IR 05000219/1986024
| ML20213F059 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 10/30/1986 |
| From: | Blough A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20213E979 | List: |
| References | |
| 50-219-86-24, NUDOCS 8611130441 | |
| Download: ML20213F059 (34) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report N /86-24 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 At: Forked River and Parsippany, New Jersey Inspection Conducted: August 18 - October 5, 1986 Participating Inspectors: W. H. Bateman, Senior Resident Inspector J. F. Wechselberger, Resident Inspector W. H. Baunack, Project Engineer K. Manoly, Lead Reactor Engineer Approved by:
A. R. Bloetfh, Chief
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Date Reactor Projects Section IA Inspection Summary:
Routine inspections were conducted by the resident inspectors and two Region based inspectors (402 hours0.00465 days <br />0.112 hours <br />6.646825e-4 weeks <br />1.52961e-4 months <br />) of activities in progress including outage manage-ment, radiation control, housekeeping, equipment modifications, concrete repairs, rework of hydraulic control unit 101 and 102 valves, underwater weld repair to a steam dryer support, pulling and continuity testing electrical cable, and inspection of Containment Spray /ESW heat exchangers for evidence of additional deterioration of bitumastic coating inside the ESW pipin The inspectors also made routine tours of the plant, followed up various operational events, review-ed licensee progress towards addressing concerns identified in the pr.evious SALP report, inspected Licensee Event Report (LER) files for LER closeout, ob-served portions of a routine quarterly emergency drill, and monitored physical security activities. Additionally, the inspectors followed up on issues involv-ing the cause for 47 leaking fuel assemblies, the Unusual Event that was declared when the deluge system in the cable spreading room initiated, failure of the newly installed operator for a Core Spray test line isolation valve (V-20-27),
piggy-backing of tagouts on the hydraulic control units, and complaints from 8611130441 861104 PDR ADOCK 05000219 G PDR
contractor workers regarding radcon practices. Finally, a Region based inspector reviewed licensee calculations that concluded the Isolation Condenser System was not rendered inoperable by the four inoperable snubbers discussed in NRC Inspec-tion Report 86-1 Results As a result of these inspection activities, one violation was identified involving failure of the licensee to perform a written safety evaluation prior to implementing a procedure change requiring deactivation of the automatic initiation feature of the Isolation Condenser systam when reactor water level exceeds 181" from top of active fuel (TAF) as discussed in paragraph Licensee action to meet commitments made in response to concerns raised in the previous SALP was found to be generally complete or well underway. Of 15 LERs reviewed 13 were closed. Two unresolved items were opened as discussed in paragraphs 2 and 10.
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DETAILS 1. On Site Review of Licensee Event Reports (LERS)
The following LERs from 1985 events were reviewed to determine if report-ing requirements were met, the report was adequate in assessing the event, the cause appeared accurate, corrective actions appeared appropriate, generic applicability was considered, the licensee's review and evaluation was complete and accurate, and that the LER form was properly complete (Closed) 85-12; Reactor Isolation Scram This LER describes an occurrence which began with a mechanical failure of the plant's electric pressure regulator (EPR) with the unit at full power, which resulted in a decrease in reactor pressure. This pressure drop caused an automatic closure of the main steam isolation valves (MSIVs), resulting in an automatic reactor scram. Following the scram, one of two scram discharge volumes (SDV) did not fully isolate due to its two drain valves not isolating properly. The resulting flow of hot water through the volume caused steam and paint fumes to be emitted into the reactor building. This in turn caused activation of the deluge fire system in a portion of the reactor building. The isolation condensers
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were not initially used for plant cooldown due to high reactor water level. This resulted in an electromatic relief valve (EMRV) actuation and the need to control pressure using the EMRVs. A reactor water cleanup system isolation valve failed to open delaying the reduction in reactor water level to the point where the isolation condensers could be used. Following the restoration of the reactor water cleanup system, reactor water level wu reduced, and reactor pressure was then controlled through manual activati;n of the isolation condensers. The plant was placed in the cold shutdown condition and repairs to the EPR, the two SDV valves, and cleanup system were completed prior to plant startu Due to the significance of this event, a number of reviews and evaluations were undertaken by the licensee. Documentation associated with these evaluations was reviewed by the inspector. These included:
(1) Post Trip Review Group conclusions, (2) Memo A100-85-0099, MC&F Director to Deputy Director, 0C, EPR Malfunction Investigation Report, (3) Memo FSD-85-164, Fluid Systems Director to Director Quality Assurance, Scram Discharge Instrument Volume (SDIV) Drain Valve V-15-134, (4) Transient Assessment Report, TAR-0C-008, and (5) Memo QAES 6133-85-0068; QAES Manager to Manager, QA Design and Procurement, Director, Engineering Projects, and Manager, QA
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Modifications / Operations; forwarding Critique Report for V-15-134 valve spring proble Each of these licensee evaluations, in addition to describing aspects of the event, contained certain recommendations. During this inspection, the inspector determined how each of these recommendations was dispositioned. Results of this determination are as follows:
(A) Post Trip Review Group Conclusions -- This review conducted immediately following the event discussed the event cause, plant response, equipment response, operator response, and made six recommendations related to equipment problems and one to additional training. Documentation and discussions with personnel shows that each of these recommendations has been acted o (B) Memo A1000-85-0099, EPR Malfunction Investigation Report --
This detailed report documents the observed conditions, a background discussion, an EPR reliability discussion, a failure determination, a discussion of correction action taken, recommendations, and conclusio The conclusions reached are that EPR failure is not probable but is possible, the failure is understood and corrected, the functional operability was verified, and improvements can be made to reduce the probability of failure A Technical Function Work Request was written to evaluate the report's recommendations. The results of the evaluation are to install a new duplex filter system. A Request for Project approval has been approved through middle management (divisional) to implement this recommendation. Approval by higher management is still neede (C) Memo FSD-85-164, SDIV Drain Valve V-15-134 -- This memo discussed the reasons why this drain valve failed and requested a QA investigation to see if the proper engineering, procurement, testing, and QA processes were followed in selecting this valv In response to this memo, the critique discussed in paragraph (E) was conducte (D) Transient Assessment Report, TAR-0C-008, Reactor Isolation Scram -- This report described and evaluated the event in detai Included in the report were certain corrective actions (recommendations).
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Completed Plant Analysis Task Records and discussions with personnel verified that all but tito of the recommendations had been dispositioned. The two recommendations which were not acted on were the responsibility of Plant Engineering. The first dealt with procedural inadequacies with Procedure 20 (Plant Cooldown from Hot Standby to Cold Shutdown) and Procedure 305 (Shutdown Cooling System Operation). Under the plant conditions experienced, these procedures hindered operators from reaching cold shutdown because Procedure 305 requires maintaining reactor level greater than 185" TAF. This level precludes venting the reactor dome through the isolation condenser tube side vents to the main steam line. This recommendation, 15 months after the event, is still under review by Plant Engineering. The second recommendation dealt with improving SDV vent and drain valve testing requirement This also is still under review by Plant Engineering. The resolution of these items will be reviewed during a future inspection (219/86-24-01).
( E') Memo QAES 6133-85-0668 which forwarded Critique Report for V-15-134 valve spring problem -- This memo and the critique which it forwarded identified four Quality Deficiency Reports (QDRs) which were issued and contained four recommendation A review of the completed QDRs showed each had been acted on and the corrective actions accepted. Also, actions taken to disposition the four recommendations were documented in memo 5500-85-152, Director, Engineering Projects to Director, Technical Functions. In addition, QC Mod Ops is continuin) to follow vendor document review in accordance with Technical Functions Procedure EP-00 This inspection also reviewed certain other aspects of the LER. These included:
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The procedure governing overriding automatic isolation condenser initiation with reactor water level greater than 180" TA The automatic actuation of EMRVs and follow-up to the "A" valve leakin The completion of the corrective action specified in the LE Additional problems, subsequent to this event, have been noted with RWCU isolation valve V-16-14. These are being pursued by LER 86-04 follow-up.
