IR 05000219/1986021
| ML20215G607 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 09/30/1986 |
| From: | Blough A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20215G601 | List: |
| References | |
| 50-219-86-21, NUDOCS 8610210027 | |
| Download: ML20215G607 (12) | |
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U. S. Nuclear Regulatory Commission Region I Report N /219/86-21 Docket N License N DPR-16 Priority -- Category C Licensee: GPU Nuclear Corporation 100 Interpace Parkway Parsippany, New Jersey Facility Name: Oyster Creek Nuclear Generating Station Inspection at: Forked River, New Jersey Inspection Conducted: July 7 - August 17, 1986
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Participating Inspectors: W. H. Bateman, Senior Resident Inspector J. F. Wechselberger, Resident Inspector W. H. Baunack, Project Engineer Approved by:
b A. R. Blough, Chief Date Reactor Projects Section IA _
Inspection Summary: -
Routine inspections were conducted by the resident inspectors and a Region based inspector,(258 hours0.00299 days <br />0.0717 hours <br />4.265873e-4 weeks <br />9.8169e-5 months <br />) of activities in progress including outage management, maintenance, modifications, QC inspection activities,-
surveillance, operator modification training, radiation control, physical security, and housekeeping. The inspectors followed up on cutage problems including administrative overexposures, storage of high level radwaste, security badging concerns and snubber problem Results One violation was identified and involved the inadequate radiation surveys which led to radiation exposures above local administrative limits (with within 10 CFR 20 limits) to workers performing maintenance underneath the reactor vessel. Inspector concerns regarding the proper handling of security badges and snubber problems were discussed with the license kDR 2 0027 861009 G DOCK 05000219 PDR ,
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DETAILS
' Operator Training Associated with Facility Modifications Operator and senior operator training to assure operator cognizance of facility modifications is required by 10 CFR Part 55. During this inspec-tion a review was conducted to determine what licensee controls are in place to assure that this required training is being provided for the mod-ifications which are being installed during this outage. Formal controls to assure that required modification training is provided are contained in Station Procedure No. 124, Plant Modification Control. However, discus-sions with training department personnel indicate that additional, infor-mal practices are being utilized at management's initiative to assure that the training department is aware of all modification Although limited formal requirements exist which assure that the training department is made aware of all the modifications which are being made, the informal effort by the training modification coordinator appears to provide assurance that adequate training on modifications will be provid-ed. The effectiveness of the required operator training on modifications
.will be reviewed prior to plant startup from the current outag . Storage of Radioacti've Trash in the Control Rod' Drive Rebuild Room On 7/30/86, the resident inspector made a tour of the control rod drive (CRD) rebuild room in the reactor building. This room is used to refur-bish the control rod. drive mechanisms removed from the reactor and to store the mechanisms prior to their reinstallation in the reactor vesse ~As a result of this rebuild work, the room has been designated a locked high radiation area and, depending upon work activity, has been classified as a high contamination are During the inspection tour, the resident detected a number of radioective trash bags reading 3CO-500 mrem /hr in the " cold storage area" of the CRD rebuild room. The inspector discussed his concern regarding the storage of radioactive trash in the CRD room with the Radiological Control Field Operations manager. This licensee manager agreed to investigate this mat-ter. At the time, CRD rebuild work activities were still being carried out in the roo On 8/4/86 the licensee commenced a cleanup of the CRD rebuild room and removed the radioactive trash to tne Old Radwaste building (ORW) for prop-er disposal / handling. Licensee records indicate that radioactive trash ~
was removed on 7/26 and again on 8/4. No radioactive trash was removed in the interim, although trash is supposed to be removed on a daily basis. A final cleanup of the CRD rebuild room commenced on 8/4 for a week. During the period 7/26-7/31, the contractor was rebuilding the remaining eleven spare CRDs. In addition, the licensee uses the CRD rebuild room to clean CRD system filters and to store these filters prior to reus Some old
CRD system filters had been allowed to accumulate that were no longer use The licensee removed these filters to ORW for disposa . - _ -.
