IR 05000219/1986012: Difference between revisions

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{{Adams
{{Adams
| number = ML20214F968
| number = ML20205E159
| issue date = 10/24/1986
| issue date = 07/22/1986
| title = Enforcement Conference Rept 50-219/86-12 on 860912.Major Items Discussed:Findings Detailed in Insp Rept 50-219/86-12 Re Inoperability of Four Snubbers Required by Tech Specs to Be Operable
| title = Insp Rept 50-219/86-12 on 860414-0601.Violation Noted:Pipe Support FP-008 Disassembled W/O Procedures to Control Rework & to Ensure Reinsp & Seismic Restraints FP-001 & FP-002 Welded to Nonseismic Floor Penetrations
| author name = Blough A
| author name = Blough A
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
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| license number =  
| license number =  
| contact person =  
| contact person =  
| document report number = 50-219-86-12-EC, NUDOCS 8611250507
| case reference number = TASK-1.A.1.3, TASK-TM
| package number = ML20214F928
| document report number = 50-219-86-12, IEB-79-02, IEB-79-14, IEB-79-2, NUDOCS 8608180257
| package number = ML20205E123
| document type = INSPECTION REPORT, NRC-GENERATED, INSPECTION REPORT, UTILITY, TEXT-INSPECTION & AUDIT & I&E CIRCULARS
| document type = INSPECTION REPORT, NRC-GENERATED, INSPECTION REPORT, UTILITY, TEXT-INSPECTION & AUDIT & I&E CIRCULARS
| page count = 3
| page count = 32
}}
}}


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U. S. Nuclear Regulatory Commission Region I Report N /219/86-12 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 and Parsippany, New Jersey Inspection Conducted: April 14 - June 1,1986 Participating Inspectors: W. H. Bateman, Senior Resident Inspector J. F. Wechselberger, Resident Inspector W. H. Baunack, Project Engineer Approved by:
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7 - 2.7 M A. R.(flough, Chief  Date Reactor Projects Section IA Inspection Summary:
Routine Inspections were conducted by the resident inspectors and a Region based inspector (393 hours) of activities in progress including outage management, maintenance, modifications, QC inspection activity, radiation control, physical security, housekeeping, defueling, fuel sipping, chemical decontamination of recirculation piping, and fire protection. The inspectors
, also reviewed licensee action on previous inspection findings, followed up Licensee Event Reports, and made routine tours of the facility. In addition, the inspectors visited the GPUN corporate offices to review the technical data associated with the licensee's inspection activities in 1979 and 1980 associated with NRC Bulletin 79-02. The inspectors also reviewed licensee control of overtime hours and followed up on various operational problems such as inadver-tent scram signals caused by IRM spiking and inadvertent starts of the Standby Gas Treatment Syste "
8608190257 860008 l PDR ADOCK 05000219 G  PDR
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Results:
Four violations were identified. Three were associated with a seismic upgrading of portions of the Spent Fuel Pool Cooling system as discussed in paragraphs 1.A, B, and C. The fourth involved failure of the licensee to recognize that three safety related snubbers in the Isolation Condenser system were inoperable, thereby, placing the plant in violation of Technical Specification Limiting Conditions for Operation as discussed in paragraph 2. Review of certain techni-cal data at Parsippany regarding previous anchor bolt inspections disclosed that the data had not been adequately reviewed by the licensee prior to taking credit for it meeting the requirements of Bulletin 79-0 Review of Licensee Event Reports (LERs) determined a problem exists regarding significant time delays in submitting supplemental LERs and implementing corrective actions.
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l DETAILS 1. Spent Fuel Pool Cooling (SFPC) System Seismic Upgrade - LER 83-26 i
Licensee Event Report.(LER) 83-26 stated the effects of the weight of lead shielding used on the SFPC heat exchangers would overstress the heat exchangers' foundation bolts during a seismic event. It also reported that the original portions of the SFPC piping were supported by dead weight hangers only and, therefore, the affected piping may not be Seismic Class 1 as stated in the Final Description and Safety Analysis Report (FDSAR). The licensee submitted a preliminary report of this issue on 12/20/83. This report stated the corrective actions, in part, would involve seismically upgrading the spent fuel pool outlet and return piping prior to plant startup from the 10R outage. LER 83-26 was formally updated on 2/7/84 and stated the upgrading of the piping would be delayed until prior to the 11R outage core offload. By letter dated 5/20/86 the >
licensee issued Revision 1 to LER 83-26 to, in part, refine their commit- <
ment to seismically upgrade the piping and heat exchangers prior to 11R ,
core offload. This refinement involved upgrading the pipe supports but not the heat exchanger supports. The rationale presented for not upgrad-ing the heat exchanger supports was based on ALARA concerns and the planned replacement of the SFPC heat exchangers during 11 A review of-the licensee correspondence indicates that the licensee changed their original corrective action commitment twice, i.e., once to delay it and once to modify it and delay a portion of it. Because Plant ,
Operations would not permit a major portion of the work involved with installing seismic supports to be done during plant operation, the bulk of it had to be done after plant shutdown prior to core offload. This seismic upgrade became an extremely important job during this report period because it was a NRC commitment that had been delayed once and modified once and, if not completed in a timely fashion, could delay core offload. Upon completion of the work associated with the modified seismic upgrade, the NRC inspector inspected a sample of the upgraded support These inspection activities identified three violations as follows: Hanger mark number BP-435A as detailed on GPUN drawing FP-008, Rev. 2, was found to be partially disassembled in that the U-bolt was not t installed in position. A review of work' package A15A-38685, Rev. O, i Spent Fuel Pool. Cooling System - Mechanical System Upgrade, indicated this support had been final inspected and accepted by QC, Further ,
L investigation into the discrepancy disclosed that craft personnel partially disassembled BP-435A after QC inspection to facilitate
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adjusting the piping in a restraint further downstream. This rework -
was not authorized or controlled. After subsequent questioning of .
;  involved Maintenance, Construction, and Facilities (MCF) personnel,
!  the inspector determined that, as long as a work package remains in
!  MCF, there are no procedural provisions to authorize and control
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rework. Had the system been turned over to Startup and Test or Plant
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Operations, the work would have been controlled by the "Short Form" l  proces .
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The failure of MCF and the Work Management System to proceduralize control of rework prior to turnover resulted in the partial dis-assembly of a newly installed seismic support after QC inspection and acceptanc This action invalidated the QC inspection. This is contrary to Criterion V of 10 CFR 50 Appendix B, and the Oyster Creek Operations quality assurance plan (QAP) section 3 which requires, in part, that activities affecting quality be prescribed by procedure This is a violation (219/86-12-01).
Subsequent to identification of this problem, MCF management issued a memorandum to all involved contractors stressing the policy that rework must be authorized. At the end of the report period, changes were being initiated to controlling procedures to make this a policy of the MCF Work Management Syste The inspector observed two seismic important to safety restraints each welded to a different existing floor penetration. GPUN drawings FP-001 and FP-002 detail the installations. Based on the assumption that the floor penetrations were not considered seismic, the inspec-tor questioned the licensee's rationale for attaching a seismic restraint to a non-seismic member to transfer the loading to the building structur Discussions with Technical Functions personnel responsible for the design confirmed the floor penetrations were not seismic and that the design was subcontracted to Associated Technologies, Incorporated (ATI). An explanation as to why the restraints were attached to the floor penetrations was not give Since ATI used the floor penetrations as a piece of supplementary steel to transfer loads to the building structure, it is evident they were not aware that they could not do this. ATI's lack of awareness can be attributed to lack of appropriate technical information in the contractual document procuring ATI's services. The failure of GPUN to assure ATI properly performed the subcontracted design work is contrary to the requirements of Criterion IV of 10 CFR 50 Appendix B and QAP section 6.4. This is a violatio (219/86-12-02)
It should be noted that neither GPUN nor ATI performed any calcu-
;  lations to demonstrate the floor penetrations were capable of l  transferring the imposed loads. The seismic calculations ended with the restraint design, i.e., upstream of the attachment weld to the floor penetration. Before the end of the report period, Tech l  Functions personnel stated the design standards would be clarified to address proper design of seismic supports, once completed the design standards would be made available to all contractors doing design work for GPUN involving Oyster Creek, and calculations would be performed to justify the use of the floor penetrations as seismic members.
I Since the two seismic supports discussed in paragraph 1.8 above were i  welded to the floor penetrations, the inspector reviewed the welding I
documentation associated with these welds and determined that the type of material the penetrations were made from was not known by l
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U. S. Nuclear Regulatory Commission Region I Docket N ,
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License N DPR-16 Licensee: GPU Nuclear Corporation 100 Interpace Parkway Parsippany, New Jersey Facility Name: Oyster Creek Nuclear Generating Station Meeting at: U. S. NRC Region I,' King of Prussia, Pennsylvania Meeting Date: September 12, 1986 Prepared By: W. H. Bateman, Senior Resident Inspector Oyster Creek Approved by:
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A. R. Blough,' Chief V4 Date Reactor Projects Section IA, DRP Meeting Summary:
 
An enforcement conference was held at NRC Region I on September 12, 1986, to discuss the findings detailed in Inspection Report 50-219/86-12 regarding the inoperability of four snubbers required by Technical Specifications to be operable. This report presents a brief summary of the topics discussed at the meetin The meeting was attended by NRC and GPUN management personnel and lasted approximately two hour kk kDO G
either Tech Functions, Special Processes'and Programs (SPP), or Q The GPUN Welding Manual (Procedure 6150-QAP-7220.01, Rev. 0-00)
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states in paragraph 4.2.4 that engineering documents and Weld Package Information Requests (WPIRs) must specify base material specification and grade for new and existing material. A review of the engineering documents and WPIRs disclosed that the existing material (floor penetrations) was never addressed. The inspector questioned SPP as to how they issued a weld package, specified a Welding Procedure Specifications, and issued filler metal without knowing the types of materials that were being joined. Representatives of SPP stated that this specific instance was an oversight and that normally they request base material information from Tech Functions if Tech Functions fails to specify the information, as happened in this cas A review of the Structural Weld Record Sheet associated with these welds indicated that QC had signed for acceptance of the base materials used in the weld. This signoff indicated, in part, that material traceability requirements had been met for the materials joine Because the existing base material was not known, one would question the intent of the QC signature. The inspector concluded there was a failure of (1) Tech Functions to supply existing base material information as required by procedures, (2) SPP to question Tech Functions regarding the base material prior to issuing the weld package, and (3) QC to recognize that the base material of the pene-trations to which the seismic supports were welded was not define These failures are contrary to the requirements of Criteria IX and X of 10 CFR 50 Appendix B and QAP, sections 6.4 and 6.12. This is a violation (219/86-12-03).
 
At the end of the report period, the licensee did not know the ma-terial type. A search of old drawings was performed in an attempt to identify original material requirements. The results indicated the floor penetrations should have been galvanized A36 steel. How-ever, an inspection of these penetrations led to the conclusion they were not made of A36 'as required by the original construction drawin The licensee plans to take a sample of the material and have it analyze Further, in reviewing the Structural Weld Record Sheet (SWRS) with SPP and QC, it became obvious the instructions for use of this document are confusing. The SWRS is Exhibit 6 in the GPUN Welding Manua The specific areas that require clarification are as follows:
(1) QC acceptance of material traceability on the SWRS when one line on the sheet may represent several different welds; (2) The often time inadequate space on the SWRS used to record the required information; (3) The use of a SWRS Attachment sheet;


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  (4) The requirements to list material traceability when welds
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are not listed individually on the SWRS; and (5) Proper method of QC signoff on SWRS when welds are not
listed individually, including requirement to list Plant Inspection Report (PIR) numbe In addition to clarifications of the SWRS, the GPUN Welding Manual should be modified to specifically address attachment welds to existing plant steel. The licensee agreed to review the manual with respect to the above aspect Licensee action on the above items will be verified in a subsequent inspection (219/86-12-04).
Other than the problems discussed in the above three violations, the completed work was found to meet drawing and construction installation requirement . Inspection of Piping and Pipe Supports During this report period, insulation was removed from portions of several safety related piping systems to facilitate various inspections of pipe welds and pipe supports. As discussed in previous NRC Inspection Reports, the licensee had performed a substantial reinspection of pipe supports in response to a NRC inspection to close NRC Bulletin 79-14. However, this inspection activity did not include removing insulation to verify correct installation of the support to the piping. In a meeting held April 1, 1986 at the NRC Regional Office, the licensee stated, with the exception of several recirculation system supports, all supports had been reinspected and the results of the inspections were being analyzed. No additional inspections to meet requirements of Bulletin 79-14 were planned beyond the several recirculation system support The NRC inspectors walked down those portions of the Isolation Condenser system piping from which insulation had been removed. During this walkdown the inspectors observed that the pipe clamps that form a part of the overall snubber assembly of two snubbers were not welded to the piping. The particular snubbers and their design drawings are as follows:
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633-R1 or NE-1-S4 as shown on Bergen-Paterson Dwg. #173
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633-R4 or NE-1-S5 as shown on Bergen-Paterson Dwg. #17 These snubbers are shown on piping isometric drawing JCP-19433, Rev. 3, Sheet 2 and are located on the steam lines to the 'A' isolation condense The drawing for snubber 633-R1 requires that two 3/8" x 1 1/2" x 3" long stainless steel lugs be fillet welded to the pipe along the 3" side of the lugs (the 3" long side follows the circumference of the pire) and that the pipe clamps be butted up against the other 3" side of the lugs and a
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DETAILS Participants 1.1 GPU Nuclear Corporation D. Croneberger, Director-Engineering and Design R. Fenti, Manager-Qyster Creek QA Mods / Ops R. Keaton, Director-Quality Assurance M. Laggert, Manager BWR Licensing R. Long, V.P.-Nuclear Assurance F. Manganaro, V.P.-Maintenance, Construction, & Facilities W. Popos, MCF Production Director J. Rogers, Dyster Creek Licensing Engineer E. Scheyder, MCF Director, Oyster Creek J. Thorpe, Director-Licensing and Regulatory Affairs 1.2 Nuclear Regulatory Commission Region I W. Bateman, Senior Resident Inspector, Oyster Creek W. Baunack, Project Engineer A. Blough, Chief, Reactor Projects Section IA J. Durr, Chief, Engineering Branch, Region I D. Holody, Enforcement Coordinator, Region I W. Kane, Director, Division of Reactor Projects H. Kister, Chief, Project Branch No. 1 J. Wechselberger, Resident Inspector, Oyster Creek J. Wiggins, Chief, Materials and Processes Section Purpose The enforcement conference was held at Region I's request to discuss the circustances that led to the inoperable snubbers, corrective action that has been effected to preclude this type of problem from recurring, and technical aspects of Isolation Condenser system operabilit . Presentation The NRC Region I Director, Division of Reactor Projects, W. Kane, opened the conference by asking the licensee to explain the circumstances surrounding the issue of the four inoperable snubbers. GPUN responded in basically a three part presentation:
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(1) Discussion of history leading up to the problem, (2) Discussion of corrective action taken, not in response to this issue in particular, but to control of contractors in general as the result of a self-critique after the 1983-84 outage, and (3) Discussion of the technical adequacy / operability of the Isolation Condenser system with the four snubbers assumed inoperabl .
 
fillet weld used to connect the lugs to the pipe clam This arrangement prevents movement of the pipe clamp relative to the pipe and permits transfer of loads to the snubber as designed. The 633-R1 snubber drawing indicated lug placement on opposite sides of the clamp 180 degrees apar In the case of this snubber, tne gap between the lugs was approximately 1/4" greater than the width of the pipe clamp. This gap existed totally on one side of the clamp, i.e., the other side of the clamp was in bearing with the other lug. This 1/4" gap precluded making a fillet weld between the one lug and the clamp. In fact, neither lug was welded to the clam The drawing for snubber 633-R4 requires that the same size and type lugs be attached in the same way, but on the same side of the clamp. In the case of this snubber, it was obvious that welds had at one time existed between the lugs and the pipe clamp but that these welds had been ground out and not subsequently rewelde The fact that these two snubbers' pipe clamps were not welded to the lugs rendered them inoperable. Both of these snubbers are required by Tech Specs to be operabl In particular, the Technical Specification Limiting Conditions for Operation 3.5.A.8 states: All safety related snubbers are required to be operable whenever tne systems they protect are required to be operable except as noted in 3.5.A.8.b and c belo With one or more snubbers inoperable, within 72 hours replace or restore the inoperable snubber (s) to operable statu If the requirements of 3.5.A.8.a and 3.5.A.8.b cannot be met, declare the protected system inoperable and follow the appropriate action statement for that syste The action statement Tech Spec 3.8.C for the Isolation Condenser system states that if one isolation condenser becomes inoperable during the run mode, the reactor may remain in operation for a period not to exceed 7 days; then the reactor shall be placed in the cold shutdown conditio Subsequent to this finding, the Itcensee commenced an investigation to determine why the snubbers were not welded. Although the investigation was not completed prior to the end of this report period, it was deter-mined that a discrepancy list generated in August 1984 during Isolation Condenser system piping repairs of cracks caused by IGSCC identified missing welds on three snubbers. Two of the three snubbers were those discussed above. The third was inspected by the licensee during this investigation and it was also found to be missing the welds between the lugs and the pipe clam The failure of the licensee to realize that three Tech Spec required snubbers were inoperable resulted in operation of the plant in violation of Technical Specification Limiting Conditions for Operation for a period of at least the entire Cycle 10 operating period. This is a violation (219/86-12-05).
 
