valve did not . close initially from the control room was that a torqui switch in the valve's control power circuit actuated thus preventing normal opera-tion of the valv It is suspected, that because this valve was electrically backseated to ensure a minimum of packing leakage during < plant operation, the torque required to initiate valve motion in the closed direction exceeded the motor operator torque switch settin A similar failure of a loop discharge valve to close from the control room signal was encountered in operating Cycle 10. Tno inspector ' discussed .he potential for a generic problem with the 11 cense These valves do not perform a safety function, but, are required to oe closed to prevent reverse flow through an idle loo The rod worth minimizer performed erratically during most of the plant startups in this report period. The. key cause was an erroneous steam flow signal. The RWM was operabl2 at the start of each startup and remained operable well past the point nf withdrawing the first 12 control rods. (Tech Specs require that, if the RWM is operable at the beginning of a startup, it remain. operable while withdrawing the - first 12 rod If failure occurs prior te withdrawing the first 12 rods, a shutdown is requirec. When the RWM ceaws *.o operata after the first 12 rods have been pulled, it is required by Tech Spacs that an additional operator be committed to verifying selection of the control rods to be withdrawn. This is a compensatory measure and the desirable situation is to keep the RWM operable. The NRC inspectors discussed with the licensee thei* concerns about the premature by-passing of the RWM by an unrealistically high steam flow signal. In particular, the inspectors stated it was less conservative to post a second operator than to correct an erroneous signal, The validity of this concern was especially evident in light of the fact that two I
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s s control rods in the same group were pulled out of sequence in one of Ih the startups when the RWM was inoperable and a second operator had 9E '
, been ' posted to ensure the proper rod was selected and withdraw P Following ,these discussions, the licensee made adjustments to the steam fl y signal' sending unit that improved the RWM performance 'rk]p during the subsequent startu , -- On 1/6/8N'during 1 reactor startup, a MSIV isolation occurred as the result of an oper~ator upranging to intermediate range #10 on inter- mediate range initrument (IRM) #18. At the time the Mode switch was in Startup and ' reactor pressure was less than 600 psig, thus, the ,
MSIV isolation signa This incident was classified an operator error'because operators are trained not to go into intermediate range
#10 until reactcr pressure is greater than 825 ps Additionally, ' - .there is a> newly installed mechanical device on each upranging ,
switch destgred to prevent inadvertent upranging from intermediate
, range channel 9 to 10. What caused the operator to uprange was a spurious increasing power signal from IRM #18 which he attempted to keep on , scale 'to prevent receiving a one half scram signal. After '
i realizing the problem resalted from a spurious signal, the MSIVs were M- reopened a,d 'the startup continued. The NRC inspectors interviewed i several control room operators to determine the effectiveness of the
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newly installed mechanical device designed to prevent inadvertent switch ur ranging. The consensus opinion was the device was not i effectiv4. This .information was discussed with the licensee. This
, matter is the subject of previously unresolved items (219/86-02-02 I and P19/86-J2-03).
y < F -- During the outag'e, testing was performed to verify control room leak-
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age during the closed recirculation mode of operation on the control
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room HVAC system. It was found to be unacceptably high due to an open, damper and operating exhaust fan in the bathroom. The test was then. reperformed with the exhaust fan stopped and the damper close . Althqugh.these test results were still higher than anticipated, they were deterreined to be acceptable by the licensee. In order to con-
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vince NRC licensing of the acceptability of the control room leakage r in the closed recirculation mode of operation, an agreement was made
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to admini.stratively control the bathroom fan and damper to ensure they would only be in service when the bathroom was in use. Inspec-
< _ - tions by NRC inspectors since restart indicate the fan and damper are not Aeing controlled, as agreed. This matter was discussed with the , l i cor.see . A commitment was made to properly solve the prcblem. The h fan end damper are currently tagged out. This item is unresolved pe dirg the licensee's permanent solution. (219/86-38-03) '
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Control room operators inadvertently tagged the 52D Emergency Service Water (ESW) pump out of service while. the No. 1 Emergency Diesel Generator was out of service for quarterly preventive maintenanc This action .placed the plant in a condition where only one ESW pump was operable by Tech Spec definition. .. This situation was recognized i
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by the liceiisee shortly afterwards and was corrected. The NRC inspec-tors discussed this mattsr with the licensee and stressed the import-ance of operator awareness of the condition of all engineered safety feature equipment. The licensee will submit a Licensee Event Report on this matte . Licensee Action on Previous Inspection Items .