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The ALARA review for the CRD rebuild maintenance recommended that the 55 gallon drum used as temporary storage of high level waste be removed from the CRD room when general area radiation around the 55 gallon drum is 3 times the general area background of the CRD room. A survey completed on 7/30/86 of the CRD room indicated a contact reading of 6000 mr/hr gamma dose rate on the lead (CRD filter) barrel. The survey did not' indicate a general area background in the CRD rebuild room, but the general area sur-veys ranged from 2-200 mr/hr gamma dose rate. Clearly, the contents of the lead (CRD filter) barrel should have been removed from the CRD rebuild room. The licensee should review the adequacy of their housekeeping pro-cedure or other procedure that controls these activities to ensure that radioactive material and trash is disposed of in an efficient and timely manner with proper consideration given for ALARA. This issue will remain an unresolved item pend.ing clarification of licensee procedures to ensure proper removal of radioactive material from in plant work areas (86-21-04).
In response to the concerns addressed above, the licensee on 8/4/86 com-menced a thorough cleanup effort of the CRD rebuild room and in addition halted all work activities in the drywell for a period of 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br /> so that a proper cleanup of the drywell could be conducted. The licensee also initiated a program to monitor drywell work for cleanup concerns.- 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
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radioactive contamination, and monitoring instruments were functional and in calibration. Posted extended Radiation Work Permits (RWPs) and survey status boards were reviewed to verify that they were current and accurat The inspector observed activities in the RCA to verify that personnel com-plied with the requirements of applicable RWPs and that workers were aware of the radiological conditions in the are The licensee reported that an individual, while working underneath the reactor vessel, exceeded his Oyster Creek administrative' exposure limit The individual was involved in the control rod drive (CRD) maintenance activity underneath the vessel below the CRD maintenance platform. As a result of their ihitial radiation surveys, the licensee determined the reactor vessel to be the highest radiation source for the individuals working on the platform as well as the individual working underneath the CRD maintenance platform. This survey dictated that the licensee place dosimetry on the workers' heads, as the highest radiation-field emanated from the reactor vessel. This head mounted dosimetry was intended to pro-vide the whole body exposure readings for the workers' exposure record <-
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The CRD maintenance werk commenced on 6/28/86 and was stopped on 7/3/8 During this time period, the highest radiation field for the worker below the CRD maintenance platform shifted from the head area to the knee are This was discovered by the radiological control technician (RCT) who placed a self reading dosimeter (SRD) on the worker's head and knee for an entry underneath the reactor vessel below the CRD platform. The SRD for the knee read approximately two times the SRD reading for the head indi-cating that a higher radiation field was emanating from the floor area than from the overhead for the worker below the platform. This was con-trary to what the licensee had expected. For the two workers on the plat-form, the highest radiation field was still from the reactor vessel. As a result the licensee immediately stopped the job and recalculated the work-ers' exposure history records based on the SRD knee to head ratio of The licensee then developed the workers thermoluminescent device (TLD) and applied the SRD correction factor to the TLD readings to determine the workers whole body exposure. This resulted in one worker exceeding his authorized administrative quarterly limit (whole body exposure) of 2000 millirem (mrem) by approximately 300 mre The resident inspector reviewed this event with the licensee and also in-spected the radiological control survey records for the CRD maintenance
. activities. The radiological work permit (RWP) was written based on a survey conducted on 6/14/86. Actual work commenced on the CRDs on 6/28/86 and was' stopped on 7/3/86. During the period prior to commencement of the work activities, the licensee conducted daily surveys under the vessel in the CRD room. After~ work started on the CRDs, the licensee conducted sur-veys of the CRD mechanism as the mechanisms were removed from the vessel to detect any abnormally high radiation spots on the mechanisms. They did not, however, perforn any surveys in the CRD room to detect the changing radiation field. The radiation field changed during the CRD maintenance activities due to radioactive particle deposition on the concrete floor of the room. Subsequent radiological control surveys taken from the floor of the CRD room under the reactor vessel at the approximate elevations of head, waist, knee and the floor indicated the highest radiation levels to be located at the floor elevation. The licensee failed to perform neces-sary and reasonable survey's as required by 10 CFR 20.201. The surveys made during the period failed to identify changes in the uniformity of the radiation exposure to the individuals working under the reactor vesse As a result, exposure received by individuals working under the reactor vessel was underestimated by a factor of two. This is a violation of 10 CFR 20.201 (86-21-01).
