IR 05000272/1988019
| ML18093B312 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 11/21/1988 |
| From: | Brochardt R, Gibson K, Swetland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18093B311 | List: |
| References | |
| 50-272-88-19, 50-311-88-20, NUDOCS 8811290412 | |
| Download: ML18093B312 (18) | |
Text
Report No Licensee:
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
50-272/88-19 50-311/88-20 Public Service Electric and Gas Company P. 0. Box 236 Hancocks Bridge, New Jersey 08038 Facility Name: Salem Nuclear Generating Station - Units 1 and 2 Inspection At: Hancocks Bridge, N~w Jersey Inspection Conducted:
September 27, 1988 - November 7, 1988 Inspectors:
Approved by:
R. W. Borchardt, Senior Resident Inspector K. Halvey Gibson, Resident Inspector L. E. Briggs, Senior Operations Engineer R. J. Paoli~ngineer P~and, Chief, Reactor Projects Section No. 2B, Projects Branch No. 2, DRP Inspection Summary:
Inspections on September 27, 1988 - November 7, 1988 (Combined Report Numbers 50-272/88-19 and 50-311/88-20)
Areas Inspected:
Routine inspections rif pl~nt operations including:
operational safety verification, maintenance, surveillance, Unit 2 outage activities, review of licensee event reports, assurance of quality, and followup on outstanding inspection items including the qualifiability of safety related items whose environmental qualification was found deficient by the license Results:
Minor problems identified regarding proper establishment and implementation of procedures related to maintenance and operation of safety related equipment are discussed in paragraphs 2, 3, 6 and 7 and collectively lead to a conclusion that licensee action is required in this area to resolve NRC concern The inspectors and Region I management are continuing assessment of licensee actions with regard to surveillance scheduling and tracking, and Unit 1 steam flow discrepancies (paragraph 6).
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DETAILS Persons Contacted Within this report period, interviews and discussions were conducted with members of licensee management and staff as necessary to support inspection activit.
Operational Safety Verification (71707, 93702) Inspection Activities On a dai1y basis throughout the report period, inspection~ were conducted to verify that the facility was Operated safely and in conformance with regulatory requirement The licensee's management control system was evaluated by direct observation of activities, tours of the facility, interviews and discussions with licensee personnel, independent verification of safety system status and limiting conditions for operation, and review of facility record The licensee's compliance with the radiological protection and security programs was also verified on a periodjc basi These inspection activities were conducted in accordance with NRC inspettion procedure 71707 and 93702 and included weekend and backshift inspection.2 Inspection Findings and Significant Plant Events 2.. Unit 1 Unit 1 operated at 100% power throughout the inspection perio Unit 2 Unit 2 fourth refueling outage activities 'continued during this inspection perio Core reload and reactor reassembly are complete and the unit is in Mode 5 at the close of the report perio On October 5 and 6, 1988, the licensee notified the NRC that the eddy current examination of Nos. 24 and 22 Steam Generator (SG) revealed a number of defective tubes in row 1 of each SG (No. 24 SG-20 defective of 204 inspected, N SG-46 defective of 84 inspected) which placed the SG's in a T.S. 4.4.6.2 examination sample category C-On October 10, 1988, the licensee requested an emergency
-3-license amendment for an alternate SG tube sampling metho to that specified in T.S. to limit additional sampling to*
rows 1 and The discovered defects are apparently due to stresses induced in the U bend region in the manufacturing process and are indicative of an established phenomenon related to row 1 tubes of Westinghouse Series 51 steam generator The license amendment was approved by the NRC on October 14; 1988 and is applicable only to the Unit 2 fourth refueling outag Row 1 tubes in all 4 SG's were plugged by the licensee.as a precautionary measure and all row 2 tubes were eddy current inspected with no deficiencies identifie The inspector witnessed SG tube eddy current testing and tube plugging activitie '
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Plugging all row 1 tubes in all 4 Unit 2 SG's results in 2.7% of Unit 2 SG tubes being plugged and yields a net loss in available RCS flow through the reactor cor~. * The licensee evaluated the reduction in RCS flow and as a result, on October 13, 1988 submitted an emergency license change request to reduce the correction factor for RCS flow measurement uncertainty from 3.5% to 2.2% relative to. The change in correction factor restores the magnitude of margin between the measured RCS flow rate and the calculated thermal design flow rate on which.2.3 limi~s*are base NRR issued the license amendment on November 3, 198 In addition, on October 21, 1988 the licensee requested a temporary exemption from 10 CFR 50.46
