IR 05000219/1986034

Insp Rept 50-219/86-34 on 861006-1116.No Violations Noted. Major Areas Inspected:Outage Mgt,Mods,Radiation Control, Security,Housekeeping & Sys Pressure Testing

ML20215D686
Person / Time
Site:	Oyster Creek
Issue date:	12/11/1986
From:	Conte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20215D684	List: IR 05000219/1986034 ML20215D682
References
50-219-86-34, IEB-80-08, IEB-80-8, NUDOCS 8612160453
Download: ML20215D686 (12)

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t U. S. NUCLEAR REGULATORY COMMISSION j REGION I Report N /86-34

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Docket N License N DRP-16 ~ Priority --

Category C

, Licensee: GPU Nuclear Corporation 1 Upper Pond Road Parsip'pany, New Jersey 07054 Facility Name: Oyster Creek Nuclear Generating Station Inspection At: Forked River, New Jersey Inspection Conducted: October 6 - November 16, 1986 i Participating Inspectors: W. H. Bateman J. F. Wechselberger W. H. Baunack P. C. Wen A. E. Finkel Approved by: [CI /MNI/I R. Conte, Chief, Reactor Projects Section IA .

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Inspection Summary:

Routine inspections were conducted by the resident and Region based inspectors (190 hours0.0022 days <br />0.0528 hours <br />3.141534e-4 weeks <br />7.2295e-5 months <br />) of activities in progress including outage management, modifications, radiation control, security, housekeeping, and system pressure testing. The inspectors also made tours of the plant, followed up various events, reviewed l the completion status of Bulletin 80-08, investigated the recirculation system l pump trip system, and further investigated the cause of failed fue Results:

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No violations were identifie Inspection of the cause of failed fuel will be

completed in a subsequent inspection. The recirculation pump trip inspection,

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a Region I initiative, was completed. The 11R outage continued beyond its originally planned 6-month duration with restart anticipated in late November 198 PDR ADOCK 05000219 .

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DETAILS

, Investigation Into Cycle 10 Fuel Failures 1.1 Cycle 10 Fuel Failure Meeting On October 9, 1986 a meeting was held with the licensee to discuss the causes of the fuel failures and the licensee's corrective action The results of this meeting are summarized belo During the current 11R refueling outage, the licensee identified 47 failed fuel assemblies out of the 536 fuel assemblies sipped. All failed fuel assemblies were Exxon type VB fuel: 1 failed assembly was loaded at the beginning of Cycle 10 (80C-10), 34 failed assemblies were loaded at 80C-9, and 12 failed assemblies were loaded at BOC- Based on the available plant operating data, the licensee attributed the cause of the majority of these fuel failures to be a Pellet-Clad-Interaction (PCI) which caused cracks in the clad and allowed leakage of fission products into the reactor coolant syste The Cycle 10 operation was from November 1984 through April 198 In January 1985, a large offgas activity increase (from 45,000 micro ci/sec to 92,000 micro ci/sec) was noted. A review of the failed fuel locations, the control rod manipulations (A-1 Group 14 and A-1 Group 9) and the associated power distribution changes performed dur-ing this period, indicated that the preconditioning envelope recom-mendations had been exceeded. The fact that the maximum allowable nodal powers as established by the fuel vendor's precondition envelope were exceeded is related to some problems with the Power Shape Monitor-

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ing System (PSMS). This is further described in Section From March to mid-December 1985, the offgas activity increased at a

fairly uniform rate to approximately 110,000 micro ci/sec. This in-dicated that some fuel failure existed during this perio In mid-December 1985, the offgas activity sharply increased to 240,000 micro ci/sec. The fuel clad integrity further deteriorated during this perio Fuel failure related to this sharp increase in offgas activity was attributed to plant startup activities on December 18, 1985 when rod group 17 was pulled during high power operation. The subsequent large increase in recirculation flow and, thus, nodal power inadvertently resulted in exceeding the precondi-tioning recommendations. The safety analysis performed to support Cycle 10 operation was based on the GE supplied rod line which i required more manipulation at high power to obtain and maintain the l target rod pattern. However, the plant procedures, specifically i

Procedure 202.1, " Plant Operation," and Procedure 1001.22, " Power Distribution Control During Power Operation," did not provide ade-quate guidance on the limit of ramp rate and maximum recirculation flow increase.