On 8/8/86, the licensee discovered a similar problem with the maintenance action to replace the "D" recirculation pump sea In this case, the in-dividual worker exceeded his administrative whole body exposure limit of 1000 mrem by approximately 300 mrem. Again, a difference in radiation fields was detected by mounting SRDs on a worker's knee and chest are Upon the worker's exit from the drywell, a disparity was noted between the two SRDs. The licensee stopped the job until they could adequately assess the working area. The licensee applied correction factors based en the ratio of SRD readings to the recorded whole body exposure to determine the
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actual exposure for each worker. The resident inspector discussed this event with the licensee, expressing concerns regarding the ALARA review process and proper performance and interpretation of radiation survey The licensee was already conducting a programmatic review of their ALARA review process and was planning to discuss this event with all the RCT In addition, all the Group Radiological Control Shift Supervisors (GRCSS)
were interviewed and counseled on proper drywell tour inspections and the radiological control survey procedure is being revised to ensure that a radiological engineer discusses the job scope and activities with the job supervisor prior to commencement of work activities. The licensee's cor-rective action will be reviewed and a complete review of this event will be conducted in a. future inspection report by a regional based health physics inspector. (See NRC Inspection Report 50-219/86-28.)
4. Observation af_ Physical Security During daily tours, the inspectors verified access controls were in accor-dance with the. Security Plan, security posts were properly manned, pro-tected 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 On 7/29/86 the facility experienced a severa thunderstorm which caused a moderate loss of security. This event was properly reported to the NR The inspector reviewed the event and the licensee actions in response to the loss of security and found the licensee response to be adequat During a tour on 7/30/86, the inspector noted several deficiencies in the protected area barrier. This was reported to the security force and the deficiencies were promptly corrected. The security supervisor stated he would ensure the remainder of the barrier was closely examined for similar deficiencies and would ensure routine surveillance would promptly identify similar deficiencies in the futur The inspector had no further concern Upon exiting the facility through the North Gate during shift change on 7/31/86, a large unorganized array of security badges was noted on the security desk top. The inspector questioned the security personnel re-garding the control of security badges during the high personnel traffic time of shift change. At this time there were only two guards present attempting to distribute badges to the oncoming shift personnel and to refile the off going shift security badges. Concerned about potential badge control problems, the inspectors observed the following morning shift change activities at the North Gate on 8/1/86. During the shift change there were 4 to 5 guards present benind the security desk refiling and distributing security badges and approximately the same number of se-curity personnel monitoring the oncoming shift personnel. There was no apparent badge control problem evident as the number of security guards was adequate to handle the task. The inspector discussed his concerns
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with the security supervisor and det' ermined that although the number of misplaced badges from shift to shift may be high, the number of lost secu-rity badges on an annual basis is relatively low. The inspector deter-mined that the misplaced badges were properly handled by the security force. In addition, the security supervisor had instituted plans to more adequately control the large number of. people that-ingress and egress the North Gate during an outage period shift change. Further observations of security badge control during the report period did not reveal any badge control problems. Apparently, the licensee corrective action was effec-tive in controlling security badges during outage shift changes. The in-spector had no further concern . Licensee Event Report (LER) Review L
(0 pen) 86-16; Fuel Clad Failures The licensee reported, as a result of fuel sipping operations, that for-ty-seven fuel bundles had cladding failures. The licensee's report also indicated that a supplemental LER would be submitted by-11/15/86 after restart from the present outage. The failures were discussed with the licensee to determine to what extent the failure mechanism would be de-fined prior to restart and any preliminary findings. The licensee is presently evaluating pellet to clad interaction (PCI) and defective clad-