. (a)(l)(i) requirements relative to the reduced RCS flow effect on peak clad temperature and the need to perform a Large Break LOCA ECCS reanalysis using an updated computer model from that used fof original plant licensing.. Since the reanalysis will take several months to complete, justification for the exemption is based on sensitivity studies performed by Westinghouse relative to the current ECCS analyses which show satisfactory result This temporary exemption from 10 CFR 46 requirements was approved by NRR on November 1, 198 The licensee* has committed to complete the ECCS reanalysis using.the updated ECCS analysis model by March 31, 198 No violations were identifie During the inspectJon period, the licensee identified cracks in the valve body of valve Nos. 21 and 22 CS 6, Containment Spray Full Flow test isolation valve, for each CS heade Metallurgical examination performed by the licensee's test lab concluded that the cracks apparently resulted from
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intergranular stress corrosion cracking (IGSCC) originating from the outside of the valve body toward the insid The licensee postulated that.a prior service water leak from a flange located near the CS 6 yalves combined with an approximate 3/4 11 cold spring on each header measured when the valves were removed (cut out) could provide the contaminant and stress needed to effect IGSC Since the valves are only used during refueling outages for CS header isolation during the SI full flow test (locked open during power operations) and the licensee did not have readily available replacement valves, spool pieces with bolted flanges were installed in place of the valve The licensee also conducted liquid penetrant te~ting on similar weld areas in the CS piping and identified minor surface pitting which was ~uccessfully mechanically remove The inspector witnessed fit up and welding of the CS spool pieces and flanges and observed the liquid penetrant examinations associated with the CS pipin The licensee plans to
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install replacement valves during the next Unit 2 refueling outage. Radiographic analysis, of 11 and 12 CS 6 valves showed no deficiencies with the similar Unit 1 valve No violations were identifie On October 29, 1988, an equipment operator performing a Technical Specification surveillance test on the 2A diesel generator (DG) synchronized the generator to the grid approximately 130 degrees out of phas The diesel accepted load, however when the error was realized, a normal shutdown
- of the DG was immediately commence Initial inspections of the generator found areas of i~sulation cracking on the stator end basket windings, a broken tie wrap, and loose and missing wedgin The generator was removed and taken to the licensee's offsite repair facility for additional inspection and repai Licensee inspection of the diesel engine and diesel generator outp~t breaker found no damage:
The licensee also inspected the 2C DG generator internals for baseline comparison to the deficiencies identified on 2A D Minor looseness was found on the stator end basket wedging but was determined to be acceptable for operation by the license The licensee has determined that the lack of periodic generator inspection is a weakness in their preventive maintenance program and plans upgrades in this are **
2. During disassembly and removal of the 2A generator from the DG room and disassembly, cleaning and inspection of the 2C generatbr~ the inspectors discussed with maintenance personnel and station management the apparent lack of s~ecific procedures r~lative to performance and control of these activities on safety related equipmen The inspectors were particularly concer~ed due to the fact that this was the fjrst time the licensee had performed these activitie Licen~ee management determined that the generic procedures fo~ rigging and removal of heavy loads, equipment cleaning, and lifted Jeads being used for the above activities were inadequate and stopped work until specific detailed procedures were in plac The inspector subsequently reviewed the procedures and witnessed implementation when the maintenance activities were resumed on 2C generato Procedure establish~ent and implementation concerns are further discussed in Section 7 of this repor No violations were identifie Both Units On October 31, 1988, the following Salem Stati-0n organizational changes were announced by the Salem General Manager and will be implemented at the conclusion of the Unit 2 fourth refueling outage:
From Pell J. White Maintenance Manager Art Orticelle Outage Manager -
Unit 2 To Technical Manager Maintenance Manager On November 1, 1988, the inspector identified a discrepancy with regard to the location of transient equipment on the 100 1 and 122 1 elevations of Unit 1 Auxiliary Buildin Station Administrative Procedure (AP) 23 "Scaffolding and Transient Load Program 11 requires that-all items not being utilized for ongoing maintenance or testing activity shall be placed in approved storage area The procedur~.