(Closed) Inspector Follow-up Iter (219/86-16-01): Measurement Control Evaluation to be Made Based on a Comparison of Results of a Sp11t Sample ,
The analyses were completed and the comparison evaluation performed and found acceptabl (Closed) Inspector Follow-up Item (219/85-23-07): Review Analysis to Support Modification to Eliminate Reliance on 600 psig Setpoint for Core Protection The concerns of this item are further addressed by open items.219/86-02-02 3 and 219/86-02-03 and, therefore, this item is close ;_
(Closed) NUREG 0737 Item II.B.2 Plant Shielding Supplemental Safety Evaluation for Oyster Creek Nuclear Generating Station NUREG 0737 Item II.B.2 - Design Review of Plant Shielding (TAC No. 59770)
dated November 21, 1986 reviewed the licensee's analysis and resolution of the plant shielding question concerning the main security buildin This concern was identified in Inspection Report - 219/85-03 and listed as an unresolved item 50-219/85-03-01 during a review of Item II.B.2 at United Engineers and Constructors, Inc., Philadelphia, PA office. The item con-cerned a possible dose < to main security building personnel of 62 Rem for the duration of the acciden In subsequent correspondence, the licensee stated that the main security building is no longer classified as requir-ing continuous post-accident occupancy and that personnel would be evacu-ated when the dose rate exceeds 50 mrem /hr. Review of the supplemental safety evaluation concluded this to be acceptable. Therefore, NUREG 0737 Item II.B.2 is close { Closed) 219/85-03-01 Radiological Habitability of Main Security Building Post Accident This item is closed based on the discussion provided in NUREG 0737 Item II.B.2 abov . . .
a , Radiation Protection During entry to and exit from the RCA, the inspectors verified that proper warning signs were posted, personnel entering were wearing proper dosi-
, metry, personnel and materials leaving were properly monitored for radio-active contamination, and monitoring instruments were functional and in calibration. Posted extended Radiation Work Permits (RWPs) and survey n 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 An administrative overexposure of an individual involved in transferring radioactive resins into a shipping cask occurred during this report
, period. This event was followed up b~y Region I based inspectors. The results of the inspection are documented in NRC Inspection Report 50-219/
86-4 ' Effluent Release
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Towards the end of November 1986, a liquid discharge of approximately 180,000 gallons was made. This was the first discharge in more than two years and resulted because of the excessive amount of water used during the outage and a lack of additional storage capacity. The overboard dis-charge radiation monitor was not functional at the time of the discharge, whereupon it was necessary as required by Tech Specs, to take multiple samples and analyze them to ensure the amount of radioactivity release was within prescribed limits. The inspectors verified multiple samples were taken during the discharge in accordance with Tech Specs and had no further question . Observation of physical Security During daily tours, the inspectors verified access controls were in accordance with the Security Plan, security posts were properly manned, protected area gates were locked or guarded, and isolation zones were free of obstructions. The inspectors examined vital area access points to verify that they were procerly locked or guarded and that access control was in accordance with tM Security Plan.