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GPUN explained it appeared that General Electric Company (GE), the contractor employed to repair Isolation Condenser welds suffering from IGSCC, had signed various cocuments broadly indicating all work, which would include the welds on the subject snubbers, was complete. Based on these signoffs, GPUN accepted the work as complete. As discussions progressed, it became clear, however, that GPUN did not have in their possession the detailed records (e.g., job travelers) of work performed and that GE had not yet formally respor,ded to GPUN's request for a full explanation of the circum-stances. This-information was stated by GPUN to be forthcomin GPUN stated corrective action taken prior to the start of this 11R outage involved improved contractor oversight by use of GPUN job monitors, improved contractor selection process, and an extended contract for the major site contracto GPUN stated they felt this corrective action addressed the problem at issu GPUN's technical discussion as to Isolation Condenser system operability, assuming the four snubbers were inoperable, indicated the system would still have remained functional,in event of a design basis earthquake (i.e., safe shutdown earthquake). This conclusion was drawn from a computer analysis of pipe and pipe support stresse . Conclusion The licensee concluded that, even though the four snubbers were inoperable, there no significant safety concerr as to system operability. The NRC requested a copy of the calculations for review prior to concurring with this conclusion. In addition, the lack of complete documentation precludes complete NRC verification of the event circumstances. GPU stated they would send the GE report to the NRC after they themselves receive it. And finally, it was stated by GPUN, that evaluation of the the effectiveness of the corrective action taken will require a post-outage critique of the current outage (11R) similar to that done after the last outag . . . . - - - - _ . -.
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8 On-Site Review of LERs The following LERs were reviewed to deternine if reporting 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 review and evaluation were complete and accurate, and the LER form was properly complete (Closed) 83-04: Failure of CR0 Feed Pump Breaker to Operate as Designed During a preventive maintenance (PM) bench test of a CR0 feed pump circuit breaker, it was determined that the undervoltage tripping function of the breaker was not functioning properly. The malfunction was attributed to binding and friction of the trip shaft bearings due to oxidized lubrican The inspector reviewed documentation which verified all similar breakers in safety related applications have been disassembled and inspected. Also, the PM frequencies have been revised to require 12 month inspections and a new PM checksheet has been develope (Closed) 83-07 and 83-07/03X-1; SGTS II Declared Inoperable and Removed from Service for HEPA Filter Replacement Standby Gas Treatment System (SGTS) II was declared inoperable du*ing surveillance testing due to a high differential pressure across its HEPA
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filter The HEPA filters and pre-filters were replaced and satisfac-torily teste Subsequent licensee evaluation (83-07/03X-1) showed that apparent high filter differential pressure resulted from (1) corrective maintenance on the flow sensing pitot tube and no post maintenance testing to verify flow curves, and (2) use of a noncontrolled outdated flow curve by operations personne The inspector reviewed documentation which verified flow calibration curves have been revised in appropriate procedures; the LER was made required reading for Maintenance and Construction, Plant Materfel, and Plant Operations personnel; that appropriate personnel have been made aware of the requirement to calibrate flow instruments following repair of sensing elements; and that a memorandum was issued to all Operations personnel regarding outdated operational aid (0 pen) 83-24: Limitorque Motor-Operated Valves Torque Switch Setpoints The licensee reported that during a review of torque switch setpoints of the Limitorque motor operated valves at Oyster Creek, it was discovered that the setpoints on many motor operated valves had been set lower than the manufacturer's data. Further investigation of isolation valves revealed that the torque switch setpoints set during pre-operational testing were found to be lower than the manufacturer's data. In some
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cases, these setpoints were later changed to values lower than pre-opera-tional testing in the course of plant operation as determined through maintenance and surveillance testin In the report the licensee described corrective actions which would be taken on safety related valves prior to plant startu During this inspection the inspector reviewed a GPUN Technical Data Report which documented the actions taken as required by the corrective actions described in LER 83-24. The corrective actions described and the actions taken were as follows:
(1) Completion of the actual design basis investigation -- GPUN obtained from Limitorque copies of the motor operator bills of materials for 57 valves which were identified as isolation and/or safety related valves. These bills of material list the differential pressure used to size the operator and the torque switch setting required to oper-ate the valve against differential pressure. This data is the origi-nal baseline data for the Oyster Creek plan (2) Determine the appropriate torque switch setpoints -- GPUN used an independent third party, Torrey Pines Technology, to do torque switch setpoint calculation .
(3) Resetting the torque switch setpoints on all applicable valves --
GpVN used Motor Operated Valve Analysis and Test System (M0 VATS) to reset the torque switches and test and analyze the 57 safety related valve (4) Issue administrative controls to eliminate recurrence of this incident -- Oyster Creek Nuclear Generating Station Procedure 700.2.010, Motor Operated Valve Removal Installation or Inspection (Elect) has been revised to specify opening and closing torque switch setting The licensee also stated a followup report would be issued following the completion of an investigation of this matter. This item remains open pending receipt of the licensee's followup repor _
( Closed) 83-25: Procedures Did Not Contain Requirement for Verifying Excess Flow Check Valves Open During a review of plant procedures by the licensee, six maintenance and two surveillance procedures were identified as not adequately addressing the Technical Specification requirement that each time an instrument line is returned to service after any condition which could have produced a pressure or flow disturbance in that line, the open position of the flow check valve in that line shall be verifie . - _ - . _ - _ . - . . . _
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These deficiencies were discovered by the licensee during a review of all Technical Specification surveillance procedures to ensure they reflected Technical Specification requirement All excess flow check valves affected by the deficient procedures were verified open prior to returning the associated systems to servic During this inspection the inspector verified corrective action had been taken to revise procedures as necessary. Procedure 603.3.002, 610.3.010, and 703.3.001 were changed to include the Technical Specification require-men Procedures 700.3.007, 719.3.006, 710.1.003 and 719.1.001 have been deleted, and Procedures 700.3.008 and 700.1.004 were determined to not require a chang (Closed) 84-01; Diesel Generator Fuel Oil Tank Level Below Technical Specification Limit After several test runs of the No. 2 diesel generator, the fuel oil tank level was noted as being slightly below the Technical Specification limi The apparent cause was operator error in not properly following up on an apparent low level indication. However, a contributing factor is that the tank capacity is only slightly greater than the Technical Specification limit, and the tank has been overflowed in the pas The corrective action to prevent recurrence was to change procedure 636.4.003 to clarify the requirement to refill the diesel fuel oil tank, and to issue a memo to all operating and supervisory personnel informing them of the revision to the procedure i istructing them to refill the tank after each load test or one hour of operation. In addition, Amendment N has been issued which reduces the Technical Specification required fuel oil amount. With this Technical Specification change, more operating flexibility is provide .(Closed)84-02: Failure of Several Breakers to Trip Upon De-energization of Their Undervoltage Trip Device The licensee reported the failure to trip of three separate breakers during the performance of undervoltage trip time operability and trip bar actuation tests. Immediate corrective action was to perform preventive maintenance on the circuit breakers. The trip shaft bearings were cleaned, lubricated and measured to have a torque of 20 inch-ounce The static time delay units ware readjusted to within specifications and the breakers tested for operability three times before being returned to servic During this inspection, the inspector reviewed documentation which verified that Preventive Maintenance Procedure 761.2.003 was revised to include 'lla appropriate recommendations of GE Service Advice 175(CPPD) Additional actions taken by the licensee to assure operability of undervoltage trip devices is provided in the licensee's response to IE Bulletin 83-0 . .
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(Closed) 84-06; Torus Corrosion Pitting and Missing Structural '4 elds This is a voluntary report submitted by the licensee to discuss the identification or torus pitting and missing torus structural welds. The report also identified the repairs performed to restore the torus to the original as-designed conditio NRC Region I Inspection 84-07 was devoted entirely to the inspection activities associated with the torus shell thickness. In addition, routine inspections reviewed additional aspects of the torus repai Based on these efforts, this item is considered close (0 pen) 84-08; Degradation of Neutron Monitoring Instrument Dry Tubes This report describes the identification by the licensee of cracks found in the neutron monitoring instrument dry tubes. While performing local power range monitoring instrumentation replacement work during a refueling outage, operators visually noticed that the dry tube associated with an intermediate range monitor (IRM) appeared bent near the upper core gri Further investigation revealed that a total of seven IRM and one source range monitor (SRM) dry tubes were cracked. The cracks were located in the thin wall tube surrounding the assembly compression spring and not in a pressure boundary portion of the dry tube. There are a total of 12 dry tube assemblies, 8 IRMs, and 4 SRMs in the reactor vessel. The corrective action was to replace all 12 dry tube During this inspection, the inspector reviewed documentation which showed all 12 instrument dry tubes were replaced during the time period June 3 to July 19, 1984. All SRM and IRM detectors have been verified operationa The LER indicated a supplemental report is expected to be submitted. The expected submission date of this report was October 30, 1984. To date this report has not been submitted. This LER remains open pending receipt of this repor (0 pen) 84-05: Isolation Condenser Piping Leak Near Weld Joint With the facility shutdown during the performance of a post maintenance hydro test, leakage was noted from isolation condenser condensate pipin At the time of the report, plans were being made to determine the cause of the failur The LER indicated a follow-up report would be submitted. The estimated submission date of this report was identified as June 30, 1984. To date this report has not been submitte The follow-up report is to contain: 1.) the results of an investigation to determine the safety significance of this event had the plant been in operation; 2.) the results of an inspection of the entire isolation condenser system piping; and 3.) a description of the corrective actions required. This LER remains open pending receipt of the follow-up repor x
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(Closed) 84-09; Deg_radation of Secondary Containment Both doors of the reactor building personnel access airlock were opened simultaneously by contractor personnel in order to bring a length of pipe into the building. The length of the time the doors were open is unknown, but the duration was believed to have been shor A critique of the incident was held. The individual responsible was dismissed, a memorandum was addressed to all onsite contractor firms to reinforce training on this matter, and signs were posted at each personnel access airlock warning personne (Closed) 84-10; Fuel Pool Gate Movement Above Irradiated Fuel Technical Specifications require that no objects in excess of the weight of one fuel assembly (approximately 485 lbs.) be moved over stored irradiated fuel. During a licensee review of a proposed modification to the fuel storage rack configuration, a question was raised as to whether or not the fuel pool gates (approximately 1800 lbs.) are moved over spent fuel during their removal or replacement. Operations could not specifi-cally cite any one particular instance of this, but they believe that movement of the gate over spent fuel may have occurred several times during past refueling operations. The station procedures used for movement of thes6 gates refers to the reactor building overhead crane operating procedure for control of loads over irradiated fue To prevent recurrence, Station Procedure 756.1.004, Fuel Pool Gates Removal and Installation, has been revised to caution that fuel pool gates shall at no time be moved over irradiated fuel. Also, a memo was issued to all Productio.1 Group Maintenance Supervisors and Mechanics informing them of these requirement (Closed) 84-11; S andby Gas Treatment Systems I and II Simultaneously Inoperable Goth trains of the Standby Gas Treatment System (SGTS) were inoperable for nine (9) minutes while performing preventive maintenance on a circuit breaker. The maintenance required that the circuit breaker for a motor control center be racked out, which secured power to the emergency exhaust fan and the inlet, outlet, and orifice valves of SGTS II. This made SGTS II inoperable. The three (3) valves in the SGTS II failed open due to the loss of power, which permits recirculation flow through train II from train I upon initiation of SGTS This caused SGTS I to also be considered inoperable. The event occurred due to Operations management misunderstanding of the extent of the temporary change associated with a plant modification involving the SGT To prevent recurrence, a plant modification has been made which makes each SGTS train electrically independent. The air operated valves for each train fail close on loss of electrical power to the respective fans. Also, a re-evaluation of the method used to inform personnel of
 
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the status of plant modifications was conducted. The evaluation con-cluded existing procedures and the use of " Nite Orders" are sufficient to insure that plant personnel are informed and trained on system /
equipment modification (Closed) 84-12; Both Emergency Diesel Generators Simultaneously Inoperable During a scheduled load test on Emergency Diesel Generator No.1 (EDG-1),
a diesel fuel oil day tank low level alarm was received in the Control Roo Subsequent investigation revealed that the diesel fuel oil transfer pump control switch for EDG-1 was in the Off position. In the Off position, fuel oil is not automatically transferred to the diesel day tank from the main fuel storage tank. This resulted in EDG-1 being considered inoperable. Since EDG-2 was out of service for governor repairs, both emergency diesel generators were simultaneously inoperabl To prevent recurrence, plant tour sheets were revised to incorporate a check of the transfer pump control switch positio (Closed) 84-25; Inadvertent Initiation of Core Spray System During Reactor Low-Low Sensor Calibration During a calibration of reactor water level sensors for Core Spray System II, Core Spray System I was inadvertently initiated and injected torus water into the vessel for approximately 20 seconds. The cause of the occurrence is attributed to personnel error. Personnel were perform-ing sections of the procedure out of the as-written sequence, accidentally omitted a key step, and erroneously performed a step on the wrong instru-ment. Another cause of the event was the amount of temporary changes to the procedure being used. The procedure was changed extensively, primarily to delete steps not needed for the low-low sensor calibratio A critique was held immediately following the event and certain corrective actions were specifie During NRC Inspection 50-219/85-11, it was noted that no corrective actions had been initiated until the time of the inspection (March 28, 1985, four months after the event). Durir.g this inspection, the inspec-tor verified corrective actions had been made which consisted of changes to Station Procedure 116, Surveillance Test Program. This change was to reflect that procedures will be performed in the as-written sequence and that the person responsible for performing the test sign that the proce-dure has been completed in its entirety. Also, this LER was made required reading for Control Room Operator (Closed) 84-29; Cask Lift with Unadjusted Crane Vertical Limit Switches While performing an initial training lift and movement of a spent fuel shipping cask above the top of the Cask Drop Protection System (CDPS),
the two crane vertical limit switches were not properly adjusted and were manually overridden. Technical Specifications require vertical
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l limit switches to be operable during cask movement above-the top of the CDPS to limit the height of the cask to no more than 6 inches above the CDP The causes of the event were determined to be lack of detail in the cask handling procedure, inadequate supervision of craft personnel, and inadequate instruction of personnel on Technical Specification requirements relative to cask handlin After it was noticed that the limit switches were not set, the cask was removed from above the CDPS and lowered to the refueling floor on a safe load pat A critique was held to discuss all noted deficiencies. Corrective actions were initiated and completed prior to further cask movement. These corrective actions included instructions to personnel, procedure changes and the proper setting of the limit switches. These corrective actions were verified at the time of the occurrenc (0 pen) 84-31; Failure of Main Steam Drain Valves to Operate During performance of the Main Steam Isolation Valve (MSIV) closure and In-Service Test (IST), three of four Main Steam Drain Valves (106,107, 110) failed to operate when given appropriate signals. The valves partially opened and would not reclose. Two valves were closed by bypassing their control circuits (106, 107) and the third valve (110)
was manually closed. These valves were deactivated and secured in their isolated position as required by TS 3.5. The apparent cause of this occurrence was the opening of the torque switches, interrupting operation of the valves. The cause of the torque switches opening is unknown at this tim The immediate corrective actions were to close, deactivate, and tag out of service all three valves, as required by the T This LER was reviewed during inspection 85-11. At that time, the LER remained open pending the completion of a licensee investigation to determine the cause of the event and the submittal of a follow-up repor It is expected that the licensee will complete his investigation of the valve failures during this outage. This item remains open pending receipt of the licensee follow-up repor (Closed) 85-02: Two Inoperable Containment Isolation Valves in a Single Penetration During a planned shutdown, Reactor Water Cleanup System isolation valve V-16-1 was required to be taken off its backseat. An electrician was dispatched to the motor control center supplying the valve to engage the closing contactor. To prevent full closure of the valve due to a seal-in closing signal, the electrician manually tripped the breaker. The breaker
 