specifies approved storage locations for transient equipment based on an engineering evaluation of the potential effect on safety related equipment in the area and floor loading
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concern The licensee has painted green stripes an labeled the AP-23 approved areas in the plan However, contrary to AP-23 requirements, the inspector observed numerous welding machines, large tool boxes, scaffolding and other miscellaneous equipment located outside of the designated storage areas on the 100' and 122' elevations of the Unit 1 Auxiliary Building. It appears to the inspector that in an effort to clean up the Unit 2 side of the Auxiliary Building in preparation for the upcoming restart of the unit following the refueling outage, the licensee moved the outage equipment to the Unit 1 side (Unit 1 was operating at 100% power) to await disposition. This discrepancy was brought to licensee management attention and the equipment was subsequently stored in proper deiignated locations.*
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On several occasions in the past, the inspector identified single instances of equipment improperly stored with. regard to AP-23 requirements and* brought the issue to supervisory and*management attention for resolutio In each case, including the instance identified above, the inspector determined that the potential effect on safety related equipment in the area was minimal relative to the type and location of the transient material. However, the inspector is concerned with the licensee's apparent laxness in implementing procedural requirements related to the storage of transient equipment, especially since the approved areas are clearly labeled in the plan Procedural implementation deficiencies are further discussed in Section 7 of this repor.
Maintenance Observations (62703)
The inspector reviewed the following safety related maintenance activities to verify that the activities were conducted in accordance with approved procedures, Technical Specifications, NRC regulations, and industry codes and standard The inspection activities were conducted in accordance with NRC inspection procedure 6270 Work Order N Procedure MP S-C-N600-MFD-0402 MP Description No. 21 Boric Acid Transfer Pump Removal and Installation Inspection of No. 21 Charging/SI Pump Cladding
-7-The inspector observed the pump/motor alignment for No. 21 BAT and No. 21 charging pumps following the maintenance activities indicated abov The inspector noted that the alignment procedure M6D was not at the work location for either of the above activities, althou~h the alignment procedure (M6D) was called for on both the work order and in the maintenance procedure The inspector noted that equipment alignment problems have contributed to a potential forced shutdown of the plan On a previous occasion the lack of a proper alignment on a centrifugal charging pump (CCP) resulted in the pump not being returned to service within the T.S. LCD time limi Procedural implementation concerns are further discussed in Section 7 of this repor.
Surveillance Observations '(61726) Inspection Activity During this inspection period the inspector performed detailed technical procedure reviews, witnessed in-progress surveillance testing, and reviewed completed surveillance package The inspector verified that the surveillances were performed in accordance with technical specifications~ licensee approved procedures, and NRC regulation These inspection activities were conducted in accordance with NRC inspection procedure 61726.
The following surveillance tests were reviewed, with portions witnessed by the inspector:
Procedure 2IC-2.10.164 M3B lPD 2.6.046 2IC-2.7.002 2IC-2.7.006 2IC-2.7.010 2IC-2.7.014 2IC-2.10.174 Description Channel Calibration of 2FT-640; RHR Flow Logic timing output testing, 28 and 2C SEC No. 13 Steam Generator feedwater flow (FT-530) calibration Nos. 21-24 RCS Flow (2FT-414, 424, 434, 444) Time Response Test No. 21 SI pump discharge flow (2FT-922) differential pressure channel calibration
SP(0)4.l.2.la-8-Reactivity Control Systems -
Boration No violations were identifie.
Unit 2 Outage Activities (60710, 37700, 37702) Refueling Activities Core reload was completed during the inspection perio The inspectors witnessed fuel movement ~ctfvities and verified proper reactivity controls. The inspector also reviewed the licensee 1 s safety evaluation S-2R600-MSE-0739-0, Unrecovered Foreign Objects in the RCS, relative to a hold down nut, -a locking weld pin and a hand held gamma detector probe which fell into the reactor vessel during core reload, and could not be recovered by the license No violations were identifie.2 Design Change Activities During the inspection period two outage inspections were conducted relating to post-modification testing (50-311/88-19) and outage activities including design changes, ISI, welding, et (50-311/88-80).