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ding as possible failure mechanisms. An internal report is being devel-oped by the core engineering group onsite in conjunction with the corporate fuels group to provide preliminary results of their investiga-tion and to define the failure mechanism with some degree of confidenc This report will be reviewed by the inspector when available in early Sep-tember. The failed fuel bundles were removed from the usuable fuel inventor . Debris on Fuel Assemblies During this report period, a filter bag located in the spent fuel pool broke emptying its contents on to five fuel assemblies (LJJ165, UD8056, UD0075,UD0017,and_UD0050). Two of these fuel assemblies (LJJ165, UD8056) are designated to be reloaded into the reactor vessel for Cycle 11. The inspector questioned the licensee concernlng their plans for the fuel assemblies and reviewed video tapes showing the debris on the assem-blies. The debris appeared to consist of rags and small rubble-like material. The licensee plans to de-channel the assemblies and use a
" water pic" type device to flush out the internals of the fuel assemblie After the flushing process is complete, the assemblies will be video taped underwater from all angles to ensure that all foreign material is remove The remaining three assemblies will likewise be cleaned after refueling activities are complet .
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6 Feedwater Isolation Valve (V-2-36) Repair The inspector discussed the results of the recent V-2-36 repa'ir effort with the licensee. The valve,-V-2-36, is a manual feedwater isolation valve inside the drywell that isolates the feedwater system just prior to entering the reactor vessel. This valve was repaired this outage after having undergone several repair attempts last outage and numerous injec-tions with leak repair material during the Cycle 10 operating perio After being overhauled during this outage, the valve's pressure seal leaked from the static pressure in the reactor vessel. As a result, the '
licensee chose to drain down the vessel to below the feedwater sparger and attempt to repair the valve again. At the same time the licensee was mak-ing repair plans, they purchased a replacement valve if the repair activi-
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ties were unsuccessfu '
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The licensee determined the valve leaked as a result of poor maintenance practice by the contractor who performed the actual work on V-2-36. A spacer ring designed to provide a better saal in the seal area ha'd been dislocated and caught on a lip of the bonnet. This prevented the bonnet from snugging up and providing a proper seal. This was confirmed by com-paring the torque measurement readings-that were approximately 500 ft.-lbs. on one side of the valve with the other side's torque measure-ments reading somewhat less. The licensee modified the bonnet to remove the bonnet lip that caught the spacer ring to prevent future problem The valve manufacturer was present onsite during the repair activities for consultatio The valve did not leak upon reflood of the reactor vessel. The effec-tiveness of the repair will be demonstrated during the reactor vessel hydrostatic pressure test during restar . Outage Activities The inspectors reviewed the following outage activities to assess the sig-nificance of the .particular event and determine the appropriateness of the licensee's corrective-action ' Safeguard System Actuations On July 27, 1986 the facility experienced severe thunderstorms which caused the Standby Gas Treatment System (SBGTS) to initiate and the primary and secondary containment to isolate several times. Voltage fluctuations caused by lightning strikes resulted in the automatic bus transfer (ABT) switch shifting from its selected power supply vital AC power panel 1(VACP-1) to its alternate supply (VMCC 1A2).
This caused a relay (6K37) to de-energerize and initiate SBGTS and isolate primary and secondary containment. The ABT is a break-before make design with a transfer time of sufficient duration to allow the relays to de-energize and actuate the safeguard system i
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The licensee evaluated the transients and found the plant response to be normal for the voltage fluctuations. The licensee had previously tasked Plant Engineering to evaluate the ABT transfer time, preven-tive maintenance, and condition to determine if the t.ransfer time is adequate for this applicatio Similar events had occurred in early June.