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trip caused the cleanup recirculation pump to trip, which in turn caused a cleanup system isolation on low flow. A second isolation valve V-16-14 failed to fully close on the system isolation signal, resulting in two inoperable isolation valves in a single penetration. The second valve failed to close due to its lantern ring being damaged which caused the stem to bin A violation was issued in NRC Inspection Report 85-23 for making the automatic isolation function of a containment isolation valve inoperable when it was required to be operable. NRC staff follow-up on licensee corrective action for this violation will be reviewed in a future inspectio During this inspection, it was verified that the corrective action specified in the LER was taken. This corrective action consisted of placing a sign at the breaker for valve V-16-1 that indicated opening the breaker caused a clean-up system recirculation pump trip, and revising Standing Order No.33, Backseating/Unbackseating of Valves, to provide instructions for the proper unbackseating of valve V-16- (Closed) 85-03; Design Deficiency in Core Spray Pump Logic On January 29, 1985, a design deficiency was discovered in the Core Spray system booster pump failure logic. Discharge pressure of the booster pumps is utilized to detect a booster pump failure which will trip the failed pump and provide a start signal to the backup booster pump. Two events were identified which can cause this instrument to misinterpret Core Spray system status and result in the system not performing according to its original design intent - the detection of loss of flow from the Core Spray booster pump. The cause of this occurrence was a deficiency in the original plant desig Corrective action consisted of performing a modification to replace the pressure switches on the booster pump discharge with differential pressure switches. The differential pressure switches will sense differential pressure across the booster pump. This modification allows the pump failure logic to perform as originally designed under all postulated condition The modification was verified to have been installed prior to the startup from the plant shutdown which commenced on February 2, 198 {C.losed)85-04: Violation of APLHGR Limit On Janttry 10, 1985, it was noted that the Power Shape Monitor System (PSMS) calculated TIP traces were under-calculating the reactor axial neutron flux profile when compared to measured TIP traces and PSMS model performance was beyond established acceptance criteria. An investigation commenced immediately to confirm the observation and determine the cause of the different flux values. The reactor rod pattern was adjusted on
 
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January 15, 1985 in an attempt to reduce the high flux peaks. On January 24, 1985, a complete set of TIP traces were taken to determine if the adjustment reduced the peaks and improved model performance. Upon review of this TIP set, it was noted that flux peaks remained high and PSMS model performance was still outside the established acceptance criteria. At this time, it was suspected that the APLHGR Technical Specification limit was violate Once it was determined that the Technical Specification limits on APLHGR had been exceeded, core thermal power was reduced and the control rod pattern was reconfigured to reduce power peaking. The flattening of the power distribution was sufficient to eliminate the Technical Specification violatio The causes of the violation were that the bottom flux peaks which existed at the facility during the month of January were beyond the limits of the PSMS Cycle 10 model and resulted in the under calculation of the peaks,
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and the PSMS software did not permit the LPRM feedback option to function, even though the option was turned o The corrective actions consisted of improved procedural control which would more frequently evaluate the PSMS nodal model accuracy and performance; specification of immediate corrective action when PSMS performance is outside acceptance criteria; and strict adherence to operational guidelines during core operations will reduce measured TIP peaks and reduce average relative axial power shape; and more frequent performance of individual TIP traces during power maneuverin Discussions with Core Group personnel verified that all corrective action has been incorporated into various facility procedures. The corrective actions were incorporated into procedures over a period of time to coincide with major procedure revisions. Core group personnel stated all procedure changes required as a result of this LER have been mad (0 pen) 85-06: Reactor Scram Due to Low Water Lovel
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On February 24, 1985 an automatic reactor scram occurred due to low reactor water level during a plant startup. The reactor was operating at a power level of 400 MWt with level and pressure being controlled automatically. A planned drywell inspection for steam leaks required reactor power to be less than 10% with steam flow minimized. In preparation, rods were inserted to decrease power. The rod movement caused a level, power, and pressure transient which ultimately led to an automatic scram on low level despite operator attempts to stabilize the transient. All plant systems responded as expected and control room operators brought the plant to a shutdown conditio The root cause of the event was determined to be operator error in
,  introducing a too-rapid decrease in reactor power and the inability of the
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Corrective action for this event was described as adding a caution to the drywell access procedure alerting the operators to the sensitivity of level and pressure to power changes at low power conditions. Also, plant startup and shutdown procedures will be reviewed for applicability of this cautio During this inspection it was determined that following the issuance of this LER on March 27, 1985 a Licensing Action Item was issued to Plant Engineering on April 1, 1985 tasking them with implementation of the corrective actions. Plant Engineering on June 18, 1985 issued a Technical Functions Work Request asking Technical Functions to implement the corrective actions. At the time of this inspection, 15 months after the event, corrective actions consisting of procedure changes had not yet been mad (Closed) 85-07; Failure to Sample Tank On March 20, 1985, during a routine Technical Specification surveillance, it was discovered by the Plant Chemistry Department that the outside floor drain sample tank was being used but had not been sampled since March 13, 1985 This was in violation of Technical Specifications which require this tank to be sampled every 72 hours unless it has been valved out of service after determining its radioactive content. Upon discovering that the tank was being used but not sampled, a sample was taken to cenfirm that the tank did not exceed the applicable Technical Specification maximum curie limi The event resulted from Chemistry not being told when the tank was placed back in service after it had been isolate To prevent recurrence, certain procedure changes were mad The inspector verified that a precaution / limitation had been inserted into procedures to ensure that the 72 hour Technical Specification sampling is met and that either the Manager of Radwaste Operations or Chemistry is notified prior to the 72 hour time limit, if this requirement cannot be met for any reaso This change was made in Revision 11 to Procedure 351.1, Revision 12 to Procedure 351.2, and Revision 1 to Procedure 83 (Closed) 85-08: 4160V Emergency Bus Technical Specification Violation A Plant Engineering review of Technical Specification Amendment 80 found that existing procedures did not meet the new Technical Specification requirements and calibration tolerance Existing calibration documentation was reviewed for the degraded voltage relays and degraded voltage relay timers. Although they were found to be within the acceptable tolerances stated in the existing procedures, the procedures had not been revised to incorporate the recently issued Technical Specification requirements. The Amendment was effective on the date of issuance and did not provide for an implementation period in which to revise the procedures. Immediate action was taken to temporarily change the procedures required to ensure compliance with the Technical Specification Amendmen I
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l The inspector verified that appropriate procedures have been prepared to implement the Technical Specification change.
 
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(0 pen) 85-09; 480 Volt Bus Overload As the result of an electrical load study performed for Oyster Creek, it was determined that 480 Volt Unit Substation 1A2 or 182 may be overloaded during a loss of coolant accident with offsite power available and
! concurrent loss of one Unit Substation. The cause of this deficiency has been determined to be a design problem because the impact of plant modi-fications on bus loadings was not evaluated for this particular set of condition If the Unit Substations are run in the anticipated overload condition, it will result in decreased transformer life. Corrective actions are planned to install fans to increase transformer capacity and install an overcurrent alarm for the buse An alarm indicating overcurrent on each of the Unit Substations has been installed. This alarms in the control room and the alarm response procedure instructs control room personnel to shed unnecessary load Fans will be added to the transformers for the Unit Substations. These fans will increase the capacity by 15*4 and bring the anticipated worst case loading within the rating of all the Unit Substation components. The fans will be installed during this outag This item remains open pending l the installation of the fans.
 
(0 pen) 85-10; IRM Setpoints Exceeded Technical Specification Limits While reviewing "as found" data on IRM setpoints, it was discovered by the licensee that some upscale scram and upscale rod block setpoints had slightly exceeded the allowable Technical Specification limit. The apparent cause of this occurrence was the inadvertent deletion of the IRM calibration procedure. Since the deletion of this procedure, the IRM
< drawers have been calibrated during refueling outages using vendor manual instructions with the "as found" and "as left" setpoints not documente An appropriate procedure, 620.3.007, Mean Square Voltage Wide Range Monitor (IRM) Bench Calibration, which documents "as found" and "as left" setpoints has been prepared. Also, a modification is being evaluated to permit testing trip settings during weekly front panel test This item remains open pending the installation of this modification.
 
; (0 pen)85-11: Three of Four Isolation Condenser _ Actuation pressure Sensors
! Out of Specification i
During routine surveillance testing, 3 of 4 isolation automatic actuation pressure sensors tripped at values slightly greater than specified in the Technical Specifications. The cause has been attributed to instrument drift. The immediate corrective action was to reset the trip setpoints within desired limits. Replacement of these sensors with ones having better setpoint repeatability is scheduled during the Cycle 11 refueling outage. This item remains open pending replacement of these sensor . .
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  (0 pen) 84-26; Emergency Service Water Containment Spray Negative Delta Pressure This report describes a condition which has existed for sometime. In particular, the differential pressure between the Emergency Service Water (ESW) and Containment Spray (CS) is such that the CS water pressure is higher than the ESW pressure in the CS heat exchangers. This would, following a loss of coolant accident, permit radioactive CS water to leak to the environment if a heat exchanger leak were present. This condition is also contrary to that described in the Facility Description and Safety Analysis Report. A Notice of Violation relative to this matter was also issued on March 14, 198 TheLElknotesthecauseofthenegativedifferentialpressureisbelieved to be a decrease in ESW pump performance and increased pressure drop in the ESW piping. Subsequent evaluation by the licensee in reference to Licensing Action Item 84208.01, documented that the negative pressure differential across heat exchanger tubes is the result of degraded pump performance and increased resistance due to biological fouli The licensee performed a safety evaluation to estimate the offsite dose due to leakage from the CS' System during a loss of coolant accident.. The evaluation concluded the existing condition will not significantly affect the safety of the public or plant personnel. However, the evaluation specifically notes the condition allows the possibility for a lingering effect of radioactive iodine deposition to the environment after a loss of system coolant accident. Therefore, the system will be returned to its original design prior to startup from the 11R refueling outage (that is, emergency service water at a higher pressure than the Containment Spray System).
 
!  The LER also indicated a supplemental report would be submitted, with the expected submission date being June 30, 1985. This LER remains open pending the receipt of the licensee's supplemental report and verification of proper differential pressure between the shell and tube side prior to startup from the 11R refueling outag .(Open) 86-04 Reactor Scram on Anticipatory Turbine Trip Caused by Limit Switch Failure
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This LER, in addition to reporting the reactor scram, also reports a Technical Specification violation associated with failure to close and deactivate a containment isolation valve in the same penetration with an inoperable containment isolation valv During this inspection, the circumstances associated with the licensee's decision to declare a containment isolation valve operable following its apparent failure after the reactor scram on March 6, 1986 were reviewed.
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As noted in the LER, "At 0236 Reactor Water Cleanup system containment isolation valves were opened to attempt a restart of the cleanup system in order to control water level. A high pressure isolation occurred but V-16-14 did not fully close as noted by double valve indication. The torque switch was jumpered out and the valve closed."
 
Also, the Licensee's Deviation Report prepared in association with the testing of V-16-14 states, in part, "All valves isolated properl In the process of restarting RWCU a second system isolation occurred on high pressure. This time V-16-14 did not fully isolate (double indication). An electrician was called and he had to jumper out the torque switch to close V-16-14."
 
The Post Trip Review Group recommended prior to restart that discrepancies with V-16-1 and V-16-14 be correcte In order to affect this corrective action, Maintenance and Construction Short Forms SF34723 and SF34275 were written. SF34275 was written to perform M0 VATS testing of V-16-14. The Short Form (SF) indicated that MOVATS current traces obtained for V-16-14 were found to be acceptabl MOVATS switch signatures were judged not to be required. The malfunction /
cause described on the SF initially was "under sized motor," but it was subsequently changed to "possible under sized motor" upon further review by the license The current values obtained on March 6, 1986 and previous values obtained on November 15, 1985 were noted as follows for V-16-14:
3/06/86  11/15/85 0C* CO** OC  C0 Start Current    39.5 A 42.35A 35.6A  36.85A Avg. Run Current    7.35A 8.4 A 7.2A  8.5 A May Run Current    7.35A 8.8 A 8.8A  9.8 A End Current    32.15A 8.8 A 31.9A  8.55A
  *0C -- Valve moving from open to closed
  **C0 -- Valve moving from closed to open The TFWR associated with V-16-14 was written on November 22, 1985, and described results of some previous testin The TFWR noted that on November 15, 1985, the operator was unable to obtain the recommended minimum thrust values and that any increase in torque switch setting would result in the motor running continuously after completion of valve travel because the motor would never generate enough torque to trip the torque switch. Additionally, the TFWR stated that the motor capability was marginal. The TFWR also notes the motor pinion and worm shaft gears of the operator were changed. This increased the capability of the motor but it is still considered marginal. The TFWR requests Technical Functions to review the feasibility of increasing the motor, cable, and starter size for V-16-1 _ _ _ _ - _ _ _ _ - _ _ _ _ - _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _  _-______ _ __ _____ __- ___ _ ___ _____ _ _ - _ -
 
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Additional information relative to the performance of V-16-14 was obtained from a review of the valve maintenance history and a memorandum dated March 17, 1986, from Plant Engineering to Technical Functions which provided a history of V-16-14 failures. This information is summarized as follows:
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The operator currently on the valve was installed during the 1983-1984 outag February 2,1985, the valve failed to fully close. This was attributed to mechanical binding causing the torque switch to ope The cause of the binding was due to a damaged lantern rin June 12, 1985, V-16-14 failed to open due to a motor overload tri Later, when closing the valve the close contactor would not drop out and an operator present at the motor control center had to trip the breaker manually. The cause of this failure to trip was attributed to a loose set screw which allowed the torque switch setpoint to drift to a higher value. At this higher value, the motor was unable to trip the torque switch open. It was noted that previous M0 VATS testing had shown the motor to be marginal and that it would not trip the torque switch at higher thrust values. LER 85-12 identified the valve's failure to open following a June 12, 1985 reactor trip. This was attributed to insufficient torque due to improper gear ratios in the operator. On June 15, 1985 the motor pinion and worm gears were changed to increase the motor torque. Tests showed torque increased, but is was still considered margina Valve thrust data after gear replacement was reviewed and noted to be as follows:
Recommended Thrust Values Minimum  Normal  Maximum Open 15956  21164  23280 Close 8346  10582  11640
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Recorded Thrust Values Open  Close  Date 10283  10442  10/03/84 15955  11493  02/13/85 10530  11237  11/15/85 As can be seen, little improvement was noted following the gear replacement.
 
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November 10, 1985 a broken stem nut was identified. This failure was not attributed to the motor or torque switch. Also, the spring pack lock-nut was found loose. Testing following the repair again showed the motor was unable to trip the torque switch open at higher setpoints and thrust value November 22, 1985, the motor for V-16-14 was replaced with an identical motor from V-17-57. The motor was replaced due to damaged wiring incurred while re-installing the motor after troubleshooting for a ground. Current signatures indicated the same characteristics
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as the original motor current signature March 6, 1986, the failure described in this LER 86-04 occurre A follow-up memorandum to the TFWR from Technical Functions dated May 1, 1986, which was not available to the reviewer on March 6, 1986, indicated that Limitorque, the operator vendor, stated the operator should provide sufficient torque (thrust) to satisfy its application. They feel that if the operator is not providing sufficient output, then there must be a problem in the operator, motor, or its power supply. Additional data presently available on site shows that a new identical operator tested by Limitorque is providing approximately twice the thrust the installed operator is providing. Further evaluation of this new operator is planned when it is installed on V-16-14. Also, the valve is scheduled for inspection during this 11R outage.
 