Results are discussed in the indicated inspection report In addition, the inspectors reviewed the following with regard to design change activitie EC-2151 Implementation of human factors enhancements in the control room On October 19, 1988, during discussions with the licensee concerning Unit 2 control room Human Factors design changes, it was noted that licensed Reactor Operators were being split into two group One group was assigned to Unit 1 and one group was assigned to Unit 2 for plant operation Specific unit assignments were being made to alleviate the potential for operator error because of control room differences due to the human factors design improvement The human factors modifications were performed on the Unit 2 control room this outage and are scheduled to be performed on the Unit 1 control room during the next refueling outage scheduled for mid April 198 These modifications were reviewed in NRC Inspection 50-311/88-8 The splitting of Licensed Reactor Operators (ROs) became a concern because Salem operators are dual licensed (can operate either plant).
In. order to obtain a dual license the licensee must perform a plant differences analysis to show that any differences are minor and will
-9-not pose a problem to the operating staff. A Salem Information Directive Distribution Notice (88-013) stated that operating crews would be split because control room consoles would be significantly different until Unit 1 was modified to match Unit On October 20, 1988, a meeting was held with several members of the Salem Operations, Trafning, and Engineering staff at the NRC Region I offic The meeting w~s held to determine if the changes were significant enough to warrant modification of operating licenses under 10 CFR 55.61(b)(2).
The licensee stated that although numerous control bezels were moved, they were not moved a large distance, except in three instance Two of these changes were fill valves (DR6 and 107) to the Component Cooling Water Surge Tank arid to the Auxiliary Feedwater Storage Tan The third change was the moving of the control for Residual Heat Removal to Charging Pump Suction Valve (22SJ45).
None of theie changes were to controls that would require immediate location and operation during an emergency or operational traMsien NRC management stated that an on-site observation and comparison of the two control rooms would be conducted to determine the significance of the change In addition, the NRC requested from the licensee a written submittal detailing how control room licensed operators would be used, including the means to refamiliarize licensed operators with the other unit 1s control room if it became necessary to rotate them between unit On October 21, 1988, a comparison of the two control rooms was conducted by the inspector The visual comparison verified the information presented by the licensee during the meeting held the previous da The inspectors also talked to various licensed reactor operators to determine if they thought that the control room changes would impact their ability to operate either uni All operators that were talked to stated that with a short indoctrination period they would be able to operate either uni On October 28, 1988, the licensee submitted a letter (NLR-N88182) to the NRC detailing how control room operators would be used until the Unit 1 control room is modified to match Unit 2 during the next Unit 1 refueling outag the letter states that Senior Reictor Operators are unaffected and will continue to rotate between units since they supervise control room operations and do not operate control Reactor Operators (RO) will not be rotated between units unless required due to unforeseen condition If such a_ condition occurs, a Unit 1 RO going to Unit 2 would be required to review and sign a list of control room differences and stand a 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> parallel (with a Unit 2 RO) console watch or a 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> simulator training session before assuming licensed operator dutie A Unit 2 RO
-10-rotating to Unit 1 would be required to review the differences and stand a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> parallel watch before assuming licensed operator dutie Rotating to Unit 2 is less restrictive since all ROs receive requalification training on the simulator which is in the Unit 2 configuratio On November 1, 1988, the inspectors reviewed the licensed operator requalification tra1ning conducted by the licensee to address the Unit 1, Unit 2 control room difference Training was conducted by two method One method was formal classroom instruction which discussed the Human Factors Modification and lasted approximately 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> The second method was by simulator training and direct hands on use of the simulator which has been modified to match the Unit 2 control roo During the simulator training portion, scenarios w~re developed by the training staff that ensured that moved or modified controls would be use In addition, a mock-up of the old Unit 2 control room panels was compared to the simulator on a panel by panel basi Th~ inspectors verified course content and attendanc An on-site meeting was also held with the Operations Manager and the Operations Engineer to discuss exactly how the review of control room differences would be conducted*prior to a licensed operator assuming licensed duty on the opposite uni The licensee explained that a list of all control room panel modifications was being developed to identify each modification in a logical order (e.g., panel by panel).
The list would be reviewed and signed by the operator before standing the parallel indoctrination watc The li~ensee also stated that shifting between units is not expected to occu In no case will a licensed reactor operator be shifted to the other unit before the differences list is finalize Licensee action taken to address this issue was determined to be acceptabl No violations were identifie EC-2232 Bottom Mounted Instrumentation As part of this design change, the licensee installed mechanical clamps on four reactor head spare adaptor caps to reduce the possibility of boric.acid leakage from the canopy seal weld at these location The use of the mechanical clamps for reactor head penetration application was under NRC review at the close of the previous inspection perio On October 5, 1988, PSE&G met with the NRC staff to discuss the details of the Mechanical Seal Clamp Assembly (MSCA).