L No concerns were identified.
l 1 Review of Outage 11R Modifications l For the plant modifications listed below, the inspector reviewed the modification packages, selected procedures and drawings, and held discussions with various licensee personnel to verify that: the s modification installation and testing procedures were adequate and
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" contained sufficient Quality Control hold points; the test results met the established acceptance criteria; operating procedures, sur-veillance procedures and the as-built drawings were revised to re-flect the modification; and operator training on the modifications was provide BA 328102, Excess Flow Check Valve Test Tap Addition
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BA 402032, Reactor Protection System Electrical Protection Assemblies
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BA 402187, Containment High Range Radiation Monitors
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BA 402382, Reactor Head Vent Valve Modification During the review of modification BA 402032, Reactor Protection Sys-tem (RPS) Electrical Protection Assemblies (EPAs), the inspector noted that the modification safety evaluation indicated the modifica-tion would not require changes to the plant Technical Specifications (TS). The inspector determined that this was contrary to a NRC letter, dated September 24, 1980, which required the licensee install fully redundant Class IE protection (i.e., the EPAs) at the interface of the non-Class 1E power supplies and the RPS, and submit appropri-ate TS for the system. In its response dated December 4, 1980, the licensee committed to install such a system during the 1981 refueling outage and submit appropriate Technical Specifications prior to startup from that outag In a subsequent letter dated August 3, 1981, the NRC provided the licensee with model Technical Specifica-tions for the RPS EPAs.
' The inspector noted the NUREG 0822, Integrated Plant Safety Assess- . ment - Systematic Evaluation Program - Oyster Creek Nuclear Genera-ting Station, deferred installation of the RPS EPAs until the Cycle 11 refueling outage. When the inspector questioned the status of Technical Specifications for the system he found that, in fact, a licensee action item (No. 81-148.04) had been assigned to address the TS change; however, the licensee had not yet prepared the proposed change and did not have an expected submittal date. As a result, the inspector obtained a licensee commitment, effective January 1987, to follow the requirements of the RPS EPA model Technical Specifications until the licensee submits appropriate TS for the system to the NR No further deficiencies were identified during the review of these modification . - - _ _ _ . _ _ _ __ - .-
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18 The emergency diesel generator (EDG) underfrequency trip and protec-tive interlock modification was similarly reviewe This modifica-tion provides a method of protecting the EDGs on an overload condi-tion by installing underfrequency relays in the output breaker con-trol circui Prior to the design change, if offsite power was lost while the EDGs were running in parallel with the offsite source, the EDGs would attempt to pick up all plant loads. This would have re-suited in loading the EDGs beyond their design limit. A failure of the EDGs would then prevent power from being supplied to vital plant equipment required for the safe shutdown of the plant. This design modification installed an underfrequency trip relay (81) so that when bus frequency decreases to 56 Hz. the EDG output breaker will trip open. The EDGs will then be completely unloaded and plant loads will trip on the undervoltage conditio Power to vital plant equipment will be automatically restored in the normal recovery to a loss of offsite power as discussed in Chapter 15 of the FSAR. This modifi-cation also rearranged the EDG output breaker logic so that the reverse power (67) and leading VAR (55) relays are bypassed during emergency operation of the diese The inspector reviewed the design modification package including Safety Evaluation 402765-001, Installation Specification OC-IS-402765-001, Installation Procedure A15A-30765, Startup Test Proced-ures, and electrical elementary drawings 3D-741-17-001 and 3D-741-17-00 No deficiencies in the design change process, installation or startup tests were identifie . Review of Reactor Vessel Head Flange 'O' - Ring Safety Evaluation The inspector reviewed safety evaluation No. 221-002, " Operation with one
'O' ring leaking in the reactor head joint." The reactor vessel to reac-tor vessel head connection contains two metal 'O' ring type seals. During the operational pressure test following refueling, the licensee determined that the inner seal leaked. The licensee removed the reactor vessel head .
and replaced the seals; however, the inner seal leaked again during the subsequent pressure tes The safety evaluation was written to justify reactor restart and operation with the inner 'O' ring seal leak. The safety evaluation noted that each 'O' ring seal is designed for full reac-tor pressure and any leakage past the outer seal would be monitored as drywell unidentified leakage and be subject to the Technical Specification limits. The inspector reviewed the safety evaluation to verify that it was properly prepared and approved in accordance with the licensee's administrative procedure The inspector also reviewed the Technical
. Specifications, the FSAR, and ASME Section III to determine the technical adequacy of the safety evaluatio No discrepancies were identified.