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Since the valve had apparently failed to close on March 6,1986, and that no changes or repairs had been made based only on a MOVATS current trace which showed the currents were essentially the same as they had been prior to the failure, the inspectors questioned the licensee on his basis for declaring V-16-14 operabl The licensee provided the inspectors the basis by which the valve was declared operable during a meeting with representatives of Plant
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Engineering and Operations personnel on June 3, 1986. The licensee's position is summarized as follows:
The licensee felt, ba2ed on the available data at the time of the trip and the post trip review, that it was not clear as to whether V-16-14 failed to open or failed to close. To be conservative they declared the valve inoperable and decided to obtain a MOVATS current signature of the valv The current signature indicated there were no problems. Based on this data and subsequent satisfactory operation of V-16-14, the valve was declared operable. The decision not to perform additional troubleshooting appears to be related to the ambiguity as to what actually happened with V-16-14 and the understanding by many people at the time just after the event until after restart, that the valve failed to open, not close. The licensee stated V-16-14 will be thoroughly inspected and tested prior to restart from the 11R outag ,
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23  j In fact, V-16-14 did fail to close. It's closing torque switch tripped and left the valve in an intermediate position. This occurred when V-16-14 was being jogged open and a Reactor Water Cleanup system isolation signal was received. It is incumbent on Plant Engineering to address this scenario and determine if a problem exists such that if the torque required to reverse the valve direction is greater than the setting of the torque switch, then V-16-14 will always fail to close in this scenari Differential pressure across the valve also needs to be included in the scenari The NRC staff will continue to follow this matte (  '
(0 pen) 84-007; Failure to Test a SGTS Train Within Required Time During a refueling outage, a diesel generator (DG) was declared inoperable as a result of a monthly surveillance failure. This required testing the redundant standby gas treatment system (SBGTS) train, since the DGs are the emergency power source for the SBGTS. The redundant train was not tested for ten hours dn to a procedure limitation as a result of torus painting. Technical Specifications require testing the redundant train within 2 hours. This was not accomplished and handling of irradiated fuel continued on the refueling floor in violation of Technical Specification requirement In response to this, GPUN licensing committed to request a revision of Technical Specifications by November 15, 1984. Technical Specification Change Request (TSCR) No. 133, was submitted January 30, 1986 over one year late. The commitment was made to clarify the fechnical  *
Specifications with regard to surveillance requirements and backup power supply. LER 84-7 stated as part of the corrective action that "a change to the Technical Specificationis will be investigated to ascertain if the more restrictive Technical Specifications regarding normal or emergency power supply requirements in the snutdown or refuel modes.can be eased or clarified." TSCR 133 requested a change in the time to test a redundant SBGTS train from two to twalve hours if a SOGTS train is inoperable and significant painting, fire, or chemical release has taken place in the reactor building. TSCR 133 did not clarify the Technical Specifications with regard to normal or emergency power supply requirement In addition, no clarification was provided on moving irradiated fuel untti the SBGTS operability has been determine Furthermore, the licensee has traditionally interpreted and so states in LER 84-07, that Techniccl Specification 3.0.B is more restrictive during shutdown or refueling with regard to inoperability of power sources than during normal operation This refers to the last sentence in 3.0.8,
"This specification is not applicable in cold shutdown or the refuel mode." which the licensee has intenreted to mean that during these modes both normal and emergency power supplies are required for a system to be~
operable. During normal operation, 3.0.B allows system to be considered operable if either the normat or emergency power source is inoperable and the redundant train is operable. The last sentence in 3.0.B could also
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be taken to apply to only the preceding sentence, which requires the plant to proceed to cold shutdown if 3.0.B is not satisfied; thus negating the requirement to proceed to cold shutdown if that is the plant's present mode of operation. The licensee has applied 3.0.B in cold shutdown and refueling to require an operable emergency power source. The licensee has agreed to change the applicable section of the technical specification for clarification. This LER will remain open pending generation of a Tech-nical Specification that addresses normal and emergency power supply requirements during all modes of operation, including shutdown and totally defuele Summary A total of 29 LERs were reviewed during this inspection. Seventeen of the 29 are considered closed. Four LERs, 84-31, 85-09, 85-10, and 85-11, are
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expected to have specified corrective actions completed during this outage, with 84-31 having a follow-up report du Report 85-06 remains open pending the completion of the specified '
corrective action. As noted above, corrective action consisting of procedure changes has not been implemented 15 months after the even One LER, 86-04, had only the circumstances associated with declaring a containment isolation valve V-16-14 operational following a valve failure reviewed. The NRC wiil continue to follow up this matte Four LERs, 83-24, 84-08, 84-05, and 84-26 have been identified by the licensee as having supplemental reports due. The expected submission date for the 83-24 supplemental report was not specified. However, expected supplemental report submission dates for the other three LERs were October 30, 1984; June 30, 1984; and June 30, 1985. None of these supple-mental reports have been submitted. This failure to submit supplemental reports in a timely manner was discussed with licensee representative . Review of Periodic and Special Reports Upon receiot, periodic and special reports submitted by the licensee pursuant totTechnical Specification requirements were reviewed by the inspectors. This review included the following considerations: the report includes the information required to be reported to the NRC; planned corrective 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 March and April 1986
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Special Report 86-01 dated 4/20/86 regarding failure to restore a non-functional fire barrier penetration seal to functional status within 7 days from time of discover .
 
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Special Report 86-02 dated 5/13/86 regarding temporary deactivation of fire detection and automatic halon fire suppression systems serving the 480V switchgear room while room undergoes Appendix R modifications. The report stated a continuous fire watch has been established as required by Tech Spec . 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 In accordance with the requirements of 10 CFR 73.71, the licensee reported a moderate and a major loss of physical security during this report period. The moderate loss of physical security involved a short-lived (1 hour and 16 minutes) situation in which less than the required number of intrusion detection systems were it, service for a portion of the protected area fence. This event occurred when portions of the protected area fence were relocated to include several contractor trailers in the protected area. Upon realization of the problem, it was immediately corrected and a search of the protected and vital areas performed. No problems were identifie The major loss of physical security occurred when access to a vital area was obtained by an unauthorized individual. This violation was identified by a member of the security force as the unauthorized individual was leaving the vital area. Subsequent investigation determined the individual was a contractor supervisor who should have had authorization in order to supervise employees under his direction who were working in the vital area. An investigation of the infraction was conducted and corrective action implemented.immediatel Based on the facts that the licensee self-identified both problems and took prompt and comprehensive corrective action, the inspectors had no further concerns regarding either matte . Review of Concrete Anchor Bolt Test Data Associated with NRC Bulletin 79-02 The resident inspectors conducted an inspection at the GPUN Corporate offices in Parsippany, NJ to review test data regarding installation and performance of concrete expansion anchor bolts in seismic piping system What precipitated this inspection was the licensee's stated intention to exclude 157 baseplates and their associated anchor bolts from current Bulletin 79-02 reinspection efforts based on data gathered during their initial efforts to address this Bulletin. The licensee's current reinspection program for pipe support base plates using expansion anchor bolts is in response to the findings from Inspection 50-219/85-14
 
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conducted May 14-17, 1985 which identified deficiencies in the original ir.spection effort which commenced in 1979 and finished in 198 In 1979 the licensee generated Special Procedure No. 79-31, Rev. 1, Inspection Test and Installation Procedure for Concrete Expansion Anchor Bolts in Seismic Piping Systems._ This procedure required pull testing of anchor bolts to verify that Bulletin 79-02 factors of safety could be me It also required that anchor bolt installation data be recorded. The inspection reviewed a sampling of the data to ensure it was sufficient to meet Bulletin requirement The discrepancies identified during the inspectors' review of anchor bolt test data for baseplate installations associated with pipe supports in the Isolation Condenser (211) and Core Spray (212) systems are listed in the below table. It should be noted that all anchor bolt installations reviewed were shell type. The support identification is listed in the left hand column and the anchor bolt test data discrepancies associated with that support are indicated by a 'X' under numbers 1-10 in a row across the table. Each number represents a different discrepancy as defined at the end of the tabl Anchor Test Data Discrepancy Table Discrepancy Type Support Number  1 2 3 4 5 6 7 8 9 10 212-BP.368.R10. X 212-BP.368.R2.15A  X 212-BP.NZ.2.H12.3 X X X 212-BP.368.R3.4 X 212-BP.NZ.2.H30.5 X X 212-BP.41.1.RI.60A 212-BP.NZ.2.H26.64A X X X X 212-BP.NZ.2.H32.93A X X 212-BP.411.R9.7 X X X 212-BP-NZ.2.RSA.97A 212-BP.NZ.2.H52.4 X X X 212-BP-NZ.2.R16A.30A  X
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Support Nu:nber  1 2 3 4 5 6 7 8 9 10 212-BP.368.R6.2 X 212-BP.368-RS.21-A X X 212-BP-368.R9  X 211-BP-634-R9-28-A X 211-BP-632 .R4.48-A    X 211-BP-NE-1-H5.5 X 211-BP-632.RI.5 X  X 211-BP-633-R6.6 X  X 211-BP-NE-1-H10.6 X  X X 211-BP-633-R1.7 X X 211-BP.633.R2.7 X 211-BP.634.R3.1 X  X 211-BP.NE.1.H4.4 X  X 211-BP.634.R2.1 X Key To Discrepancy Types Incorre;t plate bolt hole size for anchor siz In most cases the allowable hole size was greater, but in a few examples, the plate bolt hole size recorded was smaller than the anchor bolt which was obviously erroneous dat . The distance from the top of shell to the top of the red head does not meet manufacturer's recommendation . Shell embedment depth does not meet manufacturer's recommendation . Dial indicator measurement of anchor bolt displacement during pull testing indicates an anomal . Thread engagement measurement of bolt into shell not provide . Bolt spacing may be less than required for 100% capacit . Test loading insufficient to satisfy Procedure 79-31 requirement _  _. __ __ _-
 
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28 Insufficient thread engagement, i.e., bolt is threaded into shell less than one bolt diamete . Edge distance between anchor bolt and concrete may not be sufficien . Disagreement between field data sheets and design drawing The number of discrepancies found in anchor bolt data as illustrated above indicates that the licensee should analyze the data for acceptabilit prior to excluding these installations from future inspection activitie Generally, the data reviewed indicated that the pull test data was acceptable with some exceptions. In several cases the pull test indicated zero displacement for each successive increased load (212-BP.NZ.2.H26.64A; 212-BP.NZ.2.H52.43A; 211-BP.633.R1.73A), and, in one case, the displace-ment decreased with increased load (212-BP-NZ.2.H30.56.A). These installations should be re-eyamine Some other anchor bolts were not tested to the required loading (Discrepancy No. 7). If additional piping support analysis reveals that the analyzed loading exceeds the loading the anchor bolts were tested to, then these anchor bolts will have to be retested to the new loading. In addition, the manufacturer's ultimate pull out load versus concrete strength data for the anchor bolts and the concrete strength for Oyster Creek Nuclear Generating Station were not available. This data is necessary to determine the factor of safety the licensee's testing verified. The licensee stated that they would provide the necessary information to the resident inspectors so that a determina-tion of the factor of safety could be made and this value then compared to the Bulletin required factor of safety of five for shell type anchor (219/86-12-05)
The licensee stated that they plan to conduct a complete review of the anchor bolt data from the 1979-80 inspection for the 157 baseplates in question to ensure the data is meaningfu . Surveillance Testing During the observation of a diesel generator load test surveillance (Procedure 636.4.003), the inspector noted the copy of Procedure 341, Standby Diesel Generator Operation, posted in the diesel switchgear room was outdated. The current procedure revision at the time was Revision 19, while the posted procedure was Revision 18. The purpose of Procedure 341 is to provide detailed instructions for the operation of the Standby Diesel Generators. The licensee determined this was an administrative error and that no adverse operating conditions occurred as a result. The proper revision was posted in the diesel switchgear roo . Presentations The inspectors attended a briefir.g on Technical Manual review conducted by the vendor document control section of Technical Functions Engineering Assuranc . - _ _ -  - . -- .
 
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29 TMI Action Plan Requirements Item I.A.I.3, Shift Manning The inspector reviewed the licensee's Technical Specifications and Procedure 106, Conduct of Operations, to determine if overtime restrictions were incorporated in the document In addition, the recorded working hours for Senior Reactor Operators, Reactor Operators, Equipment Operators were reviewed for May 1986. In both the Technical Specifications and Procedure 106, the licensee had incorporated the overtime restrictions and had appropriately specified the minimum shift requirements. The licensee has implemented a program to track shift operators' working hours to insure the overtime restrictions are followe The review of the working hour records revealed that one equipment operator had worked 80 hours in a seven day period with prior approval of department management. This item is close . Inspector Observations of 11R Outage Activities Defueling The inspectors observed activities leading up to and including complete defueling of the reactor core. The activities were conducted in a controlled fashion using approved procedures. The assignment of an individual to coordinate refueling floor activities aided in this generally trouble-free sequence of activitie Problems were encountered when two of three stud tensioners used to de-tension the reactor head studs broke down and when minor breakdowns of the fuel handling bridge occurred. These were considered minor problems with little impact on the schedul Local Leak Rate Testing Shortly after plant shutdown on 4/12/86, local leak rate testing (LLRT) of containment isolation valves commenced. The LLRT results for the MSIVs indicated a minor packing leak on one valve and no seat leakage past any valve. Historically, at least one MSIV has been found with seat leakage. The fact that there was no seat leakage past any MSIV is an Oyster Creek first and precluded having to rebuild two MSIVs as originally planned for in the 11R schedule. Not all valves tested passed, however. Containment isolation valves in the RBCCW, Reactor Water Cleanup, Torus Vent systems, in addition to l  others, failed and will have to be repaired. The licensee is j  required by Appendix J to 10 CFR 50 to submit a final report of their test results which will document all the valves that failed LLR Fuel Sipping The licensee contracted with GE to perform an inspection of the fuel bundles just removed from the core to determine which leake The process used by GE is called fuel sipping. The process involves placing a fuel bundle in a chamber, sealing the chamber, then forc-ing air bubbles past the fuel elements in the bundle. The air i
 
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strips away any leaking gases from the surface of the fuel elements thel flows out the top of the chamber into a radiation detector that peri.irms an analysis to determine gaseous radioactivity. The liceisee decided to perform. fuel sipping because of increases in gastous activity found in reactor coolant samples that commenced in February 1985. This increase in gaseous activity was considered a precursor of leaking fuel elements. Of 536 fuel bundles sipped, 47 were determined to be leaking. Additional follow-up as to the cause of the leaking fuel elements will be performed in a subsequent inspection (219/86-12-06).
 
During fuel sipping operations in the early morning hours of 5/29/86, area radiation monitor alarms (ARMS) sounded on the refueling bridg At the time the ARMS alarmed, the bridge was positioned on the south side of the spent fuel pool directly in front of the spent fuel pcol gates. The fuel handling grapple was latched on a fuel bundle. The bridge operator disregarded these alarms because he felt they resulted from shine from the vessel cavity which was cry. He pro-ceded to lift the bundle out of the spent fuel storage rack and move it to the sipping cannister. Unknown to the operator at the time, the C-5 criticality monitor alarm on the refueling floor started to alarm both locally ano in the control roo The C-5 criticality alarm has a similar sound as the bridge ARM and was not noticeable as a unique alarm. When the alarm was received in the control room, the GSS followed procedural requirements to investigate the alarm. When he got to the ARM instrument readout, the reading was normal. He felt the alarm was spurious based on not getting a phone call from the bridge operators. Unknown to the bridge operators, personnel friskers in various plant locations alarme This sequence of events happened a second time, when the next fuel bundle was moved to the sipping cannister and then two additional times when the bundles were returned to the spent fuel storage rack It was not clear whether the C-5 criticality monitor alarmed more than once. Out of curiosity, the bridge operators obtained a R0-2A meter to check the radiation level on the bridge when they lifted the second fuel bundle out of the spent fuel racks. The reading peaked at 800 mr/hr. The operators on the bridge communicated the fact they received radiation alarms on the bridge to the GSS in the control room after the second fuel bundle was in the sipping cannister. The GSS did not mentally correlate these alarms with the C-5 criticality alarm received earlie Meanwhile, Radcon personnel were attempting to identify the source of the radiation that was setting off the alarms. They contacted the control room but the GSS had not recognized the problems on the refueling floor because of poor communications with the bridge operators. The Radcon technician on the refueling floor, when questioned as to the existence of any radiation problems, stated there were none. He was mislead to this conclusion based on ,
, reassurances from the bridge operators that the bridge alarms were
 
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normal and his misunderstanding that no fuel was being move Radcon continued their investigation for the balance of the shift. Movement of the problem fuel bundles commenced about 0300 and fuel sipping for that shift was completed about 034 Upon resumption of fuel sipping on day shift, the problem was finally identified. Specifically, radiation streaming through the spent fuel pool gate occurred when the fuel bundles reached the elevation of the gate as they were lifted out of the spent fuel racks. The streaming was unimpeded by shielding and, therefore, caused the various alarms
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to initiate. The amount of time involved with the bundles in this location was minimal as they were moved away from the south wall to the north wall as soon as they were lifted out of the spent fuel racks and were lowered back into the spent fuel racks after completion of sippin The licensee held a critique of this occurrence which a NRC inspector attended. The critique revealed a series of communication and procedural problems. The critique was effective in establishing the problem areas and adequate corrective action was propose Based on the effective critique and the fact that no personnel overexposures or significant unplanned exposures occurred, the inspectors had no further concerns regarding this matte D. Chemical Decontamination Removal of radioactive material from inside the Recirculation system piping was performed by the licensee to lower the radiation levels inside the drywell. This action is consistent with good ALARA policy and will result in many man-rem savings during subsequent drywell work activities. The process used has been used successfully at other nuclear plants and involves injecting certain chemicals in solution at elevated temperatures (180-195 F range) into the Recirculation piping. The chemical reaction results in detachment of small radioactive particles from the inside wall of pip These particles then go into suspension and are subsequently flushed out of the Recirculation piping and collected in filter beds when the chemical solution is removed. Upon completion of the chemical decontamination, a decontamination factor (DF) of 10.38 was calculate This was a high DF that exceeded all expectation E. Intake Structure Concrete Inspection Inspection of intake structure concrete below the water line is being performed during this outage. The NRC inspectors looked at portions of the below water concrete surfaces after they were hydrolazed to remove sea growth and found them to be in generally good conditio Evaluation of cracks and potential corrosion of subsurface rebar is
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an important aspect of this inspection. No significant findings had been reported prior to the end of this report period.
 