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Conclusions:
Basically the recommendations associated with the various reviews conducted by the licensee of this event have been dispositioned. In general, the event and resulting recommendations appear to have received high level managemer.t attention. The modification for installation of new filters in the EPR system remains to be approve Of all the recommendations associated with the event, only two have not yet been acted on. These two are recommendations which were assigned 15 months ago to Plant Engineering and, as noted above, deal with procedure changes and improved SDV vent and drain valve testing. Although the LER states the automatic initiation of the isolation condensers on high pres-sure was overridden in accordance with procedures, discussions with opera-tors and operations personnel indicated that the procedure changes which permitted the overriding were only made after the event. It was also noted that although the procedures had not been changed at the time of the event, the operators had been instructed to override the automatic actua-tion of the isolation condensers when reactor level was greater than 180" TAF. This appears to be an example where the training given to operators differs from what was in procedures. The Emergency Operating Procedures still do not reflect this change which has been made to plant operating procedures. Operators stated this discrepancy was also identified during the last simulator training exercis The Isolation Condenser Operating Procedure and the Reactor Scram Procedure have been changed to specify overriding the automatic actuation of the isolation condensers when the reactor water level is greater than 180" TAF. This is done to preclude water hammer in the isolation condenser system. This overriding of the isolation condensers makes an engineered safety system inoperable and, therefore, deviates from the Technical Speci-fications Limiting Conditions for Operation which require that two isola-tion condenser loops shall be operable during power operation and whenever the reactor coolant temperature is greater than 212 The procedure changes which permit the manual overriding of an engineered safety system and the associated violation of a Technical Specification to prevent a water hammer in the isolation condenser system appear to be tech-nically sound. However, these procedure changes appear to have been made without the review required by 10 CFR 50.59. This failure to make a writ-ten safety evaluation which provides the basis for the determination that the change does not involve an unreviewed safety question is considered to be a violation (219/86-24-02).
It was noted by the inspector that a recent revision made to Procedure 130, Conduct of Independent Safety Reviews and Responsible Technical
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Reviews by Plant Review Group, now would clearly require that a written l safety evaluation be performed for the procedure change permitting the ( overriding of the automatic isolation condenser initiation.
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The cover letter forwarding the LER noted the report also fulfills the requirement of Section 6.9.3.f of the Technical Specifications for reporting challenges and failures of electromatic relief valves (EMRVs).
The only information presented in the report relative to EMRVs was that two EMRVs opened as their setpoint was reached. The Post Trip Review notes two EMRVs lifted, with the "A" appearing not to fully reseat. The Transient Assessment Report states the "A" EMRV cycled automatically three times. The inspector noted that just mentioning that two relief valves activated with no additional information did not fulfill the Technical Specification requirements for reporting challenges to relief valves. The inspector further noted that in general, GPUN reports are accurate and detailed and that this appears to be an isolated case possibly due to the fact that two reporting requirements were incorporated into one repor This LER is considered close (Closed) 85-13; Failure to Maintain Drywell-to-Torus Differential During routine plant operation, the drywell to torus differential pressure was found to be below the value specified by the Technical Specifications. The cause was attributed to the failure by operators to recognize the out-of-specificatien condition. The immediate corrective action was to restore the required differential pressure within 10 minutes of its identificatio The inspector verified the following long-term corrective action was taken. (1) A memo was written to all operations personnel emphasizing the importance of careful attention to log readings and tour sheet data, (2) meetings were held with operator and supervisors to discuss the event, and (3) specific fr.dividuals involved were counselled via memo to each individua The requirement to maintain a drywell to torus differential pressure has subsequently been eliminated from the Technical Specification (Closed) 85-14; Unit Substation Transformers IA2 and 182 Low 011 During preventive maintenance testing, two unit substation transformers were identified as not having sufficient cooling oil. 'The plant was shutdown and replacement oil adde This event was reviewed in detail in NRC Region I Inspection Report 50-219/85-28. Corrective actions are being followed by Unresolved Item 50-219/85-28-01.
,(Closed) 85-15; Automatic Scram on Low Condenser Vacuum An automatic scram occurred on low condenser vacuum from full power when a crack developed in the casing of a steam jet air ejector (SJAE) drain pum __
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The pump was replaced and, to prevent recurrence, a support has been installed under both SJAE pump (Closed) 85-16; Reactor Scram on APRM Downscale and IRM Hi-Hi During a plant shutdown, the reactor scrammed on coincident signals of average power range monitors (APRMs) downscale and intermediate range monitors (IRMs) Hi-Hi. The cause of the event was operator error by the inadvertent insertion of all eight IRMs simultaneously with the APRMs being downscal The inspector verified: (1) the label on the IRM Drive Select Switch has been changed, (2) the procedure for IRM operation during plant shutdown has been revised, and (3) the event has been included in operator trainin (Closed) 85-17; Drywell Bulk Temperature During operation the licensee approved the increase in drywell bulk temperature from 135 F to 150 F without recognizing the 135 F was an initial accident condition specified in the Oyster Creek FSAR. A subsequent analysis was performed which indicated the peak drywell temperatures and pressures are unchanged or are still within acceptable units when assuming an initial bulk temperature of 150 F vs. the FSAR value of 135 The inspector verified: (1) a report describing this condition has been forwarded to NRR for their review and approval, (2) a new algorithm pro-viding more accurate bulk temperature results has been included in Rev. 34 to Procedure 106, (3) a completed Licensing Action Item indicating training has been provided to key personnel involved in changes to design bases, and (4) the changes in aging effects to environmentally qualified electri-cal equipment has been investigated and changes to component EQ packages initiate (Closed) 85-18; Emergency Service Water Pipe Coating Failure Investigation following the identification of a high differential pressure condition which developed across the baffle plate of the containment spray heat exchanger determined the corrosion protection coating inside the Emergency Service Water (ESW) piping was delaminating and plugging the heat exchanger The portions of the ESW piping containing the failed coating were hydrolazed to remove the weakly adhering material and an engineering evaluation was performed which showed the system can be operated until a long term solution is develope This event has been reviewed in detail in NRC Region I Inspection Report 50-219/85-23. Also, NRR has requested the long term corrective action be provided to the staff. During this inspection, it was determined through
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discussions with licensee personnel, that the increased pipe corrosion resulting from the loss of the coating will not affect the seismic capability of the ESW line (Closed) 85-19; Non-Conservative Error in fechnical Specification Setpoint Calculation The calculated differential pressure equivalent to the Technical Specifi-cation limit for 120% steam flow was found to be incorrect. The correct value was calculated, reviewed and implemented. Previous surveillances were reviewed against the new value. One occurrence of an as-found Techni-cal Specification setpoint exceeding the correct calculated value was identified. At no time did actual plant conditions exceed the correct value.
The inspector verified: (1) a contractor has been obtained to check all Technical Specification setpoints that measure a process via a derivative variable, and (2) it was determined this calculation was not generic but was spe.cific to Oyster Creek.
(Closed) 85-20; Loss of Both Diesel Generators With the reactor in cold shutdown, one diesel generator was declared inoperable because of a failure in the electric governor actuator controlle Prior to this, the other diesel generator was removed from service for battery replacement. Corrective action consisted of replacing the failed controller with a new unit.
(Closed) 85-21; APRM Setpoint Did Not Meet Acceptance Criteria During the performance of a surveillance test, the APRM System I flow converter trip setpoint was found to be slightly above the Technical Specification limit. The cause was attributed to setpoint drif The immediate corrective action was to adjust the flow converter trip setpoint down to within the acceptance criteria. A purchase requisition has been issued to implement the long term corrective action of installing new electronic components.
(0 pen) 85-22; Reactor Scram Due to Main Generator Trip During power operation (at 77%), a phase differential current transformer, part of the main generator protection system, failed. This failure initi-ated a generator trip, turbine trip, and reactor scram. Shortly after the scram was reset, a main steam isolation valve closure and scram occurred.
The second scram occurred as a result of an operator inadvertently ranging the Intermediate Range Monitors (IRMs) past range nine to pick up the range ten contacts. The IRMs in range ten, with less than 850 psig reactor pressure, resulted in the main steam isolation valve closure, and associated scra .-
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The failed current transformer was replaced with a spare. The event was discussed with the operators emphasizing the operation of the IRM range switch. Also, the IRM range switch will be modified to prevent inadvertent actuation of the range ten contacts. Additionally, all current transformers are being replaced during the 11R outage. This LER will remain open pending completion of the IRM Range switch modification.
(Closed) 85-23; Emergency Service Water System Seismic Concerns This report identified two separate seismic concerns related to the Emer-gency Service Water (ESW) system. One concern was the non-seismic system tie-ins of two chlorination lines to the ESW lines and two containment spray heat exchanger relief valve lines on the ESW side which could fail during a seismic event. The other was the identification of 20 deficient ESW pipe supports which could have rendered the ESW system inoperable following a seismic event.
Corrective actions have been taken to assure the ESW system meets require-ments. These actions consist of: (1) the ESW pump operability procedure has been revised to change the minimum acceptable flow rate from 2370 to 2800 gpm to compensate for the flow that could be lost out of the failed chlorination lines is a seismic event; (2) The relief valve lines have been seismically supported; and (3) the deficiencies in the ESW piping system supports have been corrected.