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1.2 PSMS Problems The licensee used PSMS to monitor and predict the power distribution during Cycle 10 operation. Given the plant operating conditions, such as core thermal power, core pressure, core flow, control rod positions, feedwater flow, and feedwater temperature, the PSMS program calculates the margin to the PCI envelope and Technical Specification required parameters such as MCPR, MLHGR, and MAPLHG The accuracy of this calculation is periodically verified by the traversing incore probe (TIP). Various provisions are available to fine tune the model and perform TIP/LPRM calibrations. When there is a significant discrepancy between the predicted (by PSMS) and measured values (by TIP), an LPRM feedback option is availabl This option allows the measured LPRM readings to be included in the calculatio A software error in the PSMS program resulted in the nodal power exceeding the recommended PCI envelope limits during the beginning of Cycle 10 operation. During January 1985 plant operation, when measured and predicted flux values showed an unusually large discrepancy, the LPRM feedback option was turned on. However, this option did not function properly. A software error in the PSMS subroutine TRIGGER prevented the LPRM feedback option from being engaged when called for by the program. Although the option did not function, the display gave the user false indication that the option was being executed. Thus for some time the core engineer was misled by the erroneous PSMS indicatio It was not until later that the error in the software was identified and corrected. When the core engineer realized that the plant was approaching the MAPLHGR limit, they quickly reduced power by inserting control rods. This abrupt rod manipulation shifted the flux peak to a higher position and did not allow proper preconditioning of the new flux peak area and resulted in exceeding the recommended PCI envelope limit The Cycle 10 reload was the first reload cycle utilizing mixed vendor fuel, i.e., GE P8X8R and Exxon Type VB fuel. The PSMS requires basic inputs to the code such as nodal model normalization constants. These constants were subjected to change after actual cycle operating data became available. It appeared that, because of the mixed vendor core, large uncertainties existed in the initial set or normalization constants, as used in the beginning of Cycle operation. This coupled with the software errors in TRIGGER subroutine described above, caused the fuel assembly nodal power to exceed the recommended preconditioning limit Traditionally, Preconditioning Interim Operating Management Recommendations (PCIOMR) is a fuel vendor recommended practice to preclude PCI fuel failur It is not a TS related surveillance and, thus received less scrutin PSMS Revision 1 was used for most of the time during Cycle 10 operation. The type of information displayed for the core engineer's use was insufficient to adequately

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monitor the PCIOM Specifically, the calculation was performed on a pointwise basis, from one power level to the next power level; no ramp rate calculation was include PSMS Revision 2 corrected these deficiencies, however, Revision 2 was not implemented until the end of Cycle 1 .3 Licensee Corrective Actions The licensee preliminary plans as discussed in the October 9, 1986 meeting are as follows:

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Implement a formal fuel performance monitoring progra Trend performance of non-failed GE and Exxon fuel which were previously located at the symmetric locations of the failed fue Revise plant Procedures 202.1 and 1001.22 to provide a more clear guidance on the PCIOMR subjec Enhance PCIOMR training for Core Engineering and Operations staf Improve predictive capability of PSMS model to include consequence predictions of rod movements and Xenon effect The inspector will follow up the licensee's corrective actions.

l Recirculation Pump Trip (RPT) System A special inspection was performed to determine the details of the RPT feature that was installed by the licensee as a result of NRC concerns of an anticipated transient without a scram (ATWS) event. The requirement for the trip was specified in 10 CFR 50.62. The following paragraphs detail the inspection result .1 Design The Oyster Creek RPT is an energize-to-operate system with logic arranged so that two out of two taken once will trip the GE 4160 volt breaker ( AM-4.16-250-6). The 4160 volt breaker has a dual trip coil for the ATWS signals. The trip coil circuits are powered from the 125 VDC safety related power source.