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1 Radiation Protection During entry to and exit from the RCA, the inspectors verified that proper warning signs were posted, personnel entering were wearing proper dosi-metry, personnel and materials leaving were properly monitored for radio-active contamination, and monitoring instruments were functional and in calibration. Posted extended Radiation Work Permits (RWPs) and survey status boards were reviewed to verify that they were current and accurat The inspector observed activities in the RCA to verify that personnel complied with the requirements of applicable RWPs and that workers were aware of the radiological conditions in the are With the increased workload during an outage, it is neccssary for Radcon to augment their staffing with contractor personnel. The inspectors observed the performance of contractor personnel to ensure they were adequately trained and capable of performing their duties. No defici-encies were identifie In NRC Inspection "eport 85-35, the licensee was cited because person-nel leaving the RCA were not properly frisking carry along items. The inspector observed frisking activities at various times during this report period and noted several examples of this same problem. These observations were relayed to Radcon management personnel who stated they had not seen recurrence of this problem during their routine tours of the site. They agreed to continue to aggressively pursue informing all personnel of the requirements for frisking prior to leaving the RC The resident inspectors will continue to routinely review this area and follow-up on licensee corrective actions for the above noted violations (which are currently under review by NRC Region I).
 
12. 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 include . _ _ _ . . _-  __ - .
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Revision as of 00:11, 7 December 2021

Insp Rept 50-219/86-12 on 860414-0601.Violation Noted:Pipe Support FP-008 Disassembled W/O Procedures to Control Rework & to Ensure Reinsp & Seismic Restraints FP-001 & FP-002 Welded to Nonseismic Floor Penetrations
ML20205E159
Person / Time
Site: Oyster Creek
Issue date: 07/22/1986
From: Blough A
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20205E123 List:
References
TASK-1.A.1.3, TASK-TM 50-219-86-12, IEB-79-02, IEB-79-14, IEB-79-2, NUDOCS 8608180257
Download: ML20205E159 (32)
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U. S. Nuclear Regulatory Commission Region I Report N /219/86-12 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 and Parsippany, New Jersey Inspection Conducted: April 14 - June 1,1986 Participating Inspectors: W. H. Bateman, Senior Resident Inspector J. F. Wechselberger, Resident Inspector W. H. Baunack, Project Engineer Approved by:

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7 - 2.7 M A. R.(flough, Chief Date Reactor Projects Section IA Inspection Summary:

Routine Inspections were conducted by the resident inspectors and a Region based inspector (393 hours0.00455 days <br />0.109 hours <br />6.498016e-4 weeks <br />1.495365e-4 months <br />) of activities in progress including outage management, maintenance, modifications, QC inspection activity, radiation control, physical security, housekeeping, defueling, fuel sipping, chemical decontamination of recirculation piping, and fire protection. The inspectors

, also reviewed licensee action on previous inspection findings, followed up Licensee Event Reports, and made routine tours of the facility. In addition, the inspectors visited the GPUN corporate offices to review the technical data associated with the licensee's inspection activities in 1979 and 1980 associated with NRC Bulletin 79-02. The inspectors also reviewed licensee control of overtime hours and followed up on various operational problems such as inadver-tent scram signals caused by IRM spiking and inadvertent starts of the Standby Gas Treatment Syste "

8608190257 860008 l PDR ADOCK 05000219 G PDR

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Results:

Four violations were identified. Three were associated with a seismic upgrading of portions of the Spent Fuel Pool Cooling system as discussed in paragraphs 1.A, B, and C. The fourth involved failure of the licensee to recognize that three safety related snubbers in the Isolation Condenser system were inoperable, thereby, placing the plant in violation of Technical Specification Limiting Conditions for Operation as discussed in paragraph 2. Review of certain techni-cal data at Parsippany regarding previous anchor bolt inspections disclosed that the data had not been adequately reviewed by the licensee prior to taking credit for it meeting the requirements of Bulletin 79-0 Review of Licensee Event Reports (LERs) determined a problem exists regarding significant time delays in submitting supplemental LERs and implementing corrective actions.

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l DETAILS 1. Spent Fuel Pool Cooling (SFPC) System Seismic Upgrade - LER 83-26 i

Licensee Event Report.(LER) 83-26 stated the effects of the weight of lead shielding used on the SFPC heat exchangers would overstress the heat exchangers' foundation bolts during a seismic event. It also reported that the original portions of the SFPC piping were supported by dead weight hangers only and, therefore, the affected piping may not be Seismic Class 1 as stated in the Final Description and Safety Analysis Report (FDSAR). The licensee submitted a preliminary report of this issue on 12/20/83. This report stated the corrective actions, in part, would involve seismically upgrading the spent fuel pool outlet and return piping prior to plant startup from the 10R outage. LER 83-26 was formally updated on 2/7/84 and stated the upgrading of the piping would be delayed until prior to the 11R outage core offload. By letter dated 5/20/86 the >

licensee issued Revision 1 to LER 83-26 to, in part, refine their commit- <

ment to seismically upgrade the piping and heat exchangers prior to 11R ,

core offload. This refinement involved upgrading the pipe supports but not the heat exchanger supports. The rationale presented for not upgrad-ing the heat exchanger supports was based on ALARA concerns and the planned replacement of the SFPC heat exchangers during 11 A review of-the licensee correspondence indicates that the licensee changed their original corrective action commitment twice, i.e., once to delay it and once to modify it and delay a portion of it. Because Plant ,

Operations would not permit a major portion of the work involved with installing seismic supports to be done during plant operation, the bulk of it had to be done after plant shutdown prior to core offload. This seismic upgrade became an extremely important job during this report period because it was a NRC commitment that had been delayed once and modified once and, if not completed in a timely fashion, could delay core offload. Upon completion of the work associated with the modified seismic upgrade, the NRC inspector inspected a sample of the upgraded support These inspection activities identified three violations as follows: Hanger mark number BP-435A as detailed on GPUN drawing FP-008, Rev. 2, was found to be partially disassembled in that the U-bolt was not t installed in position. A review of work' package A15A-38685, Rev. O, i Spent Fuel Pool. Cooling System - Mechanical System Upgrade, indicated this support had been final inspected and accepted by QC, Further ,

L investigation into the discrepancy disclosed that craft personnel partially disassembled BP-435A after QC inspection to facilitate

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adjusting the piping in a restraint further downstream. This rework -

was not authorized or controlled. After subsequent questioning of .

involved Maintenance, Construction, and Facilities (MCF) personnel,

! the inspector determined that, as long as a work package remains in

! MCF, there are no procedural provisions to authorize and control

rework. Had the system been turned over to Startup and Test or Plant

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Operations, the work would have been controlled by the "Short Form" l proces .

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The failure of MCF and the Work Management System to proceduralize control of rework prior to turnover resulted in the partial dis-assembly of a newly installed seismic support after QC inspection and acceptanc This action invalidated the QC inspection. This is contrary to Criterion V of 10 CFR 50 Appendix B, and the Oyster Creek Operations quality assurance plan (QAP) section 3 which requires, in part, that activities affecting quality be prescribed by procedure This is a violation (219/86-12-01).

Subsequent to identification of this problem, MCF management issued a memorandum to all involved contractors stressing the policy that rework must be authorized. At the end of the report period, changes were being initiated to controlling procedures to make this a policy of the MCF Work Management Syste The inspector observed two seismic important to safety restraints each welded to a different existing floor penetration. GPUN drawings FP-001 and FP-002 detail the installations. Based on the assumption that the floor penetrations were not considered seismic, the inspec-tor questioned the licensee's rationale for attaching a seismic restraint to a non-seismic member to transfer the loading to the building structur Discussions with Technical Functions personnel responsible for the design confirmed the floor penetrations were not seismic and that the design was subcontracted to Associated Technologies, Incorporated (ATI). An explanation as to why the restraints were attached to the floor penetrations was not give Since ATI used the floor penetrations as a piece of supplementary steel to transfer loads to the building structure, it is evident they were not aware that they could not do this. ATI's lack of awareness can be attributed to lack of appropriate technical information in the contractual document procuring ATI's services. The failure of GPUN to assure ATI properly performed the subcontracted design work is contrary to the requirements of Criterion IV of 10 CFR 50 Appendix B and QAP section 6.4. This is a violatio (219/86-12-02)

It should be noted that neither GPUN nor ATI performed any calcu-

lations to demonstrate the floor penetrations were capable of l transferring the imposed loads. The seismic calculations ended with the restraint design, i.e., upstream of the attachment weld to the floor penetration. Before the end of the report period, Tech l Functions personnel stated the design standards would be clarified to address proper design of seismic supports, once completed the design standards would be made available to all contractors doing design work for GPUN involving Oyster Creek, and calculations would be performed to justify the use of the floor penetrations as seismic members.

I Since the two seismic supports discussed in paragraph 1.8 above were i welded to the floor penetrations, the inspector reviewed the welding I

documentation associated with these welds and determined that the type of material the penetrations were made from was not known by l

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either Tech Functions, Special Processes'and Programs (SPP), or Q The GPUN Welding Manual (Procedure 6150-QAP-7220.01, Rev. 0-00)

states in paragraph 4.2.4 that engineering documents and Weld Package Information Requests (WPIRs) must specify base material specification and grade for new and existing material. A review of the engineering documents and WPIRs disclosed that the existing material (floor penetrations) was never addressed. The inspector questioned SPP as to how they issued a weld package, specified a Welding Procedure Specifications, and issued filler metal without knowing the types of materials that were being joined. Representatives of SPP stated that this specific instance was an oversight and that normally they request base material information from Tech Functions if Tech Functions fails to specify the information, as happened in this cas A review of the Structural Weld Record Sheet associated with these welds indicated that QC had signed for acceptance of the base materials used in the weld. This signoff indicated, in part, that material traceability requirements had been met for the materials joine Because the existing base material was not known, one would question the intent of the QC signature. The inspector concluded there was a failure of (1) Tech Functions to supply existing base material information as required by procedures, (2) SPP to question Tech Functions regarding the base material prior to issuing the weld package, and (3) QC to recognize that the base material of the pene-trations to which the seismic supports were welded was not define These failures are contrary to the requirements of Criteria IX and X of 10 CFR 50 Appendix B and QAP, sections 6.4 and 6.12. This is a violation (219/86-12-03).

At the end of the report period, the licensee did not know the ma-terial type. A search of old drawings was performed in an attempt to identify original material requirements. The results indicated the floor penetrations should have been galvanized A36 steel. How-ever, an inspection of these penetrations led to the conclusion they were not made of A36 'as required by the original construction drawin The licensee plans to take a sample of the material and have it analyze Further, in reviewing the Structural Weld Record Sheet (SWRS) with SPP and QC, it became obvious the instructions for use of this document are confusing. The SWRS is Exhibit 6 in the GPUN Welding Manua The specific areas that require clarification are as follows:

(1) QC acceptance of material traceability on the SWRS when one line on the sheet may represent several different welds; (2) The often time inadequate space on the SWRS used to record the required information; (3) The use of a SWRS Attachment sheet;

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(4) The requirements to list material traceability when welds

are not listed individually on the SWRS; and (5) Proper method of QC signoff on SWRS when welds are not

listed individually, including requirement to list Plant Inspection Report (PIR) numbe In addition to clarifications of the SWRS, the GPUN Welding Manual should be modified to specifically address attachment welds to existing plant steel. The licensee agreed to review the manual with respect to the above aspect Licensee action on the above items will be verified in a subsequent inspection (219/86-12-04).

Other than the problems discussed in the above three violations, the completed work was found to meet drawing and construction installation requirement . Inspection of Piping and Pipe Supports During this report period, insulation was removed from portions of several safety related piping systems to facilitate various inspections of pipe welds and pipe supports. As discussed in previous NRC Inspection Reports, the licensee had performed a substantial reinspection of pipe supports in response to a NRC inspection to close NRC Bulletin 79-14. However, this inspection activity did not include removing insulation to verify correct installation of the support to the piping. In a meeting held April 1, 1986 at the NRC Regional Office, the licensee stated, with the exception of several recirculation system supports, all supports had been reinspected and the results of the inspections were being analyzed. No additional inspections to meet requirements of Bulletin 79-14 were planned beyond the several recirculation system support The NRC inspectors walked down those portions of the Isolation Condenser system piping from which insulation had been removed. During this walkdown the inspectors observed that the pipe clamps that form a part of the overall snubber assembly of two snubbers were not welded to the piping. The particular snubbers and their design drawings are as follows:

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633-R1 or NE-1-S4 as shown on Bergen-Paterson Dwg. #173

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633-R4 or NE-1-S5 as shown on Bergen-Paterson Dwg. #17 These snubbers are shown on piping isometric drawing JCP-19433, Rev. 3, Sheet 2 and are located on the steam lines to the 'A' isolation condense The drawing for snubber 633-R1 requires that two 3/8" x 1 1/2" x 3" long stainless steel lugs be fillet welded to the pipe along the 3" side of the lugs (the 3" long side follows the circumference of the pire) and that the pipe clamps be butted up against the other 3" side of the lugs and a

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fillet weld used to connect the lugs to the pipe clam This arrangement prevents movement of the pipe clamp relative to the pipe and permits transfer of loads to the snubber as designed. The 633-R1 snubber drawing indicated lug placement on opposite sides of the clamp 180 degrees apar In the case of this snubber, tne gap between the lugs was approximately 1/4" greater than the width of the pipe clamp. This gap existed totally on one side of the clamp, i.e., the other side of the clamp was in bearing with the other lug. This 1/4" gap precluded making a fillet weld between the one lug and the clamp. In fact, neither lug was welded to the clam The drawing for snubber 633-R4 requires that the same size and type lugs be attached in the same way, but on the same side of the clamp. In the case of this snubber, it was obvious that welds had at one time existed between the lugs and the pipe clamp but that these welds had been ground out and not subsequently rewelde The fact that these two snubbers' pipe clamps were not welded to the lugs rendered them inoperable. Both of these snubbers are required by Tech Specs to be operabl In particular, the Technical Specification Limiting Conditions for Operation 3.5.A.8 states: All safety related snubbers are required to be operable whenever tne systems they protect are required to be operable except as noted in 3.5.A.8.b and c belo With one or more snubbers inoperable, within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> replace or restore the inoperable snubber (s) to operable statu If the requirements of 3.5.A.8.a and 3.5.A.8.b cannot be met, declare the protected system inoperable and follow the appropriate action statement for that syste The action statement Tech Spec 3.8.C for the Isolation Condenser system states that if one isolation condenser becomes inoperable during the run mode, the reactor may remain in operation for a period not to exceed 7 days; then the reactor shall be placed in the cold shutdown conditio Subsequent to this finding, the Itcensee commenced an investigation to determine why the snubbers were not welded. Although the investigation was not completed prior to the end of this report period, it was deter-mined that a discrepancy list generated in August 1984 during Isolation Condenser system piping repairs of cracks caused by IGSCC identified missing welds on three snubbers. Two of the three snubbers were those discussed above. The third was inspected by the licensee during this investigation and it was also found to be missing the welds between the lugs and the pipe clam The failure of the licensee to realize that three Tech Spec required snubbers were inoperable resulted in operation of the plant in violation of Technical Specification Limiting Conditions for Operation for a period of at least the entire Cycle 10 operating period. This is a violation (219/86-12-05).