During the review of this report, a number of issues were discussed with licensee personnel. These ircluded the following:
(1) The inspector noted that in accordance with the guidelines provided in NUREG-1022, Licensee Event Report System, Supplement No. 1, the',e two specific plant conditions should have been reported as ;eparate LERs. The licensee acknowledged the inspector's comment (2) Although the report states only five instances were noted in which the ESW pumps delivered less than 2800 gpm, the inspector noted that these five instances occurred during the period 1981 to 1983. The inspector identified that there were seven additional instances during 1985 in which the flow recorded during surveillance testing was less than 2800 gpm. From this it was evident the licensee inadvertently overlooked these in developing the repor (3) The chronology of events associated with the identification of the non-seismic chlorination lines attacFed to the seismic ESW lines appeared extensive. The details follow:
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This condition was initially documented as a " Preliminary Safety Concern (PSC) and Potential Licensee Event Report" in accordance with Corporate Procedure 1000-ADM-7330.01 by a Technical Functions Division Engineer on May 21, 198 Between May 21, 1984 and October 8, 1985 several discussions were held and memos written relative to this matter by the persons procedurally responsible for the review of the PS On October 8, 1985 a memo, Loss of ESW Flow Through 3reaks in Non-Seismic Branch Connections, was written from the Manager, Mechanical Systems to the Manager, BWR Licensin This memo concluded, "The ESW pumps should not be allowed to degrade to the point where the minimum flow requirements of the CS heat exchangers cannot be guaranteed following a seismic event. Therefore, a minimum flew requirement will be set at approximately 2800 gpm for ESW pump surveillance testing until the possible pipe break locations can be upgraded or removed."
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On November 18, 1985 the initial PSC was evaluated using the form provided in Procedure 1000-ADM-7330.01, and the
, condition was recommended to be reporte Per the LER, this condition was, " Discovered and identified as reportable on December 11, 1985."
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The report of the condition was issued on January 27, 198 In all, a delay of approximately 18 months was experienced in the overall evaluation, initiation of corrective action, and reporting of the condition.
As noted in the cover letter to this inspection report, the licensee has been requested to: (1) provide additional information relative to the delay in reporting and the initiation of action to correct this significant safety concern, and (2) explain steps that will be taken to improve future evalua-tions and adherence to reporting requirements.
(0 pen) 85-24; Reactor Trip Due to High Neutron Flux During power operation, a neutron high flux trip occurred as a result of a reactor pressure increase which resulted from a failure in the electric pressure regulator. The failure was caused by an improperly made up wire connection which permitted a lead to come loose.
The inspector verified corrective action was taken to install missing flat washers at the loose connection and at several other connections identified during a precautionary inspection of all connections in the same location.
Also, during this event, a high reactor water level condition occurred.
This high reactor water level has resulted following reactor scrams in the past. As a result of this recurring high water level problem, several engineering evaluations were undertaken to achieve a method of preventing future high level transients. The inspector reviewed portions of Technical
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Data Report 739, OC Post-Scram Reactor Water Level Transient, and an engi-neering memo, Manager Operations Engineering to Operations Director, dated April 2, 1986, Post Scram RPV Level Control. These evaluations identified certain procedure changes to prevent recurring level transients and also to address possible level setpoint changes following reactor trip This event was made required reading for certain Maintenance, Construction and Facilities personnel. In addition, the LER stated the outcome of the level transient evaluations will result in specific guidance to the opera-tors for feedwater control system operation following a reactor tri Discussions with personnel indicated this guidance is currently being per-formed during simulator training and appears to be effective. This LER remains open pending the formal issuance of this guidance to the operator (Closed) 85-25; Main Steam Isolation Valve Closure Caused by Operator Error During a plant startup with reactor pressure at 130 psig and prior to with-drawing. control rods, an operator moved the reactor mode switch from Refuel to Startup and noted that a refuel control rod withdrawal block signal was present. Thinking that this signal should normally only be present in the Refuel mode, the operator jiggled the mode switch to ensure he was out of Refuel and in Startup, but in doing so inadvertently picked up a Run mode contact. When the Run mode contact was picked up momentarily, the low pressure Reactor Protection System (RPS) trip bypass was deactivated. The absence of the RPS low pressure trip bypass caused the main steam isolation valves to receive an isolation signa The cause of the rod withdrawal block signal was determined to be the power supply to the refueling bridg The power was turned off by contractor personnel working in the are The inspector verified that this event was discussed with all operators during training with emphasis placed on cause investigation prior to action. Also, a memo was issued to all contractor personnel re-emphasizing Oyster Creek requirements to adhere to Procedure 108, Equipment Contro This event was noted as an example of the contractor failing to adhere to procedural control (Closed) 85-26; Neutron Flux Setpoints Exceed Technical Specification Limits This event resulted when a recirculation pump tripped and its discharge valve could not be immediately closed in accordance with procedure This permitted reverse flow in the loop with the idle pump. This reverse flow was added to the flow in the other four recirculation loops. This resulted in the low biased average power range monitor setpoints for the scram and rod block functions to be less conservative than those allowed r
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by Technical Specifications. The cause was attributed to an open torque switch in the close circuit of the valve operator caused by excessive friction in the packing glan Immediate corrective action was to have an electrician trouble shoot and close the valv The inspector reviewed an analysis performed which showed the setpoint shift was within the bounds assumed in the FSAR. Also, an evaluation of the torque switch setpoint was performed which showed the setpoint was correct. A procedure change was issued which provides instructions to the operators should the condition recu The valve has been repacked during the current outage. Review of Calculations for Emergency Condenser Piping Analysis The licensee provided, upon request from the NRC Regional Office, a copy of calculation package No. C-1302-211-5320-017 which documents the evalu-ation of certain piping isometrics in the Emergency Condenser Syste:n. The evaluation was not finalized as it was not yet reviewed by a checker. The analysis was performed upon the identification of four (4) inoperable snubbers on three piping systems as follows:
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Snubber 634-R11 on the condensate return piping from Condenser NE01A to Containment Penetration X-5B
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Snubber No. 634-R5 on the condensate return piping from Cordenser NE01B to Containment Penetration X-SA
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Snubbers No. 633-R1 and 633-R4 on the Steam Supply piping from Containment Penetration X-3A to Condenser NE01A The piping analyses were performed using the DYNAPO-4, version 5.2. The evaluation was based on the design criteria specified in the Technical Specification for Piping Stress Analysis (SP-1302-12.208) utilizing the modal response spectra approach. The seismic load input used the Operat-ing Basis Earthquake (OBE) horizontal response spectra curve specified in the FSAR, Figure 3.7.1. The vertical OBE spectra was specified as 2/3 of the horizontal spectra. The design basis earthquake (DBE) was defined as twice the OBE magnitude. The following findings were noted during the review of the piping analyses:
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The allowable piping stresses specified in the analyses were found to be, in many cases, considerably higher than the permissible limits of ANSI B31.1 for all code equations 11,12, and 13 evaluated. The isolation condenser piping material is A376 Type 304. The basis .naterial allowable at minimum temperature (SC),
specified in the FSAR as 575 F, is only 11.4 psi. The use of higher allowable piping stresses was observed in all three piping isometrics evaluate The analysis of piping systems for seismic loads utilized the square root sum of the squares (SRSS) in the modal combination of piping responses as specified in Regulatory Guide 1.92. The analysis did not employ, however, the Regulatory Guide requirements for the combination of closely spaced modes. The above findings are considered unresolved pending licensee evaluation and NRC review (219/86-24-03).