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Another event caused a SBGTS initiation as a result of a protection system fuse failure (6F7, 6F9). The fuse failure resulted from an electrical jumper installed in the control room panel 11F becoming unfastened and shorting across other terminals in the panel which caused the fuses to blow and SBGTS to initiate. The jumper had be-come dislodged by a worker who had accidentally bumped the jumpe The inspector reviewed this event with the licensee who stated a LER would be submitted on this event that would contain additional de-tails. This event will be followed up as part of LER closeout activitie B. HFA Relays Inspection Report 86-17 discussed the licensee revised completion schedule of IE Bulletin 84-02. In a letter dated July 30, 1986, the licensee stated, in part, that 11 normally de-energized nylon spool HFA relays with the upgraded GE Century Series relays would be re-placed prior to startup from the current outage. Subsequent to their letter, the licensee discovered two additional HFA relays which are normally de-energized and are not surveilled during plant operation and as a result would have to be replaced prior to startup. The licensee revised this commitment from 11 to 13 no nally de-energized HFA relay C. Recirculation System Intergranular Stress Corrosion Cracking (IGSCC)
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The licensee reported finding IGSCC indications in the "C" recircu-lation loop on welds NG-C-23, NG-C-17, and NG-C-9A. Weld.NG-C-9A is located on the suction _ side of "C" racirculation pump between the pump suction and the suction valve and exhibited a 2.2 inch long crack of 18% depth. NG-C-9A was dispositioned by fracture mechanics as acceptable for the next operating cycle. Weld NG-C-23 is located on the discharge piping from the "C" pump at the top of the elbow prior to entering the vessel and is t;eing weld overlaid. NG-C-23 had two indications of 1.5" length and 16% depth and 2.3" length and 55%
depth. NG-C-17 is also being weld overlaid and is the first weld past the discharge valve and had five indications of 3.2" length and 23% depth, 1.7" length and 18% depth, 2" length and 29% depth, 1" length and 14% depth, and 2.5" length a-d 27% depth. During this re-port period, the licensee completed induction heat stress improvement (IHSI) and subsequent NDE to establish new inservice inspection base-line data on 64 Recirculation system pipe welds. This completed the IHSI phase of the licensee's overall plan to combat IGSC .
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8 Full Scram During IRM Surveillance During an IRM surveillance, while the reactor was defueled, the fa-cility experienced a full scram. The licensee was testing one IRM channel in a trip condition when the scram occurred from a spiking IRM in the other channel. The licensee had recognized this possibil-ity as the IRM had exhibited this behavior prior to commencement of the surveillance, and, as a precaution, had planned to bypass the spiking IRM. In actuality, they had bypassed another IRM in the same channel, but not the spiking IRM. This occurred as a result of miss-ing IRM bypass switch labels. The labels had not yet been replaced after the painting of the control room bench board had been complet-ed. The licensee agreed to inspect all control room benchboards for proper labeling prior to restar E. Liouid Poison System Maintenance During the conduct of post maintenance testing on the Liquid Poison system, the. Liquid Poison pumps would not rotate. The licensee dis-covered that the starter located in the motor control center for the pumps was mistakenly reverse connected after recent maintenance. This also resulted in unexpected squibb continuity current fluctuation Upon proper connection of the starter, the Liquid Poison system was again tested with acceptable results. The apparent cause of the problem was maintenance personnel unf amiliarity with this particular starter configuratio F. Hydraulic Control Unit (HCU) Valves EP-101 and 102 Replacements The inspectors reviewed the licensee progress in examining Hancock control rod drive hydraulic control unit valves 101 and 10 The concern with these valves involves failure of the so called " ears" on the wedges as a result of intergranular stress corrosion cracking (IGSCC). The " ears" attach the wedge (valve disc) to the valve ste A break between the stem and the disc could cause the scram function of the