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12. Review of Installation of Reactor Low-Low Water Level Sensors On November 10, 1986 the licensee noted the Standby Gas Treatment System (SGTS) initiation function was inoperable because of the placement of jumpers associated with a modification of low-low level sensor The Technical Specifications (TS) required that the SGTS be operable. The SGTS initiation function had been inoperable from November 3, 1986. A review of the licensee's actions associated with this event was conducte In addition to discussions with personnel the following were reviewed:
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Procedure A 15P-30136.010, RPS/ECCS/ESF RE02 Analog Conversion, Modification, Removal and Installation (Electrical)
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Procedure 108, Equipment Control
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Electrical Jumper Check-off Sheets
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Elementary Diagram - Reactor Protection System GE 237E566
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Safety Evaluation for RPS/ECCS/ESF RE02 Analog Conversion Modifica-tion (Electrical) Also, the inspector attended the incident critique conducted by the licen-see of the even This event resulted from the placement of jumpers installed in conjunction with the replacement of reactor water low-low level sensors. The jumpers were installed to prevent spurious trips caused by the work associated with the modificatio The intent was to only jumper one instrument channel at a time but inadvertently both instrument channels were simul-taneously jumpered. This resulted when all 26 jumpers associated with the ! task were placed at the same time as opposed to placing them to support l work on one channel at a time. It was later determined even had the . jumpers been installed as intended, both channels would still have been l simultaneously made inoperable.
Following identification of the problem during the performance of testing, control room personnel, in taking the TS required actions, initiated the SGTS but failed to isolate the reactor building as required. This was identified and corrected in approximately 10 hours, and was attributed to poor communication Licensee Event Report 86-28 was submitted describing this even _ _ _ _ _ _ _ - _ _ _ _ _ .
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In reviewing this event, it was determined that the requirement for main-taining the instrument function operable was fully understood, that the intent was always to work on only one channel at a time, and that no single error or procedural deficiency permitted the occurrence. Also, the licensee viewed this as a significant breakdown in the control of work which should not have occurred. In an effort to fully evaluate the event, the licensee initiated a critique which was conducted by an Independent Onsite Safety Review Group membe The critique included all personnel involved including control room, Maintenance Construction and Facilities, Plant Engineering, and Operations personnel and reviewed in detail all aspects which led to the even Eleven recommendations resulted from the critique, investigation of docu-ments pertinent to the event, and interviews of personnel involved. These recommendations were assigned to appropriate divisions for actio ~ The recommendations included establishing procedural guidance when the number of jumpers becomes excessive or when work is to be sequenced; docu-menting operability, maintainability and constructability review meetings particularly when significant scope changes are made to modification pack-ages; assuring required reviews are independent; providing interpretation of trip system configuration; re-emphasizing the 108 procedure require-ments; if possible, maintaining the same responsible personnel on a spec-ific modification; updating a control relay listing; considering some 108 procedure revisions; considering changing tagout request reviews during outages; and r9-emphasizing administrative procedure complianc The licensee's actions taken in dispositioning the recommendations result-ing from the review of the occurrence or any other findings resulting from the evaluations initiated by the recommendations will be reviewed during a future inspectio The critique also identified certain lessons learned. These included the failure to follow both facility and administrative procedural require-ments, and the need to control extensive temporary variations (jumpers) to the plant. It is assumed these lessons learned will be considered during the dispositions of the critique recommendations particularly where pro-cedural changes are involved, since changes or additional procedural requirements will be of little value if procedures are not being adhered to.
One weakness associated with the licensee's review of the event appears to be the delay in the issuance of the critique (approximately 2 months) to the divisions responsible for reviewing the recommendation It appears more complete corrective action would result while the facts associated with the event are still freshly in mind.