The inspector determined, however, that the licensee's analyses showed that the-isolation condenser piping met the functional operability criteria invoked by the licensee in its IE Bulletin 79-14 reverification program with the four snubbers removed. Review of Main Steam Isolation Valve (MSIV) Drain Line Modification Valves in the two inch Main Steam drain lines penetrating containment have historically failed local leak rate testing. To overcome this problem, the licensee elected to isolate these valves by installing flanges in the lines both inside and outside containment and then installing blanks in the flange This modification not only isolated the valves from containment but also removea the capability to equalize pressure around the MSIVs. The loss of the pressure equalization feature was not considered significant because it was not used by the license The inspectors reviewed the fo' lowing drawings and documentation associated with BA #323402, Main Steam Line Drain Modification:
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GPUN Dwg. No. 3B-411-21-1000, Rev. O, Main Steam Flow Diagram
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GPUN Dwg. No. 3BM-411-22-1000, Rev O, Bill of Materials for the Main Steam Drain Modification
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GPUN Dwg. No. 3D-411-22-1000, Rev. O, Main Steam Drain Rip Out and Modification Piping Reactor Containment and Trunion Room
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Installation Spacification OC-IS-323402-001, Rev. O, Main Steam Line Drain Modification
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Station Procedure A15A-51784, Rev.1, Main Steam Drain Line Containment Penetration Blanking
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Modification Design Description for Oyster Creek Main Steam Drain Line; OC-411-A, Rev. 0
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Nuclear Safety Evaluation 323402-001, Rev. 1 As a result of the review, a concern arose regarding the NDE requirements for the new socket welds. Station Procedure A15A-51784 required these welds to be visually inspected. The inspect based on the fact the welds were pressure boundary welds, felt the Ids should also be liquid
penetrant inspected. The inspector followed up this concern and determined the licensee's Special Processes and Programs group, during their review of the weld package, did specify liquid penetrant inspection. Review of the final completed weld package indicated the welds were liquid penetrant inspected. The inspectors had no additional concerns as a result of their review of this modification packag . Rework of Hydraulic Control Unit (HCU) Manual Isolation Valves Throughout this report period, the licensee continued and completed inspection and repair activities to the HCU 101 and 102 valve The inspection of these valves was precipitated by evidence that the valve discs were cracking due to intergranular stress corresion cracking (IGSCC) as discussed in GE SIL 419. Of the 137 HCU 101 valves (insert line isolation valves) inspected, the discs on 14 showed evidence of IGSCC and were replaced. Of the 137 HCU 102 valves (withdrawal line isolation valves) inspected, the discs on 52 showed evidence of IGSCC and were replaced. The licensee reported in LER 86-020 that the 102 valve in HCU 18 ,15 was found to have one of two ears completely broken from the wedge on the valve disc which could have resulted in affecting control rod motion during rod insertio The inspectors observed valve inspection and disc replacement activitie These activities included freeze seals and performance of liquid penetrant testing of the area of pipes being frozen both before and after the freeze seal. No inspector concerns were identifie . Steam Dryer Weld Repair As a result of inservice inspection (ISI) performed by GE in portions of the steam dryer using underwater videotaping, a broken support weld was identifie The broken weld was at the attachment point of the support to a plate that forms part of the dryer assembly. As part of their routine inspection activities, the NRC inspectors reviewed the videotape to observe the problem and performed follow up inspections during the underwater weld repair. The following documents were reviewed as part of the inspection of the underwater repair:
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Radiation Work Permit (RWP) 128286, Support Work for Steam Dryer l Repair
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RWP 131886, Steam Dryer Repair per Procedure A15C-51659
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ALARA Review 86-253, Rev. 1, Reactor Building 119' Underwater Repair of the Steam Dryer in the Equipment Storage Pool
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Station Procedure A15C-51659, Steam Dryer Repair l
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The weld repair was performed by a diver. Inspector observations of the diving operation indicated the licensee made considerable effort to mini-mize radiation exposure to the dive Review of self-reading dosimeter data showed diver stay times were controlled to prevent overexposur The inspectors did, however, observe the following discrepancies:
(1) The RWP referred to the ALARA review for dosimetry. requirement The ALARA review required that an alarming dosimeter, set at 500 mr, be placed in the diver's helme It also required that the alarming dosimeter be source checked to verify operability, Upon questioning involved radcon personnel, it was determined an alarming dosimeter was not in use and that, instead, a dose rate audible indicator (chirper) had been placed in the diver's helme (2) The ALARA review stated 3 operable underwater survey instruments should be available for use on elevation 119'. The inspectors determined only 2 were available on 119'.
The inspectors discussed these discrepancies with responsible radcon man-agement who stated they would be corrected. A subsequent review of the ALARA review indicated it was revised to reflect the actual condition The inspectors expressed their concern to radcon management that it is important that an RWP and referenced ALARA review be implemented as stated or appropriate changes made. There was agreement on this point and radcon management held briefings with radiation engineering personnel to stress the importance of this issue. The inspectors will continue to review RWPs and ALARA reviews to ensure compliance.
ge 6. Emergency Exercise During this report period, the licensee conducted a quarterly emergency drill as part of their annual drill schedul The main purpose of the drill was to simulate a medical emergency involving contaminated personne This exercise required transport of a simulated contaminated individual to a local hospital to determine the hospital's capability to react. The drill was termed a success by the licensee. The inspectors observed onsite activities associated with the drill and did not observe any major deficiencie . Standby Gas Treatment System (SBGTS) Charcoal Filter Testing To satisfy Tech Spec surveillance requirements, the licensee performed a methyl-iodide test on a sample of the charcoal in SBGTS #1. The test results did not meet Tech Spec requirements and the charcoal filters were replaced. Subsequent to charcoal filter replacement, a freon test was performed to ensure the filter cartridges were properly seated. This test failed. Additional work to ensure proper sealing was performed, the
freon test reperformed and it again faile Several iterations of this process were again performed and included changing the charcoal filters again and repacking charcoal in the filters. Each time the freon test failed. Eventually, the licensee brought the charcoal filter vendor onsite for help. The vendor brought his own test equipment, performed the test, and it passe Ensuing investigations determined the licensee's test equipment had not been properly calibrated against a known standard. To correct this problem, the licensee plans to revise their test procedure to require calibration of their test equipment against a known standard. The inspectors had no further questions on resolution of this issu . Reactor Building Closed Cooling Water (RBCCW) Heat Exchanger Floor Repairs While attempting to prepare the concrete surface under the north support for the 1-1 RBCCW heat exchanger for grouting, it was determined there were voids in the floor area. The heat exchangers are located on elevation 51' in the reactor building. The initial response involved sounding the concrete in the immediate area to identify potential voids and then chipping in these areas to determine the extent of the void As the surface concrete was removed, subsurface rebar was exposed and was noted to be corroded. The licensee concluded the concrete voids were really not voids but that the surface concrete (approximately 2" deep)
had either been improperly cured or mixed during initial construction, thus resulting in weak and porous concrete in the affected areas. The chipping was continued until solid concrete was reached in all areas identified by sounding to be potentially defectiv The weak and porous concrete in areas around the heat exchangers offered a path for moisture to reach the subsurface rebar and corrosion of the rebar resulted. An initial Tech Functions evaluation of the corroded rebar determined it to be acceptable as is. The NRC inspector questioned this evaluation because the full extent of the corrosion and the amount of rebar involved had not been investigated. When questioned as to their technical basis for the "use-as-is" disposition, Tech Functions personnel agreed to more fully investigate the problem. Additional excavation was performed, corrosion was removed from the rebar, and measurements of rebar cross sectior.al thickness were made. Based on evaluation of this technical data, the same conclusion was reached, i.e. , the rebar was not degraded enough to affect design assumptions and, therefore, was accept-able as is. The NRC inspector expresseo his concern to the licensee over the fact that the initial evaluation and conclusion was based on insuffi-cient data. It is txpected that all technical evaluations of deficient conditions be based on sound technical data. As part of routine monthly inspections, the '.nspectors will continue to review dispositions of deficiencies for scand technical resolutions.
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16 Topical Report No. 037 Core Spray Sparger Inspections Topical Report No. 037 describes nondestructive examinations (NDE) per-formed on the core spray sparger since 1978 and includes inspection results from the present 1986 outage. The spargers were inspected using remote visual methods including electronic enhancement methods and ultrasonic examinations. In 1978 the licensee discovered a through wall crack in the core spray sparger and installed a repair bracket at 208 on System I Subsequently in 1980, 19 visual indications called cracks and 16 ultrasonic indications were discovered. Again repair brackets were installed to ef-fect repairs; 7 on System II and 2 on System Inspections conducted in 1983 and 1986 using improved inspection techniques and equipment did not support the previous inspection results. The 1986 inspection was a com-plete inspection of the spargers with the exception of the areas covered by the repair brackets. The 1986 inspection found no indications on the core spray spargers (the area under the repair brackets were not inspected).
The licensee has concluded that there is only one confirmed crack in the sparger assemblies, the 1978 through wall crack. Their 1986 examinations did not show any indications that could be interpreted as crack . Core Spray System I Full Flow Test Valve (V-20-27) Problem Inspection Report 86-21 discussed a failure of V-20-27 while attempting to close the valve from the control room. The inspectors met with licensee representatives from Plat Engineering to discuss their findings regarding the motor operator failure for V-20-27. The licensee has replaced the new motor operator with the former V-20-27 motor operator and sent the failed operator to the vendor for an evaluation. The licensee explained that the
"new" valve operator had been rebuilt onsite with all new parts and a new motor, as was V-20-26, the comparable System II valve. (Eleven other operators replaced this outage were completely assembled by the vendor.)