associated rod to malfunction. General Electric Service In-formation Letter (SIL) 419 addresses these concerns and recommends corrective action. The licensee plans, in response to SIL 419 and as a result of their inspection efforts, to examine all HCU 101 and 102 valves for IGSCC. Thus far 38 EP-101 valves and 94 of the EP-102 valves have been examined with 2 and 31 failures respectively. In addition, the licensee reported one EP-102 wedge was cracked in piec-es and potentially could have prevented the rod scram function from occurring when required. The SIL also discusses the potential fail-ure of EP-112 valves which the licensee was not examining. Tr.e in-spectors verified that the installed 112 valves at Oyster Creek where not Hancock valves and did not have a similar wedge configuration susceptible to IGSC r
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m 9. Mechanical Snubbers Inside the Drywell Technical Specifications require that a functional' test of 10% of each type of snubber in use in the plant be performed at least once each refueling cycle. The licensee tested 10 of approximately 100 mechanical snubbers located in the drywell. Just prior to testing the snubbArs, Paul Munroe, a contractor hired to perform the snubber testing and write the test procedure, questioned GPUN regarding the conservative nature of por-tions of the acceptance criteria. As a result, Plant Materiel initiated a Field Questionnaire (FQ) to ask for more. latitude in the acceptance crite-ria. As a result of testing, it was determined 3 of 10 snubbers did not meet the original acceptance criteria of 1% of design rated load for the running drag test. The response to FQ-C044928, however, stated a mechani-cal snubber shall not be considered a failure if the drag is equal to or less than 5%, but that when the drag is found to be greater than 2% and equal to or less than 5%, the snubber shall be rebuilt or replacert. ~This action was taken in the case of one snubber who's running drag was approx-imately 4%. The two othe snubbers had running drag greater than 1% but less than 2% and were considered acceptable. Because the snubbers were not considered failures, the Tech Spec requirements to test an additional 10% of the snubbers should any of the first 10% fail was not implemente The NRC inspectors expressed concern as to why more comp uhensive accep-tance criteria were not established in the initial procedure and suggested that in the future test procedure acceptance criteria be realistically established prior to performance of the tes During inspector tours of the drywell, the inspectors noted that scaffold-
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ing was resting on two mechanical snubbers (NE-2-S3 and NE-2-S6) and that '
a strut rod associated with snubber ND-1-S2 was bent. These discrepancies were identified to the licensee who, in turn, took action to remove the scaffolding from the snubbers and functionally test the snubbers _to ensure operability. A MNCR was written to address the bent strut rod which was dispositioned "use as is." Subsequent to this, the licensee performed their own walk-through inspection of the drywell and identified scaffold-ing again resting on the same two snubbers. In response to this situation, a Quality Deficiency Report was issued, the scaffolding was again removed, ar.d the snubbers were again stroked. Licensee awareness of the sensitivity of mechanical snubbers increased as a result of these problems and this sensitivity was communicated to contractors performing work in the drywel The inspectors also pointed out to the licensee that there are snubbers in various locations that are more than likely being used as steps. The sug-gestion was made that action be taken to protect these snubbers. The li-censee stated they would investigate this concer In addition, a hanger in the Post Accident Sampling (PAS) system was sup-ported from the strut rod associated with snubber ND-10-52 in the drywel The inspector questioned the appropriateness of supporting a piping system from a snubber strut and what action the licensee was going to take to determine the snubber's operability. The licensee agreed to stroke test
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the snubber which tested satisfactorily. The_ licensee is investigating how the snubber strut came to be used as the attachment point for the PAS system hanger. The inspector will review the results of the licensee in-vestigation (86-21-02).