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The pressure and level sensors (Barksdale Fressure Switch and Static-0-Ring differential pressure switch) are environmentally qualifie The logic and control for the RPT can be tested on line. The breakers are tested and serviced when the reactor is off line or during a refueling cycle. The selection of trip set points, procedures, instructions and personnel training are such that RPT inadvertent actuations should be minima The facility station procedure, EMG-3200.02, "RPV Control Level,"

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provides the necessary guidance to the operators in the event the recirculation pump fails to trip on the high pressure or low-low water level trip signal The emergency operating procedure instructs the operator to manually trip the recirculation pump The transients for the tripping of the recirculating pumps are analyzed in the facility Final Safety Analysis Report (FSAR). The consequences of these transients are well within the limiting transient analysis in the FSA (Note: the licensee does not have a PRA or Reliability No. for this system.)

The reactor protection trip system at Oyster Creek is consistent with applicable requirements of 10 CFR 50.62 (ATWS Rule). This design and operating procedures are based on guidance developed by General Electric and submitted to the NR .2 GE 4160 Volt Breakers (AM - 4.16-250-6)

The breaker that provides power to the Recirculating pump motors is i

a GE magna blast 4160 breaker. This breaker has a dual ATWS coil which is activated from the low-low water level or high pressure ATWS signal. The licensee has no history of failures with these breaker A review of the maintenance history cards for these breakers verified that no major failures of these breakers have occurred at this sit The five RPT 4160 volt breakers have been rebuilt by the General

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Electric Company over the last five years.

i 2.3 Surveillance The RPT surveillance testing requirements are listed in the licensee's station Procedure No. 116, " Surveillance Test Program." The system testing is performed once every refueling cycle while the surveillance testing of the instrumentation and logic components is performed on a quarterly basis. There have been no RPT failures of sensors or breakers in this system to date.

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2.4 Maintenance The licensee has a formal maintenance program which includes both corrective and preventive maintenance activitie This program is defined in Station Procedure No. 116, " Surveillance Test Program,"

and specific component procedures such as Station Procedure N .4.001, " Recirculation Pumps Trip Circuity Test." The component history is maintained on maintenance component test file card This data will be part of the data bank that will be used for trending program when it is operationa The component procedures have test data sheets which when completed and signed are located in the data file system at this site. This data plus the component history cards maintained by the maintenance organization, will be part of the data source that will be used in the trending program data bank .5 Reliability The licensec has not performed a reliability analysis of the RPT system nor have they performed a PRA of this syste The breakers (4160 volt) have redundant trip coils. The RPT component history to date indicates that they have had no failure in this syste .6 Quality Assurance A quality assurance program in conformance with the requirements of

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10 CFR 50, Appendix B, was applied to the RPT design and components from the sensors to the input of the coils of the 4160 volt breaker .7 Equipment Qualifications The sensors, instrumentation, relays, cables, and switches have been qualified to assure that the RPT will perform its functional operability under conditions relevant to the postulated ATWS. The instrumentation racks are seismically installed and meet the design requirements for this site locatio .8 Channel Independence i

All components downstream of the pressure and level sensing

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To maintain the reliability of the system, the licansee' has the components of the RPT system in the preventive and corrective maintenance program with the data going into the trending program ,

when it is operational. There is no enhancement of the RPT planned at this time by the license .10 Recorded Failure Rates for the RPT System

The licensee has not issued failure rates nor do they have a Probabilistic Safety Study for the RPT syste .11 Increasing Reliability *

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There have been no design changes issued to increase the reliability '

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s 3. Follow Up of IE Bulletin 80-08, Examination of Containment Liner s Penetration Welds . . 1

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Backgrcund information regarding concerns that' arose during NRC inspection of licensee action to address this Bullettr. appears in NRC Inspection Report 85-29. The Bulletin was left open pending volumetric inspection of field welds in Isolation Condenser system un,Wnrent ,