The MSCA is a
-11-preloaded compressed Grafoil seal with a metallic housing clamp assembl At the meeting, PSE&G was informed that the NRC disagreed with PSE&G's determination that the application of the MSCA is not a code repai As a result, on October 13, 1988 and in accordance with the requirements of 10 CFR 50.55a(g)(5)(iii), the licensee submitted to the NRC a relief request from ASME Section III Code requjrements for the MSCA modificatio Through testing and engineering evaluation the licensee has concluded that the design of the MSCA, with the exception of the use of ASTM material qualification, has been demonstrated to be in compliance with the ASME cod Further, the licensee concluded that the ASTM material qualification meets the intent of code requi~ements for this applicatio The MSCA modification is consi.dered temporary and is not intended to be used in excess of three cycle In addition, the licensee plans to verify MSCA integrity during outages and monitor potential reactor head area RCS leakage during plant operation using the Reactor Head Main Coolant System Leakage.Air P~rticulate Monito Following review of the licensee's submittal and further discussion, NRC granted the requested relief from ASME Section III code requirements for the MSC The inspectors will continue to follow licensee actions in reduction and prevention of RCS leakage on the reactor head.
No violations were identifie.
Review of Licensee Event Reports (90712, 92700)
Upon ~eceipt, the inspictor reviewed licensee event reports (LERs) as well as other periodic and special reports submitted by the license The reports were reviewed for accuracy and timely submissio Additional followup performed at the discretion of the inspector to verify corrective action implementation and adequacy is detailed with the applicable report summar The following reports were reviewed during the inspection period:
Unit 1 Monthly Operating Report - September, 1988 Unit 2 Monthly Operating Report - September, 1988 Unit 1 LER 87-12-01 - Supplement; Technical Specification Non Compliance -
Reactor Trip System Instrumentatio This report modified the corrective actions for an event which occurred on September 30, 1987 involving testing on reattor coolant pump undervoltage trip relay The licensee determined that the subject tests were being performed by both the Maintenance and Relay Department The original corrective actions included assigning full responsibility to the Maintenance Department for completion of undervoltage
-12-relay testing since the maintenance procedure already addressed Technical Specification concerns relating to this even The Relay Department has now been authorized to work on T.S. relays only during bus outage The licensee's method for tracking relay test completion is under review by the inspectors and the licensee's QA organi~ation. The inspector had no further questions with regard to this LE Unit 1 LER 88-14; Missed T.S. Surveillance 4.7.11 due to inadequate Administrative Contro During a QA review, the licensee determined that several fire barrier penetration surveillances had been missed due to inadequate scheduling and trackin Corrective actions for this event and other missed surveillance tests include the upgrading of administrative procedures, and assignment of a surveillance coordinator. to develop a tracking mechanism in accordance with an INPO good practice "Surveillance and Periodic Test Scheduling Program".
The resident inspectors and the Region I section chief were briefed by the licensee on this program during this report perio The effectiveness of improvements in the licensee's surveillance scheduling and tracking program are being closely monitored by the inspectors and Region I managemen (UNR 272/311/88-11-01)
Unit 1 LER 88-15; Turbine Trip/Reactor Trip from 100% Power - Low Auto Stop Oil Pressur This event was discussed in Inspection Report 50-272/88-1 The inspectors had no further questions.