10. Secondary Containment Leak Rate Test The inspector observed. portions of the secondary containment leak rate test conducted on 8/7/86. The first test failed, achieving .21, inches of water vacuum whereas the criterion in Procedure 665.5.002, Secondary Con-tainment Leak Rate Test, requires .25 inches of water vacuum under calm wind conditions. The refueling operations work on the reactor building elevation 119' was appropriately stopped by the shift supervisor. . The '
licensee discovered .that a wooden plug in the overboard service water line
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in the. seal well had become dislodged, allowing air inleakage through an open pipe connection to the RBCCW heat exchangers. In_ addition, the licensee had run the. test with the reactor building railroad access inner doors open. After closing the open doors and replacing the wooden plug in
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the service water line, the test achieved .35 inches of water vacuum. A subsequent test run with the inner railroad access doors open yielded .30 inches of water vacuum. The inspector discussed the test results with the licensee and determined the results to be acceptabl . Core Spray System Valve Moteq 0perator Failure V-20-27 is a motor operated valve in the Core Spray system used to test the operability. of the. system by allowing Core Spray flow to discharge to the torus. The motor operator for V-20-27 overheated and failed during a routine surveillance test. The motor operator had just been replaced dur-ing this outage and had successfully passed the post maintenance testing requirement The inspector discussed the circumstances of this failure with the licensee. Apparently, while attempting.to close the valve from the con-trol room, insufficient torque was generated to trip the torque switch which allowed the motor to continue to drive the valve disc into the valve seat. At the end of this report pe'riod, the reason this occurred was not known and the cause was under investigation by Plant Engineering who had subcontracted the evaluation to the MOVATS Corporation. The inspectors will review this matter in a subsequent inspection. (219/86-21-03)
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_l 1 Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted by the licensee pur-suant to Technical Specification requirements were reviewed by the inspec-tors. This review included the following considerations: the report includes the information required to be reported to the NRC; planned cor-rective actions are adequate for resolution of identified problems; and the reported information is vali The following reports were reviewed:
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Monthly Operating Reports for May and June 1986
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Special Report,86-03 dated 7/10/86 regarding inadequate support of the. office building fire water supply riser pipe that serves, in part, the MG set' room, monitoring and control area, and cable spreading room sprinkler Special Report 86-04 dated 7/11/86 involving non-functio.nal fire bar-riers associated with 2 piping penetrations through the east wall of the control room ~.
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Special Report 86-05 dated 7/24/86 concerning 18 improperly sealed fire barrier penetration seals in the 4160V switchgear enclosure . Team Building Training Twenty-four corporate officers attended a special three day team building seminar conducted by a consultant. The licensee plans.to enroll approxi-mately 300 of their employees in the course, including some onsite manag-ers, as part of an overall program to continue to improve management performanc . NRC Bulletin 79-02 Update During this report period, the licensee supplied concrete anchor bolt ul-timate pullout load data for Phillips Red Head shell type anchor bolt The manufacturer's pullout values were based on 3500 psi concrete which is 500 psi greater than the design strength of Oyster Creek concrete. As a result these ultimate pullout values have to be reduced by taking the ratio of 3000 psi to 3500 psi and multiplying the result times the manu-facturer's value. When this calculation is performed and compared to the load testing performed on the anchor bolts during the 1979-80 effor.t by the licensee to address Bulletin 79-02, it is clear that the pull test loading exceeded the design load guaranteed by the vendor. 'For example, the ultimate pullout for a 5/8" diameter Phillips Rea Head shell type an-chor in 3000 psi concrete is 10,028 psi. Design strength to ensure a fac-tor of safety of 5 would be one fifth of this value or 2006 psi. GPUN load tested the 5/8" diameter anchors to 2340 psi during their 1979-80 -
test program. Testing to this value was equal to or greater than the de-sign value and, therefore, satisfied the Bulletin requirements. The com-pressive strength data for the concrete was not available for review during this report period and still remains an open issu . 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.