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penetrations X-SA and X-5B and a shop weld in Liquid Poison systam containment penetration X-6. During this report period, the NRC inspector questioned the licensee regarding.the status of the volumetric inspection of the Isolation Condenser penetration welds because of concerns involving the potential for overstressing penetration welds during a hypothetical rupture of the process pipe in the penetratio The inspector determined that a NDE request had been initiated in May 1986 but had not been acted on. Following discussions between the NRC and the licensee, scaffolding was erected to the "t'wo Isolation Condenser '

condensate return penetrations X-SA and X-58, insulation was removed, and weids FW 5567A and FW 5575A were ultrasonically inspected. The inspection results were reviewed and approved by Tech Function '

This Bulletin will remain open until the Liquid Poison containment penetration shop weld is volumetrically inspecte . Licensee Action on Previous Inspection Findings (Closed) Inspector Follow-up Item (219/86-29-01): Review results of methyl iodine removal efficiency of charcoal in Standby Gas _ Treatment System B The results of the test indicated a methyl iodine removal efficiency of 96%. The Tech Spec acceptance criteria is equal to or greater than 90%.

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(0 pen) Unresolved Item (219/86-24-01): Core Spray System I Full Flow Test Valve V-20-27 <

Inspection Reports 86-21 and 86-24 discussed the failure of V-20-27 during a routina surveillance tes In discussions with the licensee, they agreed to determine the cause of the motor operator failure, who is responsible to review and approve M0 VATS data before operability determination is made, and why significant changes have occurred in TDR 623, Torque Switch Settings, which provides a list of Torrey Pines Technology calculated thrust load The licensee determined the motor operator failure for V-20-27 to be the setting of the torque switch to 3 1/2, which allowed the motor to continue to drive the valve disc into its seat. This occurred as the motor was not able to generate sufficient torque to actuate the torque switch and deactivate the closing circuitry. The vendor motor operator technical manual does not recommend exceeding a torque switch setting of 3 and installs a block plate at this torque switch setting to prevent exceeding it. The repeatability of the torque switch is not reliable when set greater than three. This block plate must be physically removed to set the torque switch at 3 1/2. Presently the motor operator has been ,

sent to the vendor for failure analysis and adjustment of the spring pack to achieve a torque switch setting of 2 at the desired thrust value as specified by TDR 623. In the future to address this concern, the .

licensee will either adjust the spring pack or replace the standard spring pack with the appropriate spring pack to achieve the required torque switch setting and thrust value In addition, the licensee stated that for this direct replacement motor operator, the particular application required the motor operator to perform at greater than its design thrust value in comparison to the Torrey Pine requirements. When questioned if other motor operated valves may be operating in similar conditions, the licensee committed to reviewing all operators to identify those operating outside the manufacturer's design recommendations. These will then be evaluated before plant startup to ensure their operating

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condition is acceptable.

Regarding the change in the thrust values delineated in TDR 623, the licensee explained that a field questionnaire had been improperly

, evaluated and dispositioned which resulted in the erroneous TDR 623

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thrust values. Presently, TDR 623 thrust values for V-20-27 have been correctly implemented. The inspector will review TDR 623 thrust value changes in a future inspectio The licensee clarified the responsible organization for approving and dispositioning motor operated valve test data and is planning to make '

procedure revisions to 700.2.010, Motor Operated Valve Removal Installation or Inspection (Elect), to reflect this. The procedure revision will clarify motor operated valve acceptance criteria with regard to block plate position and torque switch settings and will formally require Plant Engineering acceptance of deviations from this criteri .-.

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This unresolved item will remain open pending the determination if other motor operated valves in the plant are operating outside the manufacturer's design recommendations and implementation of the revised procedure. Open Item 86-21-03, is redundant to this item and is therefore closed for record purpose . Pressure Testing of Recirculation System Piping Weld Overlays As a result of NDE performed on Recirculation System piping welds, the licensee decided to weld overlay welds NG-C-17 and NG-C-23 in the 'C'