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13. 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, one of these items was verified as follows: The item number is that assigned in the IPSA Item 4.1(4) - Procedural revisions to include the fire water storage tank as a redundant source of water supply to the emergency condenser, and include in operating procedures a minimum inventory of water to be main-tained in the condensate storage tan The licensee has several procedures which specify actions associated with emergency condenser water supplies. These are identified as follows:
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Procedure 307, Isolation Condenser System. This procedure states, in relation to filling the isolation condenser, "In emergency situations fire protection shall be used if condensate transfer is not avail-able." Also, the procedure provides instruction for makeup to the isolation condenser from the fire protection syste Procedure 316, Condensate System, specifies maintaining 20' (250,000 gallons) of water in the condensate storage syste Procedure 333, Plant Fire Protection System, specifies maintaining equal to or greater than 310,000 gallons in the fire water storage tan Procedure 7000-ABN-3200.31, High Winds, specifies certain actions to be taken at specific sea water levels. Among these actions are fill-ing the isolation condenser to the high level alarm (7.7') and fill-ing the condensate storage tank to the high level alarm (43'). This item is considered close . Deficient Electrical Cable Splices in Drywell In discussions with a site employee regarding his work activities, the inspectors became concerned about the installation of Raychem heat shrink-able tubing used to make environmentally qualified (EQ) electrical cable splices. The concerns were: (1) the adequacy of repairs to apparently deficient Raychem cable splices in the drywell, and (2) the adequacy of the safety evaluation associated with the deviation reports written upon identification of the apparently deficient splice _ -. __ _ . . _ _ _ _- _ . - _ _ _ , _ - .
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During installation of a replacement assembly on an Electromatic Relief Valve (EMRV) acoustic monitor system in the drywell, deficiencies were noted on Raychem installations performed during the 10M EQ outage. Five Raychem installations, one on each channel of the EMRV acoustic monitor system, were identified as potentially incomplete. The Raychem installa-tions in question are transition kits used at the end of a cable where the casing is removed to expose the individual conductors. The transition kit is used to seal the casing to the conductors to prevent moisture from travelling along the conductors inside the casin The transition kit contains three (3) pieces: the breakaway piece, the shim, and the outer sealing sleeve. In all five installations of the transition kit, only the breakaway piece was in place. Another type of deficiency was also iden-tified that involved a splice in the 'C' EMRV acoustic monitor's line driver box that had tape of undetermined type and origin on the cable under the Raychem splice sleev In accordance with licensee procedures, deviation reports were prepared for both of these conditions. Deviation Report # 86-480 dealt with inade-quate Raychem transition kit installation, and Deviation Report #86-529 dealt with unidentified tape under a Raychem splice sleeve. In response to DR #86-480 the five Raychem transition kits with only the breakaway piece installed had the shim and outer sealing sleeve added under Short Form Number 3525 Deviation Report # 86-529 resulted in Short Form Number 38414 to replace Raychem splice sleeve on the 'C' EMRV acoustic monitor cable inside the line driver bo To ensure no other defective Raychem splices existed in the drywell, the Quality Assurance group initiated an inspection of the other splices in similar applications on the other channels of the acoustic monitors. Of the total of 15 known splices in the drywell (all associated with the EMRV acoustic monitor system), 5 were identified to be deficient. All five had been fabricated during the 10M EQ outage and had been inspected and ac-cepted by a QC inspector. Four of the five splices were subsequently cut out and re-fabricated. The fifth spice was repaire In addition to discussions with licensee personnel, the following docu-ments were reviewed:
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Station Procedure 732.2.009, Installation of Raychem Splices" Rev. O, dated 2/22/80 and Rev. I dated 8/25/83
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Deviation Report # 86-480 dated 10/3/86 and its safety evaluation
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Deviation Report # 86-529 dated 10/9/86 and its safety evaluation
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Maintenance and Construction Short Forms: Work Request # 38414 dated 11/7/86 Work Request # 35256 dated 4/4/86 Work Request # 38123 dated 11/13/86
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Station Procedure A15A-51736, "EMRV Valve Monitoring System - EQ Upgrade" Rev. 0, dated 10/5/85
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Quality Control Plant Inspection Reports associated with the inspec-tion and replacement of various Raychem installations