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8 On-Site Review of LERs The following LERs were reviewed to deternine if reporting 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 review and evaluation were complete and accurate, and the LER form was properly complete (Closed) 83-04: Failure of CR0 Feed Pump Breaker to Operate as Designed During a preventive maintenance (PM) bench test of a CR0 feed pump circuit breaker, it was determined that the undervoltage tripping function of the breaker was not functioning properly. The malfunction was attributed to binding and friction of the trip shaft bearings due to oxidized lubrican The inspector reviewed documentation which verified all similar breakers in safety related applications have been disassembled and inspected. Also, the PM frequencies have been revised to require 12 month inspections and a new PM checksheet has been develope (Closed) 83-07 and 83-07/03X-1; SGTS II Declared Inoperable and Removed from Service for HEPA Filter Replacement Standby Gas Treatment System (SGTS) II was declared inoperable du*ing surveillance testing due to a high differential pressure across its HEPA

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filter The HEPA filters and pre-filters were replaced and satisfac-torily teste Subsequent licensee evaluation (83-07/03X-1) showed that apparent high filter differential pressure resulted from (1) corrective maintenance on the flow sensing pitot tube and no post maintenance testing to verify flow curves, and (2) use of a noncontrolled outdated flow curve by operations personne The inspector reviewed documentation which verified flow calibration curves have been revised in appropriate procedures; the LER was made required reading for Maintenance and Construction, Plant Materfel, and Plant Operations personnel; that appropriate personnel have been made aware of the requirement to calibrate flow instruments following repair of sensing elements; and that a memorandum was issued to all Operations personnel regarding outdated operational aid (0 pen) 83-24: Limitorque Motor-Operated Valves Torque Switch Setpoints The licensee reported that during a review of torque switch setpoints of the Limitorque motor operated valves at Oyster Creek, it was discovered that the setpoints on many motor operated valves had been set lower than the manufacturer's data. Further investigation of isolation valves revealed that the torque switch setpoints set during pre-operational testing were found to be lower than the manufacturer's data. In some

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cases, these setpoints were later changed to values lower than pre-opera-tional testing in the course of plant operation as determined through maintenance and surveillance testin In the report the licensee described corrective actions which would be taken on safety related valves prior to plant startu During this inspection the inspector reviewed a GPUN Technical Data Report which documented the actions taken as required by the corrective actions described in LER 83-24. The corrective actions described and the actions taken were as follows:

(1) Completion of the actual design basis investigation -- GPUN obtained from Limitorque copies of the motor operator bills of materials for 57 valves which were identified as isolation and/or safety related valves. These bills of material list the differential pressure used to size the operator and the torque switch setting required to oper-ate the valve against differential pressure. This data is the origi-nal baseline data for the Oyster Creek plan (2) Determine the appropriate torque switch setpoints -- GPUN used an independent third party, Torrey Pines Technology, to do torque switch setpoint calculation .

(3) Resetting the torque switch setpoints on all applicable valves --

GpVN used Motor Operated Valve Analysis and Test System (M0 VATS) to reset the torque switches and test and analyze the 57 safety related valve (4) Issue administrative controls to eliminate recurrence of this incident -- Oyster Creek Nuclear Generating Station Procedure 700.2.010, Motor Operated Valve Removal Installation or Inspection (Elect) has been revised to specify opening and closing torque switch setting The licensee also stated a followup report would be issued following the completion of an investigation of this matter. This item remains open pending receipt of the licensee's followup repor _

( Closed) 83-25: Procedures Did Not Contain Requirement for Verifying Excess Flow Check Valves Open During a review of plant procedures by the licensee, six maintenance and two surveillance procedures were identified as not adequately addressing the Technical Specification requirement that each time an instrument line is returned to service after any condition which could have produced a pressure or flow disturbance in that line, the open position of the flow check valve in that line shall be verifie . - _ - . _ - _ . - . . . _

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These deficiencies were discovered by the licensee during a review of all Technical Specification surveillance procedures to ensure they reflected Technical Specification requirement All excess flow check valves affected by the deficient procedures were verified open prior to returning the associated systems to servic During this inspection the inspector verified corrective action had been taken to revise procedures as necessary. Procedure 603.3.002, 610.3.010, and 703.3.001 were changed to include the Technical Specification require-men Procedures 700.3.007, 719.3.006, 710.1.003 and 719.1.001 have been deleted, and Procedures 700.3.008 and 700.1.004 were determined to not require a chang (Closed) 84-01; Diesel Generator Fuel Oil Tank Level Below Technical Specification Limit After several test runs of the No. 2 diesel generator, the fuel oil tank level was noted as being slightly below the Technical Specification limi The apparent cause was operator error in not properly following up on an apparent low level indication. However, a contributing factor is that the tank capacity is only slightly greater than the Technical Specification limit, and the tank has been overflowed in the pas The corrective action to prevent recurrence was to change procedure 636.4.003 to clarify the requirement to refill the diesel fuel oil tank, and to issue a memo to all operating and supervisory personnel informing them of the revision to the procedure i istructing them to refill the tank after each load test or one hour of operation. In addition, Amendment N has been issued which reduces the Technical Specification required fuel oil amount. With this Technical Specification change, more operating flexibility is provide .(Closed)84-02: Failure of Several Breakers to Trip Upon De-energization of Their Undervoltage Trip Device The licensee reported the failure to trip of three separate breakers during the performance of undervoltage trip time operability and trip bar actuation tests. Immediate corrective action was to perform preventive maintenance on the circuit breakers. The trip shaft bearings were cleaned, lubricated and measured to have a torque of 20 inch-ounce The static time delay units ware readjusted to within specifications and the breakers tested for operability three times before being returned to servic During this inspection, the inspector reviewed documentation which verified that Preventive Maintenance Procedure 761.2.003 was revised to include 'lla appropriate recommendations of GE Service Advice 175(CPPD) Additional actions taken by the licensee to assure operability of undervoltage trip devices is provided in the licensee's response to IE Bulletin 83-0 . .

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(Closed) 84-06; Torus Corrosion Pitting and Missing Structural '4 elds This is a voluntary report submitted by the licensee to discuss the identification or torus pitting and missing torus structural welds. The report also identified the repairs performed to restore the torus to the original as-designed conditio NRC Region I Inspection 84-07 was devoted entirely to the inspection activities associated with the torus shell thickness. In addition, routine inspections reviewed additional aspects of the torus repai Based on these efforts, this item is considered close (0 pen) 84-08; Degradation of Neutron Monitoring Instrument Dry Tubes This report describes the identification by the licensee of cracks found in the neutron monitoring instrument dry tubes. While performing local power range monitoring instrumentation replacement work during a refueling outage, operators visually noticed that the dry tube associated with an intermediate range monitor (IRM) appeared bent near the upper core gri Further investigation revealed that a total of seven IRM and one source range monitor (SRM) dry tubes were cracked. The cracks were located in the thin wall tube surrounding the assembly compression spring and not in a pressure boundary portion of the dry tube. There are a total of 12 dry tube assemblies, 8 IRMs, and 4 SRMs in the reactor vessel. The corrective action was to replace all 12 dry tube During this inspection, the inspector reviewed documentation which showed all 12 instrument dry tubes were replaced during the time period June 3 to July 19, 1984. All SRM and IRM detectors have been verified operationa The LER indicated a supplemental report is expected to be submitted. The expected submission date of this report was October 30, 1984. To date this report has not been submitted. This LER remains open pending receipt of this repor (0 pen) 84-05: Isolation Condenser Piping Leak Near Weld Joint With the facility shutdown during the performance of a post maintenance hydro test, leakage was noted from isolation condenser condensate pipin At the time of the report, plans were being made to determine the cause of the failur The LER indicated a follow-up report would be submitted. The estimated submission date of this report was identified as June 30, 1984. To date this report has not been submitte The follow-up report is to contain: 1.) the results of an investigation to determine the safety significance of this event had the plant been in operation; 2.) the results of an inspection of the entire isolation condenser system piping; and 3.) a description of the corrective actions required. This LER remains open pending receipt of the follow-up repor x

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(Closed) 84-09; Deg_radation of Secondary Containment Both doors of the reactor building personnel access airlock were opened simultaneously by contractor personnel in order to bring a length of pipe into the building. The length of the time the doors were open is unknown, but the duration was believed to have been shor A critique of the incident was held. The individual responsible was dismissed, a memorandum was addressed to all onsite contractor firms to reinforce training on this matter, and signs were posted at each personnel access airlock warning personne (Closed) 84-10; Fuel Pool Gate Movement Above Irradiated Fuel Technical Specifications require that no objects in excess of the weight of one fuel assembly (approximately 485 lbs.) be moved over stored irradiated fuel. During a licensee review of a proposed modification to the fuel storage rack configuration, a question was raised as to whether or not the fuel pool gates (approximately 1800 lbs.) are moved over spent fuel during their removal or replacement. Operations could not specifi-cally cite any one particular instance of this, but they believe that movement of the gate over spent fuel may have occurred several times during past refueling operations. The station procedures used for movement of thes6 gates refers to the reactor building overhead crane operating procedure for control of loads over irradiated fue To prevent recurrence, Station Procedure 756.1.004, Fuel Pool Gates Removal and Installation, has been revised to caution that fuel pool gates shall at no time be moved over irradiated fuel. Also, a memo was issued to all Productio.1 Group Maintenance Supervisors and Mechanics informing them of these requirement (Closed) 84-11; S andby Gas Treatment Systems I and II Simultaneously Inoperable Goth trains of the Standby Gas Treatment System (SGTS) were inoperable for nine (9) minutes while performing preventive maintenance on a circuit breaker. The maintenance required that the circuit breaker for a motor control center be racked out, which secured power to the emergency exhaust fan and the inlet, outlet, and orifice valves of SGTS II. This made SGTS II inoperable. The three (3) valves in the SGTS II failed open due to the loss of power, which permits recirculation flow through train II from train I upon initiation of SGTS This caused SGTS I to also be considered inoperable. The event occurred due to Operations management misunderstanding of the extent of the temporary change associated with a plant modification involving the SGT To prevent recurrence, a plant modification has been made which makes each SGTS train electrically independent. The air operated valves for each train fail close on loss of electrical power to the respective fans. Also, a re-evaluation of the method used to inform personnel of

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the status of plant modifications was conducted. The evaluation con-cluded existing procedures and the use of " Nite Orders" are sufficient to insure that plant personnel are informed and trained on system /

equipment modification (Closed) 84-12; Both Emergency Diesel Generators Simultaneously Inoperable During a scheduled load test on Emergency Diesel Generator No.1 (EDG-1),

a diesel fuel oil day tank low level alarm was received in the Control Roo Subsequent investigation revealed that the diesel fuel oil transfer pump control switch for EDG-1 was in the Off position. In the Off position, fuel oil is not automatically transferred to the diesel day tank from the main fuel storage tank. This resulted in EDG-1 being considered inoperable. Since EDG-2 was out of service for governor repairs, both emergency diesel generators were simultaneously inoperabl To prevent recurrence, plant tour sheets were revised to incorporate a check of the transfer pump control switch positio (Closed) 84-25; Inadvertent Initiation of Core Spray System During Reactor Low-Low Sensor Calibration During a calibration of reactor water level sensors for Core Spray System II, Core Spray System I was inadvertently initiated and injected torus water into the vessel for approximately 20 seconds. The cause of the occurrence is attributed to personnel error. Personnel were perform-ing sections of the procedure out of the as-written sequence, accidentally omitted a key step, and erroneously performed a step on the wrong instru-ment. Another cause of the event was the amount of temporary changes to the procedure being used. The procedure was changed extensively, primarily to delete steps not needed for the low-low sensor calibratio A critique was held immediately following the event and certain corrective actions were specifie During NRC Inspection 50-219/85-11, it was noted that no corrective actions had been initiated until the time of the inspection (March 28, 1985, four months after the event). Durir.g this inspection, the inspec-tor verified corrective actions had been made which consisted of changes to Station Procedure 116, Surveillance Test Program. This change was to reflect that procedures will be performed in the as-written sequence and that the person responsible for performing the test sign that the proce-dure has been completed in its entirety. Also, this LER was made required reading for Control Room Operator (Closed) 84-29; Cask Lift with Unadjusted Crane Vertical Limit Switches While performing an initial training lift and movement of a spent fuel shipping cask above the top of the Cask Drop Protection System (CDPS),

the two crane vertical limit switches were not properly adjusted and were manually overridden. Technical Specifications require vertical

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l limit switches to be operable during cask movement above-the top of the CDPS to limit the height of the cask to no more than 6 inches above the CDP The causes of the event were determined to be lack of detail in the cask handling procedure, inadequate supervision of craft personnel, and inadequate instruction of personnel on Technical Specification requirements relative to cask handlin After it was noticed that the limit switches were not set, the cask was removed from above the CDPS and lowered to the refueling floor on a safe load pat A critique was held to discuss all noted deficiencies. Corrective actions were initiated and completed prior to further cask movement. These corrective actions included instructions to personnel, procedure changes and the proper setting of the limit switches. These corrective actions were verified at the time of the occurrenc (0 pen) 84-31; Failure of Main Steam Drain Valves to Operate During performance of the Main Steam Isolation Valve (MSIV) closure and In-Service Test (IST), three of four Main Steam Drain Valves (106,107, 110) failed to operate when given appropriate signals. The valves partially opened and would not reclose. Two valves were closed by bypassing their control circuits (106, 107) and the third valve (110)

was manually closed. These valves were deactivated and secured in their isolated position as required by TS 3.5. The apparent cause of this occurrence was the opening of the torque switches, interrupting operation of the valves. The cause of the torque switches opening is unknown at this tim The immediate corrective actions were to close, deactivate, and tag out of service all three valves, as required by the T This LER was reviewed during inspection 85-11. At that time, the LER remained open pending the completion of a licensee investigation to determine the cause of the event and the submittal of a follow-up repor It is expected that the licensee will complete his investigation of the valve failures during this outage. This item remains open pending receipt of the licensee follow-up repor (Closed) 85-02: Two Inoperable Containment Isolation Valves in a Single Penetration During a planned shutdown, Reactor Water Cleanup System isolation valve V-16-1 was required to be taken off its backseat. An electrician was dispatched to the motor control center supplying the valve to engage the closing contactor. To prevent full closure of the valve due to a seal-in closing signal, the electrician manually tripped the breaker. The breaker

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trip caused the cleanup recirculation pump to trip, which in turn caused a cleanup system isolation on low flow. A second isolation valve V-16-14 failed to fully close on the system isolation signal, resulting in two inoperable isolation valves in a single penetration. The second valve failed to close due to its lantern ring being damaged which caused the stem to bin A violation was issued in NRC Inspection Report 85-23 for making the automatic isolation function of a containment isolation valve inoperable when it was required to be operable. NRC staff follow-up on licensee corrective action for this violation will be reviewed in a future inspectio During this inspection, it was verified that the corrective action specified in the LER was taken. This corrective action consisted of placing a sign at the breaker for valve V-16-1 that indicated opening the breaker caused a clean-up system recirculation pump trip, and revising Standing Order No.33, Backseating/Unbackseating of Valves, to provide instructions for the proper unbackseating of valve V-16- (Closed) 85-03; Design Deficiency in Core Spray Pump Logic On January 29, 1985, a design deficiency was discovered in the Core Spray system booster pump failure logic. Discharge pressure of the booster pumps is utilized to detect a booster pump failure which will trip the failed pump and provide a start signal to the backup booster pump. Two events were identified which can cause this instrument to misinterpret Core Spray system status and result in the system not performing according to its original design intent - the detection of loss of flow from the Core Spray booster pump. The cause of this occurrence was a deficiency in the original plant desig Corrective action consisted of performing a modification to replace the pressure switches on the booster pump discharge with differential pressure switches. The differential pressure switches will sense differential pressure across the booster pump. This modification allows the pump failure logic to perform as originally designed under all postulated condition The modification was verified to have been installed prior to the startup from the plant shutdown which commenced on February 2, 198 {C.losed)85-04: Violation of APLHGR Limit On Janttry 10, 1985, it was noted that the Power Shape Monitor System (PSMS) calculated TIP traces were under-calculating the reactor axial neutron flux profile when compared to measured TIP traces and PSMS model performance was beyond established acceptance criteria. An investigation commenced immediately to confirm the observation and determine the cause of the different flux values. The reactor rod pattern was adjusted on