i During testing of the new valve, it was observed that the new operator for V-20-27 generated only 9000 lbs. of thrust with a torque switch setting of
- 2, whereas the old operator was capable of generating nearly 13000 lbs. at l the same torque switch setting. The new operator required a setting of 3 1/2 in order to develop the required thrust. The licensee has concluded
- that the problem, although still not fully diagnosed, is limited to V-20-27 I
since no other valve operators demonstrated the torque switch anomal The licansee will continue to investigate the cause of the motor operator failur The inspectors developed another concern regarding the proper approval of motor operated valve automatic testing systems (MOVATS) data. This l question arose as a result of the licensee declaring V-20-27 operable to l commence refueling operations without a proper review of the MOVATS data for V-20-27 prior to commencement of refueling operations. In addition,
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the licensee had developed outstanding questions regarding the operability of V-20-27, but the valve was still released to Plant Operations to satisfy a refueling operations prerequisite. The licensee should clarify who is responsible for reviewing and approving M0 VATS data prior to determining operabilit During this meeting, the licensee made available TDR 623, Torque Switch Settings, which provided a list of Torrey Pines Technology Calculated Thrust loads. The thrust loads for V-20-27 are listed as follows in pounds of thrust:
Close Minimum Nominal Maximum 10,885 11,974 13,171 Open
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Minimum Nominal Maximum 509 4118 4530 Previously, at the time of the V-20-27 motor operator failure, the thrust values listed in TOR 623 were as follows:
Close Minimum Nominal Maximum 12,892 12,892 14,198 Open Minimum Nominal Maximum 12,892 12,892 14,198
Other thrust values in TDR 623 appear to have changed significantly. The licensee agreed to clarify why the thrust values have changed significantl As a result of the meeting, the licensee agreed to determine the cause of the motor operator failure, who is responsible to review and approve MOVATS data before operability determination is made, and why significant changes have occurred in TDR 623 thrust values. This will remain an unresolved item pending the licensee determination and subsequent NRC review (219/86-24-04).
11. Leaking Fuel Assemblies The licensee has completed part of their investigation into the fuel failures occurring during Cycle 10 operation. Preliminary indication is i the 47 fuel failures occurred as a result of pellet to clad interaction (PCI) which occurred during a startup sequence on December 18, 1985.
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Apparently, incomplete pre-conditioning was conducted during the startup sequence which caused the PCI to occur and the resultant fuel failure The licensee plans to examine the circumstances that precipitated the failures and to compile a report which will be presented to the resident and regional inspectors prior to startup.
12. Undervessel Work To Repair IRM/SRMs During the licensee's preparation for refueling, excessive noise was noted in the IRM/SRM systems. The licensee conducted meggar and voltage breakdown tests on the instruments which resulted in IRMs 11, 12, 15, 17, and 18 and all four SRMs failing the test requirements. An inspection of the cabling under the vessel revealed moisture intrusion underneath taped areas allowing the connectors to become wet. The connectors were dried using heat guns and freon. SRMs 21, 22, and 23 were sufficiently dried to meet the test acceptance criteri SRM 24 detector had to be replaced in order to meet the test acceptance criteria. The same method was employed on the IRMs with favorable results except for IRMs 12, 15, and 17. The detectors for these IRMs had to be replace The problem of moisture intrusion occurs as a result of under vessel work performed during an outage. The major contributor to the moisture problem is the control rod drive (CRD) exchange. During each CRD exchange, a large amount of water (approximately 40 gallons) is released, spraying the in-strument field cables and connections. This is repeated approximately 30 times during an outage to rebuild the CRDs. Attempts to protect the nuclear instrumentation connections from moisture intrusion have only been marginally successfu The licensee expended approximately 160 man hours and 9.5 man-rem under the vessel to remedy the detector cabling moisture intrusion proble This same problem occurred in the previous outage where approximately 265 man hours and 32 man-rem were expended on SRM/IRM replacement and repair of cable The licensee is contemplating several modifications to the nuclear instrumentation system which would improve system performance, as well as reduce man hours and man-rem exposure from under vessel work. The inspectors encouraged the licensee to proceed with these modification It was pointed out by the licensee that this problem is industry wide.
13 '. Update of Licensee Commitments Made in Response to SALP Report 50-219/85-99 Various commitments were made by GPUN to address NRC concerns discussed in SALP Report 50-219/85-99. During this report period, the inspectors discussed these commitments with various licensee personnel to determine completion status and have documented the results of these discussions and their own observations in the following tex In general it appears the licensee has made progress in those areas where commitments were
mad There are some exceptions. As a result of the efforts made by the licensee to address the SALP concerns, improvement has been noted in most areas where problems existed. However, . indications as to the effectiveness of many of the corrective actions will not be conclusive until after restart from the 11R outag Licensee Commitment: Positive steps will be taken to address the concerns regarding the professional environment of the control roo (licensee response letter, page A-2).
Inspector Comments: Improvement in the control room decorum is still re-quired at Oyster Cree Indications that improvement is required were two examples where the controls were not properly manned. Additional
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attention is also required to improve the access controls for the control room and ordering of food. The licensee has made a number of physical improvements in the control room including replacement of recorders, human factors considerations, upgraded furniture, new carpets and tile, and painted and relabeled panels. Overall,'there has been some improvement in this area. Discussions held with the Director of Operation indicate a general improving trend with continued effort to further upgrade the control room are ~
Licensee Commitment: Operations management is reviewing control room access procedures and is in the process of securing space to assemble the relief crews and equipment oper'ators so as to limit their access to the control room and ensure operators can be found when needed. (Page A-3)
Inspector Comments: Control room access has been more tightly controlled, but additional improvement is needed. Securing of space to assemble relief crews has not been accomplishe Licensee Commitment: Surveillance procedures will be clarified to define that limited set of acceptance criteria required to meet minimum Tech'
Spec operability requirements. This is. projected to be a long term project which will be started during the 11R outage and completed at the end of 1987. (Page A-4)
Inspector Comments: The. licensee initiated a long term project to clarify safety-related equipment operability criteria contained in the surveillance procedures. This project was started in Cycle 11 and is projected to be completed by the end of 1987. The inspectors reviewed surveillance procedures to determine if the Technical Specification surveillance criteria was evident. The licensee had delineated the criteria necessary to meet Technical Specification surveillance requirements in the selected procedures.
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Licensee Commitment: Continue efforts to clean up the refueling floo (Page A-6)
Inspector Comments: The licensee has initiated a program to cleanup the refueling floor, but has not completed their effort Management attention is still required in this area to insure the cleanup effort continues. There are a significant number of unnecessary items stored around the perimeter of the refueling floor, especially the west wall.
Management's attention has produced results, but continued attention is require Licensee Commitment: Accurate and sufficient log keeping stressed at sir:ulator and logs reviewed daily by management. (Page A-15)
Inspector Comments: The SALP reported a concern regarding the control room log keeping. The licensee has stressed proper log keeping at simulator training sessions and in daily management review of the control room logs. Some improvement in the logs has been noted, but additional detail on key events is still needed. The logs have been noted to wcurately reflect the out of service time for instruments during gresfilance procedures.
Licensae Commitment: More attention to be given to returning inoperable radwaste equipment to service through maintenance and modification and retiring old unused radwaste equipment. (Page A-16)
Inspector Comments: The licensee 'nas placed considerable effort in im-proving radwaste operations, especially the offgas system and the new radwaste facilitie However, equipment problems have persisted, in par-ticular, leaks in offgas system piping and valves, radwaste evaporators, and HVAC damper problems. Continued management attention is required to insure radwaste system availability is maintained and improved.
Licensee Commitment: Radwaste operators need to fully understand the purpose of taking specific readings and to determine the significance of off-normal readings. Training and Operations department will address this concern. (page A-16)
Inspector Comments: The licensee has taken steps to improve radwaste operators' understanding of taking specific readings and the significance of off-normal readings. The steps included training and an administrative control and review program for operating logs. No evidence of the radwaste operators being unaware of the significance of operational readings has been noted.
Licensee Commitment: The licensee stated that discrepancies with the SBGTS will be corrected. One deficiency is the automatic shutdown of the lead system fan after low-flow swap over operation to the standby system and the other is the annunciation of the low-flow alarm during manual operation of the SBGTS. (Page A-17)
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Inspector Comments: No action has been taken to meet this commitment. A safety concern was written to address these problems in 1984 and still remains unresponded to despite the commitment made in the SALP response lette Licensee Commitment: Radiological Controls stated that they plan to formalize Radiological Engineering training in-house. (Page B-1)
Inspector Comments: This training program was changed from an Oyster Creek project to a corporate responsibility which has delayed its implementation until sometime in 1987 at the earlies Licensee Commitment: Implement long range planning to enable matchup of work resources to work scope. (page C-4)
Inspector Comments: The licensee has implemented a long range planning effort to better determine the amount of work to be accomplished in a specific time frame according to the resources available. The licensee attempts to rearrange schedules where resources are limited to accommodate completion of the jo Long range planning has contributed significantly to promoting a manageable work scope. For the Cycle 11 refueling outage some jobs were deleted as new work was added to the outage scope which compensated for the deleted work scope. The deleted work scope will be incorporated in the Cycle 12 refueling outage. The environmental qualifi-cation outage conducted in October-November 1985 time frame was well-con-trolled due in large part to the extensive planning effort and to the relatively limited scope and duration of the outag Licensee Commitment: GPUN plans to upgrade the quality of personnel involved in modifications, repairs, maintenance and surveillanc (Page C-4)
Inspector Comments: The licensee acknowledged a need to upgrade the quality of personnel involved in modifications, repairs, maintenance and surveillances which would require action in several areas including train-
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ing, selection process, and field assignments. In an effort to increase i contractors' ability to function at the Oyster Creek site and to fulfill
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the paperwork requirements of the Work Management System (WMS), the licensee conducts a three day training session for contract supervisors concerning specific requirements for conduct of work at Oyster Creek. For training of plant craft, a training program for I&C technicians, electricians and
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mechanics has been instituted. The I&C technician program has been generally l well received by the I&C technicians and supervisors and as a result has shown early success. The electrician and mechanic programs have not ex-perienced this early degree of success. This training program has just
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been accredited by INP For exempt employees the licensee has not yet l instituted a program, but plans to initiate a program commencing after completion of the current refueling outage.