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GPUN Memorandum "Raychem Splices" dated 8/22/86, OC 6131-86-288-QCC0 As a result of these reviews, the following NRC inspector concerns resulted:
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The repair of the Raychem splice kit in the 'E' EMRV line driver box involved removal of the tape and reheating and reshrinking the tub-ing. This technique was questioned by the inspector, however, after consultation with the Raychem representative, it was determined that this was an acceptable method of repai It was determined that the Quality Assurance Group did not inspect Raychem installations controlled by Short Form # 35256 during initial installation in the 11R outage. (Subsequent inspections initiated by the deficient splices determined them to be acceptable.) In response to NRC Information Notice 86-53, the licensee upgraded their inspec-tion procedures to ensure a comprehensive inspection of cable splice The Short Form had been routed to Quality Assurance (QA) prior to its performance, however, there was no mention of Raychem installation in the description of work requested, therefore, the QA reviewer did not have a basis to provide inspection coverage for the jo To ensure QA is informed when Raychem splices are to be in-stalled, the licensee has stated they will revise Station Procedure 732.2.009, " Installation of Raychem Splices" to include a step re-quiring,QA notification anytime the procedure is used. This item in unresolved pending the licensee action stated above. (219/86-38-04)
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Because 5 splices were inspected and accepted by the same QA inspec-tor with unacceptable deficiencies, the NRC inspectors requested the licensee determine if this particular inspector had been involved in inspecting any other cable splices. The licensee review determined there are 33 known EQ cable splices that use Raychem splice kits. Of these 33,15 are in the drywell and the remainder are in the reactor building. The 15 in the drywell were all reinspected and the 5 dis-crepant splices repaire The 18 splices in the reactor building were not inspected by this inspector. Six of these 18 were reinspec-ted to develop confidence that no additional problems existe No deficiencies were identifie __
as e
The NRC inspection results indicated EQ splice problems existed but were corrected by replacing the potentially deficien+ splices. QC inspections were found to be inadequate but additional emphasis and training since identification of the . problems appears to have addressed this proble Other than the Unresolved Item stated above, the inspectors had no further question . Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted by the licensee pur-suant to Technical Specification requirements 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 report was reviewed:
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Special Report 86-14 dated 10/9/86 involving non-functional fire barrier penetration seals not restored to functional status within 7 days from the time of discovery as required by Tech Spec paragraph 3.12. An hourly fire watch was establishe No concerns were identifie . Summary of Drywell Shell Thinning Problem During this report period, the licensee reported to the NRC a problem in-volving thinning of an area of the drywell shell due to corrosio The problem was identified during ultrasonic (UT) thickness measurements of the shell that were taken because of licensee suspicions that water leak-age into the sand cushion located toward the bottom of the drywell and between the drywell and the surrounding concrete in the circumferential vessel segment from approximately the invert of the drywell vent line penetration down just over 3' could cause corrosion. The resolution of the technical significance of the problem involved the licensee and NRC licensing (NRR) with Regional and resident inspector support. The NRR staff was assigned the lead responsibility for evaluation of the licen-see's submittal and the technical resolution of the identified drywell corrosio It was concluded that the original code stress allowables would be met with the drywell plates locally reduced in the sand cushion area to 0.700". Based on UT examination (NRC Report No. 219/86-40) it is concluded that the drywell shell has been reduced by corrosion from its original thickness of 1.154" to an average thickness of about 0.850" with some local areas thinned to about 0.75". The best estimate corrosion rate, based on evaluation of samples of the drywell shell and adjacent sand, is about 0.020" per year. The most conservative estimate for the corrosion rate is approximately 0.050" per yea Thus, even assuming the most con-servative rate of corrosion, there is sufficient margin between the cur-rent thickness of the drywell and the 0.70" acceptable minimum thickness to justify the next cycle of operatio _ _ _ _ _ _
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The key events by date are listed below: 11/20/86 GPUN notified the resident inspectors of a problem with thinning . of the drywell shell. Only a small number of areas measured by l UT. Thinnest reading reported as .832". Original plate thick-i ness stated to be 1.154".