recirc loop. Post weld NDE inspection of both welds disclosed rejectable indications. Rework of these indications continued past the period in time when the Tech Spec and ASME Section XI Code required system pressure test was performed. The NRC in:pectors questioned the licensee as to when post-weld repair pressure test of the weld overlays would be performed. The licensee's response was that neither the Tech Specs nor the ASME Code required a pressure test of weld overlays. The resident inspectors disagreed with this interpretation and initiated further discussion of the question between NRC Licensing and the licensee. The discussions revolved around the fact that the ASME Codes do not address weld overlays and, therefore, cannot be used as a reference to determine test requirements. The NRC does, however, recognize weld overlays as an acceptable method to temporarily repair weld joints that exhibit intergranular stress corrosion cracking. NRC guidance on weld overlays does not address pressure test requirements. This was apparently an oversight that NRC Licensing intends to address. To resolve the question at Oyster Creek, NRC Licensing required the licensee to inspect the weld overlays at normal operating pressure after satisfactory completion of all repairs. The need for a hydrostatic test at some higher pressure was not considered necessary. The licensee completed the weld repairs of the overlays and performed an inspection at system operating pressure. The results were satisfactory and the inspectors had no further question . Questionable Practices Involving Qualification of a Welder to Perform Not Important to Safety Welding The licensee informed the NRC inspectors of questionable practices identified during the welder qualification process of a contractor welde Schneider Power Corp. was contracted by the licensee to perform miscellaneous work on "not important to safety" heating, ventilating, and air conditioning system Some of the work involved welding. Schneider transferred a qualified welder from another power plant to Oyster Creek and hired a new welder locally who they had to qualify. The welding code involved was AWS D1.1, Structural Welding. The questionable practice identified involved lack of any type of oversight or supervision of the locally hired welder during the qualification process. This was brought to light when a contractor foreman claimed he saw the qualified welder welding on the test coupons of the welder undergoing qualification. The onsite Schneicer manager could not confirm or deny the claim because he failed to meet the intent of the AWS Code to ensure the qualification

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process was properly carried out. Specifically, he failed to control the qualification process in that there was no oversight to ensure tne new r

welder properly welded his test coupon When the licrasee learned of this incident, they informed the contractor's home office who, in turn, proceeded to investigate the incident. The in- -

vestigation resulted in the contractor discharging both welders, although there was no conclusive proof of wrongdoing on the part of either welder.

, Additionally, the contractor committed to control the welder qualification process for all future welder qualification activitie The NRC inspectors were concerned about this disregard for control of welder qualification by the contractor because of the transferability of the qualification. In particular, if a welder had been improperly quali-fied by Schneider at Oyster Creek, he could then be transferred by Schneider to another site as a qualified welder. At Oyster Creek the improper quali-fication would have impacted only "not important to safety" work, but at another site, could impact "important to safety" work. The action taken to discharge the welders precluded this problem. The inspectors had no additional concern . Radiation Protection During entry to and exit from the RCA, the inspectors verified that proper warning signs were posted, personnel entering were wearing proper dosimetry, personnel and materials leaving were properly monitored for radioactive contamination, and monitoring instruments were functional and in calibration. Posted extended Radiation Work Permits (RWPs) and survey status boards were reviewed to verify that they were current and 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 An Unusual Event was declared at 1638 on October 7, 1986 when a contaminated worker was transported to Community Memorial Hospital. The worker had tripped and fallen while working at the bottom of the reactor seal cavity. He sustained multiple injuries and could not be fully decontaminated prior to leaving the site. The decontamination was completed at the hospital and the Unusual Event terminated approximately an hour and a half later at 181 On October 23, 1986 the licensee detected that an individual working in the reactor vessel seal cavity had inhaled Cobalt 60 (C0-60). This was detected when the individual set off the alarm on a PCM-1 frisker when leaving the RCA. A subsequent frisk using a RM-14 determined the indivi-dual read 50-60 cpm above background and was not externally contaminate He was given a whole body count at which time it was determined he had an uptake of CO-60. The amount was estimated at slightly greater than 200 nano curies. The individual had been properly protected with a powered air purifying respirator (PAPR) while working in the seal cavity and subsequent investigation determined the uptake occurred after he had left

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the area and was helping a fellow worker remove his protective clothing in the change area. The protective clothing was contaminated with CO-6 The individual passed the particle duri,ig a bowel movement within a day and a half, thereby minimizing his exposur . Hydraulic Control Unit (HCU) Valves EP 101 (Drive Insert Riser Isolation Valve) and EP 102 (Drive Withdrawal Riser Isolation Valve)