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Several steps have been taken to improve the selection process of contractors performing work on site. GPUN has elected to screen exempt contract employees' resumes before allowing , contract management to employ an individual. In addition, the use of specialty contractors has been increased for particularly difficult or unusual tasks rather than relying on a general contractor. New GPUN craft personnel must r.ow be screened by an examination process prior to being hired by the compan In regard to field assignments, the licensee has employed additional-first line supervisors to allow more supervisory time to b2 spent in the fiel The results of GPUN's efforts in the above areas cannot be measured in the short term. Success may be measured in the long term if a general increasing trend ir MCF outage performance is noted. There are indications that some of the same problems continue to exist at Oyster Creek as was evident in the incorrect positioning of the ground switch on the 4160 volt circulation water pump breaker and the improper connection of the , starter for the liquid poison pumps. Several incidents also occurred where the fire systems were initiated as the result of the improper use of heat guns, including the initiation of the deluge system in the cable spreading room. Improper conduct of maintenance resulted in the inoperability of the fire pump diesels. A better assessment of the licensee's efforts in these areas may be determined at the completion of the current 11 R outage during plant startup activitie Licensee Commitment: Management attention to direct field observation and verification of work activities by first-line supervision needs to be increase (Page C-4)
Inspector Comments: Management has initiated activities to improve in this area as indicated above. The implementation of job supervisor training and an increase in the number of job supervisors should increase the licensee capabilities to more effectively supervise field work. In addition, operation management screens contract personnel before accepting the individual as a job superviso Inspector observations and discussions with plant personnel indicate that job supervisors spend too much time in the office and may not be sufficiently aware of interfaces with other organizations such as radiological controls. GPUN should determine if the paperwork load on job supervisors prevents effective utilization of their time and detract from productive field effort Licensee Commitment: Supervision selection and screening process needs to be finalize (Page C-4)
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Inspector Comme,ts: The licensee screens the resumes of prospective contract supervisors and approves individuals for hire by the contractor management. During this outage GPUN has attempted to use specialty contractors as much as possible instead of the general contractor to perform special and unusual tasks. The results of these efforts may be more accurately evaluated by improved plant performanc The process mentioned above of screening prospective supervisors' resumes prior to hire is the finalized process to gain quality supervisors for outage related maintenance activitie Licensee Commitment: GPUN MCF stated that additional effort will be placed on enforcing compliance with the Corporate Work Management System (WMS). (Page C-5)
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Inspector Comments: Inspector observations indicate that compliance with the WMS has improved. The licensee has initiated a program of job monitors who assist the area supervisors in providing direction and guidance for the contractor job supervisors. This has increased compliance with WM The job monitors are GPUN employees on loan to MCF to perform a monitoring function of job activities during the outag The Quality Assurance audit group has two open findings in this area regarding adherence to WMS procedures. The audit group plans to review the status of these findings in their October 1986 audit of, maintenanc Licensee Commitments: The licensee stated the development of an administrative procedure to define post maintenance testing (PMT) and assign responsibilities was necessary and should be available in March 1986. They further stated that management attention would be applied to this area to ensure timely completio (Page C-7)
Inspector Comments: The licensee contracted a consultant to develop guidelines for plant generic components. This effort has been cc,mpleted for 73 components, but the administrative procedure to define and prescribe PMT requirements is not complete. The procedure is in the final stages of review and should be complete by the end of 198 In addition, another administrative procedure that governs maintenance procedure reviews has incorporated a section to address PMT specifically.
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The implementation and effectiveness of the PMT program will be reviewed
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l Licensee Commitment: GPUN, as a result of a review of the amount of
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rework, concluded to upgrade craft personnel, upgrade supervisory
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personnel, improve in the technical direction for the performance of I maintenance, and establish accountability for rewor (Page C-7)
i Inspector Comments: The licensee's efforts to upgrade craft and supervisory personnel was discussed above. A procedure to identify rework was written in 1985 but has never been finalized. In the interim, i
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the licensee has initiated informal controls to identify rework and deter-mine the cause of the rework. These controls require an evaluation as to the root cause, corrective action, and lessons learned. Another MCF proce-dure reports rework that results from inaccurate information in approved plans, procedures, or technical manuals. This procedure requires a critique of the identified rework and stipulation of corrective actio In these procedures and informal controls, the licensee has not clearly defined accountability for rework items. As indicated above in the licensee commitment statement, the establishment of accountability for rework was an item of concern to be resolved. It is not clear that the licensee has truly made their people responsible and thus accountable for the quality of the work performed. The licensee has taken disciplinary action against contract and company personnel on significant maintenance problems, though, and has instituted problem reports to identify problem areas and personnel negligence. To the licensee's credit, they have reviewed all MCF critiques for corrective action and issued follow-up items to ensure proper correc-tive action has been take The lic.ensee feels that improvement in the technical direction for the performance of maintenance will result from the improved training programs and the job monitoring program. In addition, new personnel have been hired to fill newly created and present technical positions to improve capabilities in this are Overall, the amount of rework seems to have decreased, considering that the 10M outage rework was minor in comparison to the significant rework conducted at the end of the last major outage. A better comparison will be possible at the conclusion of the current 11R outag Licensee Commitment: The licensee plans to develop a program that will identify and report rework to insure accountability and proper dispositioning of rewor (Page C-7)
Inspector Comments: This program is still in the planning stage with implementation approximately two to three years away. This will be phased in after the computer based maintenance management and tracking system has been fully implemente Licensee Commitment: GPUN has instituted a program to employ additional company personnel to monitor and oversee contractor activities during an outag (Page C-7)
Inspector Comments: Job monitors provide guidance and direction to con-tractor job supervisors unfamiliar with the requirements to accomplish work at the Oyster Creek facilit In this capacity, a job monitor reports to the area supervisor having cognizance over the particular job
- being monitored. The monitors are selected from among knowledgeable GPUN personnel. The effectiveness of this program is not obvious to the NRC inspectors. The licensee plans to have the GPUN corporate training department evaluate the job monitor program at the conclusion of the outag .
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Licensee Commitment: The licensee states.that the craft training program should result in significant improvement in the workers' knowledge and demonstrated ability through completion of the On-the-Job Training Assignment Sheets in his particular craft area. (Page C-8)
Inspector Comments: The licensee initiation of this program has been bene-ficial in upgrading the craft workers' knowledge. The I&C technicians and supervisors have welcomed the opportunity to participate in such a progra The program opportunity also has had an impact on I&C technicians' produc-tivity and, as their knowledge of the plant and systems increased, the number of outstanding job orders decreased in comparison with the elec-tricians and mechanics. There is, however, a high turnover rate in the I&C grou The Oyster Creek I&C technician is a very knowledgeable and capable individual and, therefore, a valuable asset to other site organi-zations. This does not diminish the importance, though, of having a wel qualified, experienced, I&C technician staff. The licensee should examine the I&C staff to ensure the proper compliment of well qualified individuals remains within I&C. Similar improvements within the electricians and mechanics could be effected if the appropriate group supervisors would effectively utilize this training program. Noted improvement in craft quality and knowledge has been noted only within the I&C grou Licensee Commitment: The licensee stated that SIMS would be implemented in the third quarter of 198 (Page C-9)
Inspector Comments: The Station Information Management System (SIMS) is currently scheduled for implementation in February 1987. The format of the computer software for data input did not exactly conform to the tradi-tional format that has been present at the Oyster Creek site. MCF admini-strative procedures must be revised extensively in order to implement the SIMS program. The licensee did not meet this commitmen Licensee Commitment: GPUN will conduct an assessment of the maintenance area during 1986 and establish a schedule to review results of the assessment with Region I NRC personne (Page C-10)
Inspector Comnents: The MCF organi ation has begun work.on this assessmen A schedule for review with Region I has not been established yet.