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January 15, 1985 in an attempt to reduce the high flux peaks. On January 24, 1985, a complete set of TIP traces were taken to determine if the adjustment reduced the peaks and improved model performance. Upon review of this TIP set, it was noted that flux peaks remained high and PSMS model performance was still outside the established acceptance criteria. At this time, it was suspected that the APLHGR Technical Specification limit was violate Once it was determined that the Technical Specification limits on APLHGR had been exceeded, core thermal power was reduced and the control rod pattern was reconfigured to reduce power peaking. The flattening of the power distribution was sufficient to eliminate the Technical Specification violatio The causes of the violation were that the bottom flux peaks which existed at the facility during the month of January were beyond the limits of the PSMS Cycle 10 model and resulted in the under calculation of the peaks,

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and the PSMS software did not permit the LPRM feedback option to function, even though the option was turned o The corrective actions consisted of improved procedural control which would more frequently evaluate the PSMS nodal model accuracy and performance; specification of immediate corrective action when PSMS performance is outside acceptance criteria; and strict adherence to operational guidelines during core operations will reduce measured TIP peaks and reduce average relative axial power shape; and more frequent performance of individual TIP traces during power maneuverin Discussions with Core Group personnel verified that all corrective action has been incorporated into various facility procedures. The corrective actions were incorporated into procedures over a period of time to coincide with major procedure revisions. Core group personnel stated all procedure changes required as a result of this LER have been mad (0 pen) 85-06: Reactor Scram Due to Low Water Lovel

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On February 24, 1985 an automatic reactor scram occurred due to low reactor water level during a plant startup. The reactor was operating at a power level of 400 MWt with level and pressure being controlled automatically. A planned drywell inspection for steam leaks required reactor power to be less than 10% with steam flow minimized. In preparation, rods were inserted to decrease power. The rod movement caused a level, power, and pressure transient which ultimately led to an automatic scram on low level despite operator attempts to stabilize the transient. All plant systems responded as expected and control room operators brought the plant to a shutdown conditio The root cause of the event was determined to be operator error in

, introducing a too-rapid decrease in reactor power and the inability of the

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Corrective action for this event was described as adding a caution to the drywell access procedure alerting the operators to the sensitivity of level and pressure to power changes at low power conditions. Also, plant startup and shutdown procedures will be reviewed for applicability of this cautio During this inspection it was determined that following the issuance of this LER on March 27, 1985 a Licensing Action Item was issued to Plant Engineering on April 1, 1985 tasking them with implementation of the corrective actions. Plant Engineering on June 18, 1985 issued a Technical Functions Work Request asking Technical Functions to implement the corrective actions. At the time of this inspection, 15 months after the event, corrective actions consisting of procedure changes had not yet been mad (Closed) 85-07; Failure to Sample Tank On March 20, 1985, during a routine Technical Specification surveillance, it was discovered by the Plant Chemistry Department that the outside floor drain sample tank was being used but had not been sampled since March 13, 1985 This was in violation of Technical Specifications which require this tank to be sampled every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> unless it has been valved out of service after determining its radioactive content. Upon discovering that the tank was being used but not sampled, a sample was taken to cenfirm that the tank did not exceed the applicable Technical Specification maximum curie limi The event resulted from Chemistry not being told when the tank was placed back in service after it had been isolate To prevent recurrence, certain procedure changes were mad The inspector verified that a precaution / limitation had been inserted into procedures to ensure that the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Technical Specification sampling is met and that either the Manager of Radwaste Operations or Chemistry is notified prior to the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> time limit, if this requirement cannot be met for any reaso This change was made in Revision 11 to Procedure 351.1, Revision 12 to Procedure 351.2, and Revision 1 to Procedure 83 (Closed) 85-08: 4160V Emergency Bus Technical Specification Violation A Plant Engineering review of Technical Specification Amendment 80 found that existing procedures did not meet the new Technical Specification requirements and calibration tolerance Existing calibration documentation was reviewed for the degraded voltage relays and degraded voltage relay timers. Although they were found to be within the acceptable tolerances stated in the existing procedures, the procedures had not been revised to incorporate the recently issued Technical Specification requirements. The Amendment was effective on the date of issuance and did not provide for an implementation period in which to revise the procedures. Immediate action was taken to temporarily change the procedures required to ensure compliance with the Technical Specification Amendmen I

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l The inspector verified that appropriate procedures have been prepared to implement the Technical Specification change.

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(0 pen) 85-09; 480 Volt Bus Overload As the result of an electrical load study performed for Oyster Creek, it was determined that 480 Volt Unit Substation 1A2 or 182 may be overloaded during a loss of coolant accident with offsite power available and

! concurrent loss of one Unit Substation. The cause of this deficiency has been determined to be a design problem because the impact of plant modi-fications on bus loadings was not evaluated for this particular set of condition If the Unit Substations are run in the anticipated overload condition, it will result in decreased transformer life. Corrective actions are planned to install fans to increase transformer capacity and install an overcurrent alarm for the buse An alarm indicating overcurrent on each of the Unit Substations has been installed. This alarms in the control room and the alarm response procedure instructs control room personnel to shed unnecessary load Fans will be added to the transformers for the Unit Substations. These fans will increase the capacity by 15*4 and bring the anticipated worst case loading within the rating of all the Unit Substation components. The fans will be installed during this outag This item remains open pending l the installation of the fans.

(0 pen) 85-10; IRM Setpoints Exceeded Technical Specification Limits While reviewing "as found" data on IRM setpoints, it was discovered by the licensee that some upscale scram and upscale rod block setpoints had slightly exceeded the allowable Technical Specification limit. The apparent cause of this occurrence was the inadvertent deletion of the IRM calibration procedure. Since the deletion of this procedure, the IRM

< drawers have been calibrated during refueling outages using vendor manual instructions with the "as found" and "as left" setpoints not documente An appropriate procedure, 620.3.007, Mean Square Voltage Wide Range Monitor (IRM) Bench Calibration, which documents "as found" and "as left" setpoints has been prepared. Also, a modification is being evaluated to permit testing trip settings during weekly front panel test This item remains open pending the installation of this modification.

(0 pen)85-11
Three of Four Isolation Condenser _ Actuation pressure Sensors

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During routine surveillance testing, 3 of 4 isolation automatic actuation pressure sensors tripped at values slightly greater than specified in the Technical Specifications. The cause has been attributed to instrument drift. The immediate corrective action was to reset the trip setpoints within desired limits. Replacement of these sensors with ones having better setpoint repeatability is scheduled during the Cycle 11 refueling outage. This item remains open pending replacement of these sensor . .

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(0 pen) 84-26; Emergency Service Water Containment Spray Negative Delta Pressure This report describes a condition which has existed for sometime. In particular, the differential pressure between the Emergency Service Water (ESW) and Containment Spray (CS) is such that the CS water pressure is higher than the ESW pressure in the CS heat exchangers. This would, following a loss of coolant accident, permit radioactive CS water to leak to the environment if a heat exchanger leak were present. This condition is also contrary to that described in the Facility Description and Safety Analysis Report. A Notice of Violation relative to this matter was also issued on March 14, 198 TheLElknotesthecauseofthenegativedifferentialpressureisbelieved to be a decrease in ESW pump performance and increased pressure drop in the ESW piping. Subsequent evaluation by the licensee in reference to Licensing Action Item 84208.01, documented that the negative pressure differential across heat exchanger tubes is the result of degraded pump performance and increased resistance due to biological fouli The licensee performed a safety evaluation to estimate the offsite dose due to leakage from the CS' System during a loss of coolant accident.. The evaluation concluded the existing condition will not significantly affect the safety of the public or plant personnel. However, the evaluation specifically notes the condition allows the possibility for a lingering effect of radioactive iodine deposition to the environment after a loss of system coolant accident. Therefore, the system will be returned to its original design prior to startup from the 11R refueling outage (that is, emergency service water at a higher pressure than the Containment Spray System).

! The LER also indicated a supplemental report would be submitted, with the expected submission date being June 30, 1985. This LER remains open pending the receipt of the licensee's supplemental report and verification of proper differential pressure between the shell and tube side prior to startup from the 11R refueling outag .(Open) 86-04 Reactor Scram on Anticipatory Turbine Trip Caused by Limit Switch Failure

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This LER, in addition to reporting the reactor scram, also reports a Technical Specification violation associated with failure to close and deactivate a containment isolation valve in the same penetration with an inoperable containment isolation valv During this inspection, the circumstances associated with the licensee's decision to declare a containment isolation valve operable following its apparent failure after the reactor scram on March 6, 1986 were reviewed.

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As noted in the LER, "At 0236 Reactor Water Cleanup system containment isolation valves were opened to attempt a restart of the cleanup system in order to control water level. A high pressure isolation occurred but V-16-14 did not fully close as noted by double valve indication. The torque switch was jumpered out and the valve closed."

Also, the Licensee's Deviation Report prepared in association with the testing of V-16-14 states, in part, "All valves isolated properl In the process of restarting RWCU a second system isolation occurred on high pressure. This time V-16-14 did not fully isolate (double indication). An electrician was called and he had to jumper out the torque switch to close V-16-14."

The Post Trip Review Group recommended prior to restart that discrepancies with V-16-1 and V-16-14 be correcte In order to affect this corrective action, Maintenance and Construction Short Forms SF34723 and SF34275 were written. SF34275 was written to perform M0 VATS testing of V-16-14. The Short Form (SF) indicated that MOVATS current traces obtained for V-16-14 were found to be acceptabl MOVATS switch signatures were judged not to be required. The malfunction /

cause described on the SF initially was "under sized motor," but it was subsequently changed to "possible under sized motor" upon further review by the license The current values obtained on March 6, 1986 and previous values obtained on November 15, 1985 were noted as follows for V-16-14:

3/06/86 11/15/85 0C* CO** OC C0 Start Current 39.5 A 42.35A 35.6A 36.85A Avg. Run Current 7.35A 8.4 A 7.2A 8.5 A May Run Current 7.35A 8.8 A 8.8A 9.8 A End Current 32.15A 8.8 A 31.9A 8.55A

  • 0C -- Valve moving from open to closed
    • C0 -- Valve moving from closed to open The TFWR associated with V-16-14 was written on November 22, 1985, and described results of some previous testin The TFWR noted that on November 15, 1985, the operator was unable to obtain the recommended minimum thrust values and that any increase in torque switch setting would result in the motor running continuously after completion of valve travel because the motor would never generate enough torque to trip the torque switch. Additionally, the TFWR stated that the motor capability was marginal. The TFWR also notes the motor pinion and worm shaft gears of the operator were changed. This increased the capability of the motor but it is still considered marginal. The TFWR requests Technical Functions to review the feasibility of increasing the motor, cable, and starter size for V-16-1 _ _ _ _ - _ _ _ _ - _ _ _ _ - _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _-______ _ __ _____ __- ___ _ ___ _____ _ _ - _ -

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Additional information relative to the performance of V-16-14 was obtained from a review of the valve maintenance history and a memorandum dated March 17, 1986, from Plant Engineering to Technical Functions which provided a history of V-16-14 failures. This information is summarized as follows:

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The operator currently on the valve was installed during the 1983-1984 outag February 2,1985, the valve failed to fully close. This was attributed to mechanical binding causing the torque switch to ope The cause of the binding was due to a damaged lantern rin June 12, 1985, V-16-14 failed to open due to a motor overload tri Later, when closing the valve the close contactor would not drop out and an operator present at the motor control center had to trip the breaker manually. The cause of this failure to trip was attributed to a loose set screw which allowed the torque switch setpoint to drift to a higher value. At this higher value, the motor was unable to trip the torque switch open. It was noted that previous M0 VATS testing had shown the motor to be marginal and that it would not trip the torque switch at higher thrust values. LER 85-12 identified the valve's failure to open following a June 12, 1985 reactor trip. This was attributed to insufficient torque due to improper gear ratios in the operator. On June 15, 1985 the motor pinion and worm gears were changed to increase the motor torque. Tests showed torque increased, but is was still considered margina Valve thrust data after gear replacement was reviewed and noted to be as follows:

Recommended Thrust Values Minimum Normal Maximum Open 15956 21164 23280 Close 8346 10582 11640

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Recorded Thrust Values Open Close Date 10283 10442 10/03/84 15955 11493 02/13/85 10530 11237 11/15/85 As can be seen, little improvement was noted following the gear replacement.

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November 10, 1985 a broken stem nut was identified. This failure was not attributed to the motor or torque switch. Also, the spring pack lock-nut was found loose. Testing following the repair again showed the motor was unable to trip the torque switch open at higher setpoints and thrust value November 22, 1985, the motor for V-16-14 was replaced with an identical motor from V-17-57. The motor was replaced due to damaged wiring incurred while re-installing the motor after troubleshooting for a ground. Current signatures indicated the same characteristics

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as the original motor current signature March 6, 1986, the failure described in this LER 86-04 occurre A follow-up memorandum to the TFWR from Technical Functions dated May 1, 1986, which was not available to the reviewer on March 6, 1986, indicated that Limitorque, the operator vendor, stated the operator should provide sufficient torque (thrust) to satisfy its application. They feel that if the operator is not providing sufficient output, then there must be a problem in the operator, motor, or its power supply. Additional data presently available on site shows that a new identical operator tested by Limitorque is providing approximately twice the thrust the installed operator is providing. Further evaluation of this new operator is planned when it is installed on V-16-14. Also, the valve is scheduled for inspection during this 11R outage.

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Since the valve had apparently failed to close on March 6,1986, and that no changes or repairs had been made based only on a MOVATS current trace which showed the currents were essentially the same as they had been prior to the failure, the inspectors questioned the licensee on his basis for declaring V-16-14 operabl The licensee provided the inspectors the basis by which the valve was declared operable during a meeting with representatives of Plant

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Engineering and Operations personnel on June 3, 1986. The licensee's position is summarized as follows:

The licensee felt, ba2ed on the available data at the time of the trip and the post trip review, that it was not clear as to whether V-16-14 failed to open or failed to close. To be conservative they declared the valve inoperable and decided to obtain a MOVATS current signature of the valv The current signature indicated there were no problems. Based on this data and subsequent satisfactory operation of V-16-14, the valve was declared operable. The decision not to perform additional troubleshooting appears to be related to the ambiguity as to what actually happened with V-16-14 and the understanding by many people at the time just after the event until after restart, that the valve failed to open, not close. The licensee stated V-16-14 will be thoroughly inspected and tested prior to restart from the 11R outag ,

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23 j In fact, V-16-14 did fail to close. It's closing torque switch tripped and left the valve in an intermediate position. This occurred when V-16-14 was being jogged open and a Reactor Water Cleanup system isolation signal was received. It is incumbent on Plant Engineering to address this scenario and determine if a problem exists such that if the torque required to reverse the valve direction is greater than the setting of the torque switch, then V-16-14 will always fail to close in this scenari Differential pressure across the valve also needs to be included in the scenari The NRC staff will continue to follow this matte ( '

(0 pen)84-007; Failure to Test a SGTS Train Within Required Time During a refueling outage, a diesel generator (DG) was declared inoperable as a result of a monthly surveillance failure. This required testing the redundant standby gas treatment system (SBGTS) train, since the DGs are the emergency power source for the SBGTS. The redundant train was not tested for ten hours dn to a procedure limitation as a result of torus painting. Technical Specifications require testing the redundant train within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. This was not accomplished and handling of irradiated fuel continued on the refueling floor in violation of Technical Specification requirement In response to this, GPUN licensing committed to request a revision of Technical Specifications by November 15, 1984. Technical Specification Change Request (TSCR) No. 133, was submitted January 30, 1986 over one year late. The commitment was made to clarify the fechnical *

Specifications with regard to surveillance requirements and backup power supply. LER 84-7 stated as part of the corrective action that "a change to the Technical Specificationis will be investigated to ascertain if the more restrictive Technical Specifications regarding normal or emergency power supply requirements in the snutdown or refuel modes.can be eased or clarified." TSCR 133 requested a change in the time to test a redundant SBGTS train from two to twalve hours if a SOGTS train is inoperable and significant painting, fire, or chemical release has taken place in the reactor building. TSCR 133 did not clarify the Technical Specifications with regard to normal or emergency power supply requirement In addition, no clarification was provided on moving irradiated fuel untti the SBGTS operability has been determine Furthermore, the licensee has traditionally interpreted and so states in LER 84-07, that Techniccl Specification 3.0.B is more restrictive during shutdown or refueling with regard to inoperability of power sources than during normal operation This refers to the last sentence in 3.0.8,

"This specification is not applicable in cold shutdown or the refuel mode." which the licensee has intenreted to mean that during these modes both normal and emergency power supplies are required for a system to be~

operable. During normal operation, 3.0.B allows system to be considered operable if either the normat or emergency power source is inoperable and the redundant train is operable. The last sentence in 3.0.B could also

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be taken to apply to only the preceding sentence, which requires the plant to proceed to cold shutdown if 3.0.B is not satisfied; thus negating the requirement to proceed to cold shutdown if that is the plant's present mode of operation. The licensee has applied 3.0.B in cold shutdown and refueling to require an operable emergency power source. The licensee has agreed to change the applicable section of the technical specification for clarification. This LER will remain open pending generation of a Tech-nical Specification that addresses normal and emergency power supply requirements during all modes of operation, including shutdown and totally defuele Summary A total of 29 LERs were reviewed during this inspection. Seventeen of the 29 are considered closed. Four LERs, 84-31, 85-09, 85-10, and 85-11, are

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expected to have specified corrective actions completed during this outage, with 84-31 having a follow-up report du Report 85-06 remains open pending the completion of the specified '

corrective action. As noted above, corrective action consisting of procedure changes has not been implemented 15 months after the even One LER, 86-04, had only the circumstances associated with declaring a containment isolation valve V-16-14 operational following a valve failure reviewed. The NRC wiil continue to follow up this matte Four LERs, 83-24, 84-08, 84-05, and 84-26 have been identified by the licensee as having supplemental reports due. The expected submission date for the 83-24 supplemental report was not specified. However, expected supplemental report submission dates for the other three LERs were October 30, 1984; June 30, 1984; and June 30, 1985. None of these supple-mental reports have been submitted. This failure to submit supplemental reports in a timely manner was discussed with licensee representative . Review of Periodic and Special Reports Upon receiot, periodic and special reports submitted by the licensee pursuant totTechnical Specification requirements were reviewed by the inspectors. This review included the following considerations: the report includes the information required to be reported to the NRC; planned corrective 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 March and April 1986

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Special Report 86-01 dated 4/20/86 regarding failure to restore a non-functional fire barrier penetration seal to functional status within 7 days from time of discover .