! 11/24/86 A telephone conference call involving the licensee, Region I, and NRR personnel was held to discuss the known particulars of the problem. GPUN stated it appeared that if drywell shell was greater than .8" thick, that it would be acceptable to operate at least one more operating cycl They stated, however, further investigations were in progres NRC stated they felt additional UT thickness measurements should be taken to better determine the extent of the proble The licensee agreed.
! 11/28/86 Results of additional UT thickness readings indicated there were localized thin spots of approximately . 4". Other areas were , found with less thinning but more extensive in nature.
! , 12/1/86 The licensee met with NRC licensing to discuss the status of the i investigation. The licensee and NRC. ag' reed additional informa-tion was required prior to plant restar /6-7/86 Core samples removed from drywell shell. Sand samples take Inspection of the core samples verified the localized thin spots , were not real but were the results of UT thickness measurement inaccuracies caused by imperfections in the steel plate used to i fabricate the drywell shel Other samples indicated the UT
thickness measurements were accurate when an imperfection did
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not cause a premature reversal of the sound wave.
j 12/9/86 Excavations in the drywell concrete floor to permit additional i thickness measurements of the shell were completed. However, I one of the two excavations partially filled with water. This indicated the drywell concrete floor contained water. The water was analyzed and found to be reactor coolant quality. Because concrete is porous and the drywell floor is not sealed, it was ~, suspected that the volume of concrete forming the floor had become somewhat of a concrete sponge. The source of the water was suspected to have been leakage onto the floor during both - operating and outage cycles throughout the history of the plan Concerns as to its deleterious affects on the drywell shell were . i allayed when UT thickness measurements of the drywell shell in the excavation below the water line indicated full plate , .hickness.
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ms -+ -m-, y . - - - - - - .,wwe,.e-.rn, ---- n, -----,4 ,e,- -,--m,mn n o.a,-,---.,-,e- .-e, e ,emmewoer m -,, - - - a,,, n-,
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12/10/86 The licensee met with NRC licensing for a second time to discuss the status of the investigatio /11/86 Region based NRC inspector exited after reviewing UT measurement activitie (See NRC Inspection Report 86-40.)
GPUN held briefing onsite to update key personnel as to status of thinning proble Welding plugs into the holes in the drywell commence /19/86 The licensee met with NRC licensing for a third time. At this meeting the licensee presented conclusions from their investiga-tions and a Safety Evaluation Report in accordance with the requirements of 10 CFR 50.59. Based on the information pre-sented in this meeting, NRC licensing agreed the plant was safe to restart but requested the licensee not exceed 15*4 power until their review of the SER was complet /22/86 Onsite inspectors reviewed completed drywell work package Several concerns were identified including inadequate tracea-bility for the material used for the replacement plugs. Addi-tionally, Region based and resident personnel reviewed SER and ASME Code requirement /23/86 Drywell work package concerns resolved satisfactorily. A modif-ied CMTR was received from the supplier of the plug material that corrected the material traceability proble /24/86 All NRC reviews completed. NRC licensing notified GPUN by tele-phone call that is was acceptable to operate Oyster Creek for at least one more operating cycle. This was contingent, however, on (1) a mid-cycle shutdown and drywell entry to take UT thick- , ness measurements of the drywell shell to determine if the rate of corrosion is consistent with the predicted, and (2) the sub-mission by 6/30/87 of a corrective action plan to stop the corrosio /29/86 NRC licensing issued a letter stating in writing what had been discussed verbally in the 12/24/86 telephone call with GPU The particular details of the problem were discussed at length in various pieces of correspondence between GPUN and NRR. This report will defer to these documents for a detailed description of the proble These docu-ments and others listed below were reviewed by the NRC inspectors as part of the overall inspection effort to ensure this problem was properly resolved:
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NRR letter dated 12/12/86 documenting the 12/1/86 meeting with GPU NRR letter dated 1/5/87 documenting the 12/10/86 meeting with GPU NRR letter dated 1/14/87 documenting the 12/19/86 meeting with GPU GPUN letter dated 12/18/86 presenting the Safety Evaluation Review to NR NRR letter dated 12/29/86 documenting NRC's approval to operate through the end of Cycle 1 Interpretations of ASME Boiler Code, Cases 1272 N and 1272 N- NRC IE Information Notice No. 86-99, Degradation of Steel Contain-ments
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GPUN Work Order No. A15A-51992, Drywell Steel Wall Evaluation
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GPUN BA328227, Drywell Steel Wall Evaluation
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CMTR for plug material: CMTR dated 12/8/86 from Spectrum Laborator-ies, Inc. to Meredith Corporation documenting chemical and physical properties on steel manufactured by Johnson Forg QC Inspection Reports for UT thickness measurements, visual welding
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inspections, liquid penetrant testing of plugs, vacuum box leak test-ing of completed plug welds, and magnetic particle testing of plug weld Original General Electric / Burns and Roe Specification S-2299-4, Design, Furnishing, Erection, and Testing of the Reactor Drywell and Suppression Chamber Containment Vessels
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GPUN MNCR No. 86-966
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ASME Section VIII 1962 Edition and 1983 Edition In addition to reviewing the above documents, the inspectors toured the drywell and observed in process work activitie Welding records were ! reviewed including the Weld Procedure Specification, Filler Metal With-drawal Authorizations, and welder qualification records. No discrepancies were identifie . l
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J In the licensee's letter dated 12/18/86 that submitted the SER to the NRC, it was stated their understanding of the corrosion mechanism was not com-plet Based on calculations, however, it was determined sufficient structural strength ex.ists to permit continued operation for at least Cycle 1 The licensee concluded this letter by stating,
"... we intend to maintain an intensive effort to: Eliminate the source of any future water incursions into the sand be Dry the moisture from the sand cushion and/or otherwise render corrosive attack minima Continue the metallurgical and chemical investigations to determine, if possible, the exact cause of the attac Further assess longer term corrective actions that may be appropriat Continue the UT shell thickness test program at future outages of opportunity including forced outages otherwise requiring entry during the next cycle."
The NRC response letter dated 12/29/86 required a mid-cycle shutdown by no later than 9/30/87 to ultrason1cally inspect affected areas in the drywell shell to ensure corrosion rate assumptions are conservative and the sub-mission of a corrective action plan by no later than 6/30/87. These licen-see commitments and NRC requirements constitute an unresolved item pending their completion. (219/86-38-02) 17. Lack of Rod Block Clamping Circuitry The licensee made a 10 CFR 50.72 report concerning the lack of a clamping circuit in the average power range monitor ( APRM) rod block system. The licensee determined this during the process of changing the rod block line slope as a result of a change to the Technical Specifications. The change allowed the clamp to increase from 106's to 108's powe The significance of this determination is that the surveillance on the rod block circuitry did not ascertain the lack of the rod block circuitr The licensee is reviewing other Technical Specification surveillances to determine the adequacy of each surveillance procedure. This review will be discussed in the licensee's LER on this proble The inspector will review the licensee's LE * . .. o
18. Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, items of noncompli-ance, or deviations. Unresolved items which were identified during this inspection are discussed in paragraphs 5, 14, and 1 . Exit Interview A summary of the results of the inspection activities performed during this report period were made at meetings with senior licensee management at the end of the inspection. the licensee stated that, of the subjects discussed at the exit interview, no proprietary information was include . }}