During this outage, the licensee has examined all HCU 101 and 102 valves for intergranular stress corrosion cracking in the wedge (valve disc) of the valves. After completing this work and vessel operational pressure test, the licensee detected bonnet gasket leaks on some of the valve This will require a freeze seal on the line to each valve to be repaire This is another example of a maintenance task being reworked prior to final acceptance by the plant. The licensee should evaluate rework items as part of their end of outage evaluation to determine root cause. The inspector discussed this with the licensee at the exit meetin . Reactor Coolant System (RCS) Operational Pressure Test During the post refueling operacional pressure test of the RCS, the licensee experienced leakage problems with the vessel head flange inner l 0-ring seal, 'A' recirculation pump flange seal, 'D' recirculation pump l inner seal, and 'E' recirculation pump shaft seal. The vessel flange k

0-ring inner seal leaked as a result of snsp rings, used to hold the 0-ring in place, dislodging and preventing the head flange from making

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metal to metal contact. The licensee removed the vessel head and replaced both vessel flange 0-ring seals. During a subsequent operational pressure test, the inner vessel 0 ring seal leaked agai Because of the recirculation pump seal failures during the Cycle 10 operating cycle, the licensee decided to replace 'D' and 'E'

recirculation pump seals. Upon completion of the seal replacement and the vessel operational system pressure test, the seals leaked as indicated above. The licensee replaced the 'D' recirculation pump seal and was about to complete reassembly of the pump when metal filings were discovered in the seal leakoff. This led to further pump work to determine the source of the metal filings, which was eventually determinad to be an anti-rotation pin that had sheared. The licensee as a result had to replace some of the pump internals, including the impeller, auxiliary impeller, and bearing housing. Apparently, the seal damage was caused by the spacer ring striking the bottom of the seal cartridge. The reassembly process was somewhat protracted as numerous assembly problems arose including the inability to obtain the proper lift on the auxiliary impeller and the pump impeller. The 'E' recirculation pump was also disassembled to verify the pump did not have the same problem as the 'D' recirculation pump. The licensee found that one anti-rotation pin had been dragged and could shear at a later date and that the bearing retainer / spacer ring anti-rotation pin had been wor The licensee repaired the anti-rotation pin locating it 180 degrees from the original position and replaced the bearing retainer, spacer ring and

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bearing. Work continued on the 'A' recirculation pump. The licensee will determine if the 'B' and 'C' recirculation pump seal and pump internals need to be inspected prior to plant startup. The inspectors will continue to follow the licensee's activities in this area and report subsequent findings in future inspection report . Observation of Physical Security During daily tours, the inspector 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 W operly locked or guarded and that access control was in accordance with the Security Pla The licensee reported a moderate loss of security on November 3, 198 The event involved a personnel error where a security guard failed to reset all vital barrier access points in the security computer after a problem with a vital barrier. All other security personnel responded appropriatel . Technical Specifications The licensee has committed to submit a Technical Specification Change Request (TSCR) to clarify Table 3.1.1 of the Oyster Creek Technical Specification by November 1987 in advance of the Cycle 12 refueling outage. Table 3.1.1 needs to be revised to clarify the action requirement for maintaining the reactor shutdown during rod time testin This will remain an open item pending the licensee TSCR submitta (219/86-34-01)

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1 Plant Engineering Meeting The resident inspectors met with the Plant Engineering Director to discuss Plant Engineering work assignments and Technical Functions tasking request The Director described the Operations and Maintenance (0 & M) programs that Plant Engineering performs. He characterized Plant Engineering work assign-l ments as comprising a larger number of functional tasks in comparison to

capital budget activities. He stated that Technical Functions work requests

do not request technical functions design work that is Plant Engineering's responsibility.

j 13. Exit Interview A summary of the results of the inspection activities performed during this report period were made at meetings with senior licensee management at the end of the inspection. The licensee stated that, of the subjects discussed at the exit interview, no proprietary information was included.