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Special Report 86-02 dated 5/13/86 regarding temporary deactivation of fire detection and automatic halon fire suppression systems serving the 480V switchgear room while room undergoes Appendix R modifications. The report stated a continuous fire watch has been established as required by Tech Spec . 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 In accordance with the requirements of 10 CFR 73.71, the licensee reported a moderate and a major loss of physical security during this report period. The moderate loss of physical security involved a short-lived (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 16 minutes) situation in which less than the required number of intrusion detection systems were it, service for a portion of the protected area fence. This event occurred when portions of the protected area fence were relocated to include several contractor trailers in the protected area. Upon realization of the problem, it was immediately corrected and a search of the protected and vital areas performed. No problems were identifie The major loss of physical security occurred when access to a vital area was obtained by an unauthorized individual. This violation was identified by a member of the security force as the unauthorized individual was leaving the vital area. Subsequent investigation determined the individual was a contractor supervisor who should have had authorization in order to supervise employees under his direction who were working in the vital area. An investigation of the infraction was conducted and corrective action implemented.immediatel Based on the facts that the licensee self-identified both problems and took prompt and comprehensive corrective action, the inspectors had no further concerns regarding either matte . Review of Concrete Anchor Bolt Test Data Associated with NRC Bulletin 79-02 The resident inspectors conducted an inspection at the GPUN Corporate offices in Parsippany, NJ to review test data regarding installation and performance of concrete expansion anchor bolts in seismic piping system What precipitated this inspection was the licensee's stated intention to exclude 157 baseplates and their associated anchor bolts from current Bulletin 79-02 reinspection efforts based on data gathered during their initial efforts to address this Bulletin. The licensee's current reinspection program for pipe support base plates using expansion anchor bolts is in response to the findings from Inspection 50-219/85-14

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conducted May 14-17, 1985 which identified deficiencies in the original ir.spection effort which commenced in 1979 and finished in 198 In 1979 the licensee generated Special Procedure No. 79-31, Rev. 1, Inspection Test and Installation Procedure for Concrete Expansion Anchor Bolts in Seismic Piping Systems._ This procedure required pull testing of anchor bolts to verify that Bulletin 79-02 factors of safety could be me It also required that anchor bolt installation data be recorded. The inspection reviewed a sampling of the data to ensure it was sufficient to meet Bulletin requirement The discrepancies identified during the inspectors' review of anchor bolt test data for baseplate installations associated with pipe supports in the Isolation Condenser (211) and Core Spray (212) systems are listed in the below table. It should be noted that all anchor bolt installations reviewed were shell type. The support identification is listed in the left hand column and the anchor bolt test data discrepancies associated with that support are indicated by a 'X' under numbers 1-10 in a row across the table. Each number represents a different discrepancy as defined at the end of the tabl Anchor Test Data Discrepancy Table Discrepancy Type Support Number 1 2 3 4 5 6 7 8 9 10 212-BP.368.R10. X 212-BP.368.R2.15A X 212-BP.NZ.2.H12.3 X X X 212-BP.368.R3.4 X 212-BP.NZ.2.H30.5 X X 212-BP.41.1.RI.60A 212-BP.NZ.2.H26.64A X X X X 212-BP.NZ.2.H32.93A X X 212-BP.411.R9.7 X X X 212-BP-NZ.2.RSA.97A 212-BP.NZ.2.H52.4 X X X 212-BP-NZ.2.R16A.30A X

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Support Nu:nber 1 2 3 4 5 6 7 8 9 10 212-BP.368.R6.2 X 212-BP.368-RS.21-A X X 212-BP-368.R9 X 211-BP-634-R9-28-A X 211-BP-632 .R4.48-A X 211-BP-NE-1-H5.5 X 211-BP-632.RI.5 X X 211-BP-633-R6.6 X X 211-BP-NE-1-H10.6 X X X 211-BP-633-R1.7 X X 211-BP.633.R2.7 X 211-BP.634.R3.1 X X 211-BP.NE.1.H4.4 X X 211-BP.634.R2.1 X Key To Discrepancy Types Incorre;t plate bolt hole size for anchor siz In most cases the allowable hole size was greater, but in a few examples, the plate bolt hole size recorded was smaller than the anchor bolt which was obviously erroneous dat . The distance from the top of shell to the top of the red head does not meet manufacturer's recommendation . Shell embedment depth does not meet manufacturer's recommendation . Dial indicator measurement of anchor bolt displacement during pull testing indicates an anomal . Thread engagement measurement of bolt into shell not provide . Bolt spacing may be less than required for 100% capacit . Test loading insufficient to satisfy Procedure 79-31 requirement _ _. __ __ _-

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28 Insufficient thread engagement, i.e., bolt is threaded into shell less than one bolt diamete . Edge distance between anchor bolt and concrete may not be sufficien . Disagreement between field data sheets and design drawing The number of discrepancies found in anchor bolt data as illustrated above indicates that the licensee should analyze the data for acceptabilit prior to excluding these installations from future inspection activitie Generally, the data reviewed indicated that the pull test data was acceptable with some exceptions. In several cases the pull test indicated zero displacement for each successive increased load (212-BP.NZ.2.H26.64A; 212-BP.NZ.2.H52.43A; 211-BP.633.R1.73A), and, in one case, the displace-ment decreased with increased load (212-BP-NZ.2.H30.56.A). These installations should be re-eyamine Some other anchor bolts were not tested to the required loading (Discrepancy No. 7). If additional piping support analysis reveals that the analyzed loading exceeds the loading the anchor bolts were tested to, then these anchor bolts will have to be retested to the new loading. In addition, the manufacturer's ultimate pull out load versus concrete strength data for the anchor bolts and the concrete strength for Oyster Creek Nuclear Generating Station were not available. This data is necessary to determine the factor of safety the licensee's testing verified. The licensee stated that they would provide the necessary information to the resident inspectors so that a determina-tion of the factor of safety could be made and this value then compared to the Bulletin required factor of safety of five for shell type anchor (219/86-12-05)

The licensee stated that they plan to conduct a complete review of the anchor bolt data from the 1979-80 inspection for the 157 baseplates in question to ensure the data is meaningfu . Surveillance Testing During the observation of a diesel generator load test surveillance (Procedure 636.4.003), the inspector noted the copy of Procedure 341, Standby Diesel Generator Operation, posted in the diesel switchgear room was outdated. The current procedure revision at the time was Revision 19, while the posted procedure was Revision 18. The purpose of Procedure 341 is to provide detailed instructions for the operation of the Standby Diesel Generators. The licensee determined this was an administrative error and that no adverse operating conditions occurred as a result. The proper revision was posted in the diesel switchgear roo . Presentations The inspectors attended a briefir.g on Technical Manual review conducted by the vendor document control section of Technical Functions Engineering Assuranc . - _ _ - - . -- .

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29 TMI Action Plan Requirements Item I.A.I.3, Shift Manning The inspector reviewed the licensee's Technical Specifications and Procedure 106, Conduct of Operations, to determine if overtime restrictions were incorporated in the document In addition, the recorded working hours for Senior Reactor Operators, Reactor Operators, Equipment Operators were reviewed for May 1986. In both the Technical Specifications and Procedure 106, the licensee had incorporated the overtime restrictions and had appropriately specified the minimum shift requirements. The licensee has implemented a program to track shift operators' working hours to insure the overtime restrictions are followe The review of the working hour records revealed that one equipment operator had worked 80 hours9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> in a seven day period with prior approval of department management. This item is close . Inspector Observations of 11R Outage Activities Defueling The inspectors observed activities leading up to and including complete defueling of the reactor core. The activities were conducted in a controlled fashion using approved procedures. The assignment of an individual to coordinate refueling floor activities aided in this generally trouble-free sequence of activitie Problems were encountered when two of three stud tensioners used to de-tension the reactor head studs broke down and when minor breakdowns of the fuel handling bridge occurred. These were considered minor problems with little impact on the schedul Local Leak Rate Testing Shortly after plant shutdown on 4/12/86, local leak rate testing (LLRT) of containment isolation valves commenced. The LLRT results for the MSIVs indicated a minor packing leak on one valve and no seat leakage past any valve. Historically, at least one MSIV has been found with seat leakage. The fact that there was no seat leakage past any MSIV is an Oyster Creek first and precluded having to rebuild two MSIVs as originally planned for in the 11R schedule. Not all valves tested passed, however. Containment isolation valves in the RBCCW, Reactor Water Cleanup, Torus Vent systems, in addition to l others, failed and will have to be repaired. The licensee is j required by Appendix J to 10 CFR 50 to submit a final report of their test results which will document all the valves that failed LLR Fuel Sipping The licensee contracted with GE to perform an inspection of the fuel bundles just removed from the core to determine which leake The process used by GE is called fuel sipping. The process involves placing a fuel bundle in a chamber, sealing the chamber, then forc-ing air bubbles past the fuel elements in the bundle. The air i

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strips away any leaking gases from the surface of the fuel elements thel flows out the top of the chamber into a radiation detector that peri.irms an analysis to determine gaseous radioactivity. The liceisee decided to perform. fuel sipping because of increases in gastous activity found in reactor coolant samples that commenced in February 1985. This increase in gaseous activity was considered a precursor of leaking fuel elements. Of 536 fuel bundles sipped, 47 were determined to be leaking. Additional follow-up as to the cause of the leaking fuel elements will be performed in a subsequent inspection (219/86-12-06).

During fuel sipping operations in the early morning hours of 5/29/86, area radiation monitor alarms (ARMS) sounded on the refueling bridg At the time the ARMS alarmed, the bridge was positioned on the south side of the spent fuel pool directly in front of the spent fuel pcol gates. The fuel handling grapple was latched on a fuel bundle. The bridge operator disregarded these alarms because he felt they resulted from shine from the vessel cavity which was cry. He pro-ceded to lift the bundle out of the spent fuel storage rack and move it to the sipping cannister. Unknown to the operator at the time, the C-5 criticality monitor alarm on the refueling floor started to alarm both locally ano in the control roo The C-5 criticality alarm has a similar sound as the bridge ARM and was not noticeable as a unique alarm. When the alarm was received in the control room, the GSS followed procedural requirements to investigate the alarm. When he got to the ARM instrument readout, the reading was normal. He felt the alarm was spurious based on not getting a phone call from the bridge operators. Unknown to the bridge operators, personnel friskers in various plant locations alarme This sequence of events happened a second time, when the next fuel bundle was moved to the sipping cannister and then two additional times when the bundles were returned to the spent fuel storage rack It was not clear whether the C-5 criticality monitor alarmed more than once. Out of curiosity, the bridge operators obtained a R0-2A meter to check the radiation level on the bridge when they lifted the second fuel bundle out of the spent fuel racks. The reading peaked at 800 mr/hr. The operators on the bridge communicated the fact they received radiation alarms on the bridge to the GSS in the control room after the second fuel bundle was in the sipping cannister. The GSS did not mentally correlate these alarms with the C-5 criticality alarm received earlie Meanwhile, Radcon personnel were attempting to identify the source of the radiation that was setting off the alarms. They contacted the control room but the GSS had not recognized the problems on the refueling floor because of poor communications with the bridge operators. The Radcon technician on the refueling floor, when questioned as to the existence of any radiation problems, stated there were none. He was mislead to this conclusion based on ,

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normal and his misunderstanding that no fuel was being move Radcon continued their investigation for the balance of the shift. Movement of the problem fuel bundles commenced about 0300 and fuel sipping for that shift was completed about 034 Upon resumption of fuel sipping on day shift, the problem was finally identified. Specifically, radiation streaming through the spent fuel pool gate occurred when the fuel bundles reached the elevation of the gate as they were lifted out of the spent fuel racks. The streaming was unimpeded by shielding and, therefore, caused the various alarms

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to initiate. The amount of time involved with the bundles in this location was minimal as they were moved away from the south wall to the north wall as soon as they were lifted out of the spent fuel racks and were lowered back into the spent fuel racks after completion of sippin The licensee held a critique of this occurrence which a NRC inspector attended. The critique revealed a series of communication and procedural problems. The critique was effective in establishing the problem areas and adequate corrective action was propose Based on the effective critique and the fact that no personnel overexposures or significant unplanned exposures occurred, the inspectors had no further concerns regarding this matte D. Chemical Decontamination Removal of radioactive material from inside the Recirculation system piping was performed by the licensee to lower the radiation levels inside the drywell. This action is consistent with good ALARA policy and will result in many man-rem savings during subsequent drywell work activities. The process used has been used successfully at other nuclear plants and involves injecting certain chemicals in solution at elevated temperatures (180-195 F range) into the Recirculation piping. The chemical reaction results in detachment of small radioactive particles from the inside wall of pip These particles then go into suspension and are subsequently flushed out of the Recirculation piping and collected in filter beds when the chemical solution is removed. Upon completion of the chemical decontamination, a decontamination factor (DF) of 10.38 was calculate This was a high DF that exceeded all expectation E. Intake Structure Concrete Inspection Inspection of intake structure concrete below the water line is being performed during this outage. The NRC inspectors looked at portions of the below water concrete surfaces after they were hydrolazed to remove sea growth and found them to be in generally good conditio Evaluation of cracks and potential corrosion of subsurface rebar is

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an important aspect of this inspection. No significant findings had been reported prior to the end of this report period.

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1 Radiation Protection During entry to and exit from the RCA, the inspectors verified that proper warning signs were posted, personnel entering were wearing proper dosi-metry, personnel and materials leaving were properly monitored for radio-active contamination, and monitoring instruments were functional and in calibration. Posted extended Radiation Work Permits (RWPs) and survey status boards were reviewed to verify that they were current and accurat The inspector observed activities in the RCA to verify that personnel complied with the requirements of applicable RWPs and that workers were aware of the radiological conditions in the are With the increased workload during an outage, it is neccssary for Radcon to augment their staffing with contractor personnel. The inspectors observed the performance of contractor personnel to ensure they were adequately trained and capable of performing their duties. No defici-encies were identifie In NRC Inspection "eport 85-35, the licensee was cited because person-nel leaving the RCA were not properly frisking carry along items. The inspector observed frisking activities at various times during this report period and noted several examples of this same problem. These observations were relayed to Radcon management personnel who stated they had not seen recurrence of this problem during their routine tours of the site. They agreed to continue to aggressively pursue informing all personnel of the requirements for frisking prior to leaving the RC The resident inspectors will continue to routinely review this area and follow-up on licensee corrective actions for the above noted violations (which are currently under review by NRC Region I).

12. 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 include . _ _ _ . . _- __ - .

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