, Licensee Commitment: GpVN is attempting to improve the attitude of craft personnel towards housekeeping and making the individual craftsmen accountable to bring about the necessary improvement in this area. (Page C-11)
Inspector Comments: The inspectors have not noted improvement in this are The facilities still rely heavily on management controls to insure proper housekeeping. It is not evident that craft attitude has changed or that they are being held accountable for housekeeping. Recent inspector reviews found the station housekeeping procedures to be weak with regard to both radioactive and non-radioactive housekeepin . . , ... -. . . . - . . - . . . - .- .-
Licensee Commitment: The tech support section of MCF has been assigned the responsibility to coordinate timely processing of QDRs, track progress of responses and escalate to upper management deficiencies which are not responded to in a timely manner. (Page C-15)
Inspector Comments: This MCF group has established a manual tracking system for QDRs. Currently the system is tracking approximately 7 QDRs with about 20 QDRs having been issued to MCF this year. Plans are to ex-pand the system and implement a computer based tracking system to incor-porate MNCRs as well as QDRs. Assessment of the performance of this system at present would be limited and, therefore, will be made when the larger scale system is implemente Licensee Commitment: MCF supervision will stress attention to detail with their employees routinely and on a continuing basis. (Page C-15)
Inspector Comments: Again the licensee states that the supervisory training program will help in this area. Also, the addition of the job monitors discussed previously will contribute to this effor In addition, the licensee reports that the quality of the planners has increased as well as the level of detail in the governing maintenance -
procedures. Further, specific job supervisors are selected based on experience and performance for the more difficult task Licensee Commitment: MCF supervisors are being held accountable for failure to properly maintain the cleanliness of areas when work is performe (Page C-16)
Inspector Commente: The inspectors have not noted a significant improvement in housekeepin Licensee Commitment: Actions have been taken by Tech Functions to reduce the significant number of Field Changes Requests (FCRs) and Field Questionnaires (FQs). (Page E-2)
Inspector Comments: Based on the significant quantity of FCRs, FQs, and Field Change Notices (FCNs) generated during this 11R outage, it is not obvious Tech Functions has made progress in this area. In discussions
- with Tech Functions personnel, it was stated that, although the quantity
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of field documents was not reduced, the type of changes required have been less significant. Within the scope of this SALP followup, the inspectors had no way to verify thi It was also determined that the quantity of FCNs, FCRs, and FQs would actually be greater if the same guidelines ap-plied to 11R as applied to 10R. Changes made for 11R have resulted in MNCRs being written where previously FCRs would have been written and many problems identified during concrete anchor bolt inspections were documented on anchor bolt inspection data (AID) sheets whereas previous normal routine would have required a FC l
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In summary, the evidence indicated Tech Function's efforts to improve their overall product in an effort to, in part, reduce the quantity of FCRs, FCNs, and FQs have not yet been effectiv Licensee Commitment: Major upgrading to the plant computer system by technical support groups and commencement of operation of the upgraded computer at the end of 1986. (Page E-3)
Inspector Comments: Upgrading is in progress, however, this commitment will not be met. Progress on the upgrade has been delayed due to a multitude of problem Licensee Commitment: Further reduce both late commitment responses and backlog of open item (page E-4 and E-6)
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Inspector Comments: (The below comments relate to resident inspector observations and are not intended to fully address this commitment. NRC
. Licensing's view of the status of this commitment will be discussed in upcoming SALP Report 85-98.) Since the previous SALP, most licensee responses to Violations have been extended beyond the prescribed 30 day This is due, in part, to purported delays in the mail and the licensee's review and approval circuit. The backlog of open NRC inspection findings has been reduced due to efforts on the licensee's part to better prepare the items for closur Licensee Commitment: Upgrade the Technical Specification (Page E-5)
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Inspector Comments: This commitment tied the upgrading schedule to the BWR Owners Group schedule. Thus far, the Owners Group has not established a schedule, therefore, GPUN has no schedule. GPUN is continuing to participate in the Owner's Group activities in this are Licensee Commitment: ESW pumps 52B and 52D were to be rebuilt and an evaluation made regarding the need to take additional action to address the Containment Spray /ESW heat exchanger differential pressure proble (Page E-7)
Inspector Comments: ESW pumps 528 and 52D were rebuilt during the 10M and '1R outages. No pressure data was available at the time this report was written. However, the licensee committed to submit a follow-up LER on the issue which has still not been received by the NR It is anticipated that Tech Functions will perform the evaluation when data is availabl Licensee Commitment: Address inadequate technical performance by improved design reviews, more emphasis on plant walkdowns, and assignment of accountability to external engineering organizations for the adequacy and accuracy of their technical wor (Page E-8)
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Inspector Commer.ts: Routine inspections have identified continuing problems with inadequate tuchnical support. The inspectors have been aware of walk-down efforts .
The inspectors have not reviewed actions taken by GPUN to hold external engineering organizations accountable. The inspectors have identified problems where such action should have taken place. Inspector reviews of the design review process disclosed problems. An improvement in the organization and content of engineering packages has been observed. Tech Functions coordination with the site was noted to be improved during the Cycle 10M mini-outage and although the level of improvement was not sustained during 11R, it was still improved over that observed in 10 Licensee Commitment: Perform an evaluation of the effectiveness of the safety review process within three to six months after implementation of the revised 1000-ADM-1291.01 Safety Review Procedur (Page F-2)
Inspector Comments: The evaluation has not been performed because the revised Safety Review Procedure was not approved until 9/1/86.
Licensee Commitment: Strive for further improvement in timeliness and aggressive pursuit of resolution of QA/QC findings. (Page F-3 and F-4)
Inspector Comments: The inspectors reviewed a sampling of MNCRs, QDRs, and QA audit findings in an effort to determine if improvements have been achieved. This review indicated there is a reluctance to implement the escalation process when conditions dictate. A majority of the documents reviewed were properly responded to without the need to enter the escalation process, however. Personnel changes have been made in several groups that have the potential to result in the identification of more preceptive and significant findings than have been identified in the past. The identification of more perceptive and meaningful problems should result in more timely and adequate responses from the various divisions at Oyster Creek.
Licensee Commitment: Cont'nuing attention will be directed at lack of management response, inadequate response, tardy completion, and/or tardy QA follow-up of QA/QC findings. (Page F-4)
Inspector Comments: This commitment was discussed with QA management who, in turn, stated several initiatives have been implemented to better track the status of QA findings. These include reports to the vice presidents and monthly QOR and MNCR status reports. Additionally, the licensee stated weekly reviews are conducted of MNCRs a d audit findings and MNCRs are tracked and reviewed in more detail by both Operations QA and the Plans and Programs group in Plant Operations. These initiatives should result in better informed management. The inspectors could not determine if these initiatives resulted in making upper management more responsive, howeve . . _ - - _ _
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Licensee Commitment: QA initiated actions to assist management with root cause identification and completion of actions to resolve deficiencie (Page F-4)
Inspector Comments: The inspectors performed only a cursory review in this are Their impression was that the effort put in to identifying and correcting the root cause was directly proportional to the perceived significance of the finding. It appears the most significant step QA can make to improve this area is to identify more significant finding Licensee Commitments: MCF is committed to improving attention and responsiveness to quality problems. (Page F-7)
Inspector Comments: Based on discussions with QA management, reviews of QA/QC documents, and inspector observations, the inspectors concluded that MCF made improvement initially but was unable to sustain their momentum as the work load involved with the 11R outage continued to grow.
License _e Commitment: Replace various security equipmen (Page D-2)
Inspector Comments: Many pieces of security equipment have been replaced / upgraded.
Licensee Commitment: Full implementation of the Oyster Creek Security Preventive Maintenance Program by the end of January 198 (Page D-3)
Inspector Comments: Discussions with Plant Security management indicated that the preventive maintenance program was fully implemented on schedule.
Licensee Commitment: Reduce the number of vital area door nuisance alarms. (Page D-3)
Inspector Comments: No improvements noted in this area. The licensee determined this problem to be industry wide. Attempts have been made to reduce the number of nuisance alarms by educating personnel with minimal success. A door handle design fix that is hoped will help has been undergoing engineering evaluation.
Licensee Commitment: Eliminate the need for fixed security posts during 1986. (Page D-4)
Inspector Comments: Fixed security posts still exis It appears that all but one will be gone by the end of 198 l
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14. Unusual Event - Flooding of Cable Spreading Room Hot air blowers used to shrink heat shrink material caused initiation of the water deluge fire protection system in the cable spreading roo Refueling operations were in progress at the time. Shortly after the deluge system initiated, one fourth of the rod position indication in the control room was lost. At this point, an Unusual Event was declare Operator action included ceasing refueling operations, verifying no fire existed in the cable spreading room (CSR), isolating the deluge system to ,
stop spray down, and posting a firewatch. It was not immediately known what caused the alarm or what caused the loss of a portion of the rod position indication, but it was obvious from an inspection of the CSR that no fire was in progress. Proper notifications were mad Subsequent investigation determined that two contractor electricians had been applying heat shrink tubing and heat from the hot air blower used to shrink the tubing had set off the smoke detectors. The cause of the loss of rod position indication (RPI) was moisture intrusion into the ER2 cabi-nets th.at house the RPI electrical components. The inspectors toured the CSR after the event and found work in progress to dry out the RPI electric circuit boards. During questioning of personnel involved in the drying operation, it was determined that input from the RPI to the rod worth minimizer (RWM) would not be verified prior to recommencing refueling but would be completed prior to performance of the shutdown margin tes A Short Form was written to track this work activity. A short time before commencement of the shutdown margin test, the inspectors questioned the licensee as to the results of the test verifying RPI input to the RWM and discovered this test had not been performed and was not on the prerequisite list. After.the inspectors pointed out this oversight, the licensee per-formed the test with satisfactory result The inspectors stressed the importance of performing required work in the proper sequence, especially in light of the impending plant restart.
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Follow-up corrective action to preclude initiation of fire detection systems by a source of heat used in routine work activities was still under evalu-l ation by the licensee at the end of this report period. The inspectors l will review MCF Critique 86-022 when it is complete to ensure corrective
- action is appropriate (219/86-24-05).
l l 15. Action on Previous Inspection Findings i
l (0 pen) Unresolved Item (219/85-23-04): Delamination of Coal Tar Lining l from Portions of Emergency Service Water (ESW) Piping
[ This item was also discussed in NRC Inspection Report 86-19. During this l report period, the ESW/ Containment Spray heat exchangers were opened to
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inspect the ESW (tube) side for accumulation of foreign material. This
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inspection identified pieces of coal t4r lining laying on top of the tube l sheet. The quantity of coal tar material in System 2 exceeded that in System I by a slight amount. The NRC inspectors examined the physical i
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characteristics of the material and evaluated the quantity and subsequent-ly met with the licensee to determine the licensee's interpretation of the
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presence of coal tar material in the heat exchangers. Both the inspectors and the licensee agreed that the material did not appear to be freshly
~delaminated and appeared to have been material remaining in the piping-after the original hydrolazing and flushing operation performed in 198 To assure this was the case, the licensee reviewed a previous video inspec-tion of the inside of the ESW piping to confirm that the point at which the hydrolazing was stopped in 1985 had not changed. This inspection con-
. firmed no new coal tar delamination had occurred. The inspectors expressed
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d concern that, since all the loose coal tar lining removed by hydrolazing
, has not been flushed out, the potential still exists for degraded heat i exchanger performance due to tube blockage by the remaining loose coal tar
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material. The licensee responded by stating they continue to monitor heat exchanger differential pressures and intend to take action should clogging problems be indicated during routine monthly surveillance testing. The
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inspectors had no additional questions at this tim . Review of Periodic and Special Reports
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I Upon receipt, periodic and special reports submitted by the licensee
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pursuant to Technical Specification requirements were examined by the in-spectors. 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
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the reported information is valid.
! The following reports were reviewed:
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Monthly Operating Reports for July and August 1986
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Special Report 86-06 dated 7/28/86 regarding improper valve lineup
of the Fire Water Suppression system that rendered the system ~
inoperable. The particular problem was a closed valve in the fuel i
supply line to the diesel driven fire pump engine. The inspectors made an inspection of the physical layout of the diesel fire pumps,-
fuel tanks, etc. and noted some areas for improvement that were discussed with Plant Operations-personnel. In particulaa labeling of the tanks and valves, specifying a valve lineup, and requiring a valve lineup check with verification appear appropriate. Corrective action will be verified in a subsequent inspection (219/86-24-06).
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Special Report 86-08 dated 8/15/86 concerning the following two events:
(1) Diesel engine gauge replacements were not completed on Fire Pump 1-2 within 7 days as required by Tech Specs, and
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(2) The Fire Suppression water system was declared inoperable when a gauge during the above discussed 7-day time frame was damaged by personnel working on Fire System 1- Special Report 86-09 dated 9/17/86 relating the finding that the
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setpoints on four reactor safety valves were found out of tolerance low when tested at Wylie Laborator Special Report 86-10 dated 9/17/86 describing a non-functional fire barrier (wall) above the southwest entrance to the Monitor and Change area. This wall was found to be made of one layer of sheet rock fastened to steel studs which does not comply with a one hour UL fire ratin Special Report 86-11 dated 9/17/86 related that a fire barrier penetration seal around a conduit exiting the cable spreading room had cracked grout around the periphery of the condui Special Report 86-12 dated 9/16/86 described fire barrier penetration seals around seven conduits in the Monitor and Change area had cracked grout around the periphery of the condui . 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 calibra-tio Posted extended Radiation Work Permits (RWPs) and survey status boards were reviewed to verify that they were current and accurate. 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 Two contractor workers approached the NRC inspectors with a concern re-garding potential intake of radioactive materia In particular the workers stated they were denied the use of respirators while grinding material that had fixed contamination. The inspectors pursued the concern with radcon personnel and determined that radcon considers the use of engineering measures that obviate the need for full face negative pressure respirators to be the more desirable approac In this case air flow into a filter had been established in the area of grinding. This was considered by radcon to be an effective engineering control based on testing that demonstrated its effectiveness. The apparent skepticism of the workers to believe they were safe without respirators may have been indicative of a lack of training or education in the use of engineering controls. The in-spectors discussed this possibility with radcon management. The licensee stated they felt radcon's use of engineering controls in lieu of respirators was an altogether better approach to performing a job and that workers j
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should comply with radcon decisions in these matters. The inspectors had no further questions on this issue.
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During this report period, the licensee informed the resident inspectors of the following events:
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During routine surveys performed of material in dumpsters located outside the RCA, a bag of slightly contaminated wet rags was identified. The bag was removed and properly disposed o A carpenter's shirt became slightly contaminated from contamination contained on scaffolding poles he was carrying on his shoulde This was identified when he was leaving the protected area. The contamination reportedly leached out of the poles which had previously been used in the drywel A radcon technician set off a PCM-1 frisker when exiting the RC A more detailed frisk identified the source of the radiation as five contaminated one dollar bills he allegedly received during a transaction with a local bank. Proper authorities were notified and a NRC Region I evaluation ensue Man rem exposure for the year is near the 2000 man rem point. The original estimate for the year was 1000 man re . Hydraulic Control Units (HCOs) - Tagout Discrepancy At the same time during this report period, two unique activities involving manipulation of HCU valves were in progress. The first of these was fuel loading and.the other was repair of the HCU 101 and 102 valves (as discussed in paragraph 4 above). During a routine tour of the plant, the inspectors noticed some unattached tags for valves associated with one HCU laying on a piece of equipment. The inspectors subsequently questioned the control room operators as to why the tags were loose if they were not in use. This questioning determined that the HCUs were tagged out as part of Station Procedure 205.7, Control Cell Loading, and steps in this procedure speci-fically required temporary removal of tags to permit valve positionin The valves on the HCU for which the loose tags were found had undergone positioning the previous day. The tags were removed prior to valve posi-tioning but were not replaced because problems were encountered and the step in the 205.7 procedure to replace the tags was not reached.
( Upon further investigation, it was determined that tagouts of the 137 l
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HCUs for 101 and 102 valve rework were piggy-backed on the tagouts for the HCUs which were accomplished and controlled by the 205.7 procedur This series of events resulted in bypassing Station Procedure 108, Equipment Control, which is the station procedure designed to implement and control tagouts. The inspectors expressed a concern to the licensee l regarding the failure to properly tagout the HCUs in accordance with the station tagout procedure. The licensee responded to this concern by initiating Procedure 108 tagouts for all the HCUs to cover the 101 and 102 valve work and piggy-backed the 205.7 work onto these Procedure 108 tagout The inspectors considered this appropriate 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 properly locked or guarded and that access control was in accordance with the Security Pla No inspector concerns were identifie . Independent Inspection During routine tours of the plant, the inspectors observed on several occasions that the temperature in the 480V room was in excess of 100 The inspectors expressed their concern to the licensee that this elevated temperature could result in problems with the electrical equipment in the room at some later time. The licensee was concerned about the temperature but, du.e to major modifications to the HVAC in the room and the warm summer weather, were unable to take any effective steps to significantly decrease the temperatur Performance of equipment in the 480V room will be monitored by the inspectors to ensure no heat damage was sustaine . Training During this report period, the licensee completed the final steps in their efforts to gain INPO accreditation of 10 training programs. They were informed their efforts were successful and they are now the fourth power plant in the country to have achieved this accomplishmen . 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 inspectio The licensee stated that, of the subjects discussed at the exit interview, no proprietary information was included.
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