Unit 1 LER 88-16; T.S. Surveillance 4.7.11 Non Compliance - Fire Dampers Not Surveilled - Inadequate Administrative Contro On September 9, 1988, the licensee determined that 29 dampers had never been surveilled as required by T.S. due to administrative control problems relating to equipment identification tag When tested, the subject dampers successfully passed the tes The licensee is revising the appropriate drawing Failure to test fire dampers is an apparent violation of.7.11, however the deficiency was identified by the licensee, adequate corrective action has been taken, and since the dampers were satisfactory when tested the inspector concludes that the safety significance was minima Therefore in accordance with 10 CFR 2, Appendix C, a notice of violation is not being issue (272/88-19-02)
Unit 1 LER 88-17; Five Steam Flow Channels Read Lo This event is discussed in Inspection Report 50-272/88-1 The inspectors have no questions at this time on the LER, however this issue continues to be of concern to the NR Licensee investigation and prompt resolution of the root cause of the steam flow indication "drift", in addition to the monitoring program implemented to prevent recurrence until final resolution is effected are being closely followed by the resident inspectors and Region I managemen (UNR 272/88-17-01)
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-13-Unit 1,LER 88-18; T.S. Action Statement 3.7.11 Non Compliance; Hourly Roving Fire Watch Patrol Late due to Equipment proble This LER documents that several fire areas were not patrolled because the firewatches could not access the areas due to security computer problem The inspector r~viewed the licensee's corrective actions to prevent recurrence and found them to be acceptabl Failure to complete an hourly firewatch is an apparent violation of T.S. 3.7.11, however in accordance with 10 CFR 2, Appendix C a notice of violation is not being issue (272/88-19-03)
Unit 2 LER 88-18; T.S. Surveillance test not completed due to inadequate administrative contro On September 15, 1988, the licensee determined that plant vent tritium grab samples had not been taken over a 2 day period as required by Technical Specification 4.11. Although the required grab samples were not taken, continuou~ plant vent sampling for tritium was conducted and indicated normal reading Corrective actions planned include upgrading procedures, generic outage schedules, and assignment of a surveillance test coordinato Failure to complete T.S. surveillances within the required time is a previously identified deficiency for which licensee corrective action implementation and effectiveness is being closely monitored by the resident inspector and Region I managemen (UNR 272/311/88-11-01)
The root cause of this event was a reliance upon individuals' knowledge of T.S. requi,rements rather than having specific sampling requirements detailed in station procedure Licensee deficiencies with regard to procedure establishment and implementation are further discussed in Section 7 of this repor Unit 2 LER 88-19; Nos. 22 and 24 Steam Generator Tubes found degrade This event is discussed in Section 2 of this repor The inspectors had no further questions following review of the LE The following special reports relating to the fire protection program were reviewed and the inspector had no further question Unit 1 Special Report 88-3-2 Fire-barrier penetration impairments Unit 1 Special Report 88-4 Planned momentary deactivation of fire pump auto start feature Unit 1 Special Report 88-5 Fire barrier penetration impairments Assurance of Quality During recent NRC inspections problems have been identified both by the inspectors and by the licensee regarding procedure use at Sale In this
-14-inspection report several instances are discussed including a diesel generator (DG) being synchronized out of phase with the grid contrary to operations surveillance procedures, the failure to establish adequate maintenance procedures for followup disassembly, cleaning and preparation for removal of the DG, the failure to have safety related pump alignment procedures at the work location while the maintenance was being performed, storage of transient equipment contrary to administrative procedures, and failure to establish adequate chemistry and/or operations procedures which resulted in a T.S. required sample not being obtaine In addition, a recent inspection of radiological controls at Salem revealed examples of failure to follow radiation work permits and radiological control procedure Other previously identified procedure use problems include an I&C technician pulled nuclear instrumentation channel fuses contrary to procedural requirements which resulted in a plant trip, hourly firewatch requirements performed late due to not following the established rove sequence delineated on the impairment checklist, valve manipulations contrary to procedures by a maintenance technician returning a transmitter to service which resulted in a plant trip, a fire protection valve surveillance missed due to a surveillance procedure not being followed, an inadequate operations alarm response procedure which resulted in a action statement not being entered as required for an inoperable SEC, and PASS procedures which could not be followed as written due to unresolved equipment problem The inspector concluded that these examples indicate a need for improvement in the level of management and supervisory oversight in ensuring that procedures are established when required, that procedures are accurate and adequate, and that procedures are followed as written (attention to detail).
The inspector noted that procedure discrepancies have been identified across station department The licensee's Nuclear Administrative Procedure NA-AP.22-000l(Q) "Preparation and Use of Procedures, 11 Section 5.4 specifies how procedures are to be implemented by Nuclear Department personne However, the inspector has observed dis-cussions between workers, supervisors and managers regarding procedure use issues, which indicate that these requirements are not familiar to licensee personnel or that some confusion exists as to how these requirements should be implemented in the fiel The inspector concluded that management attention and action is needed to resolve these concerns with regard to procedure establishment and use at Sale.
Environmental Qualification of Safety Related Equipment (LER 86-007, Licensee Identified Environmental Qualification Discrepancies)
During the week of October 24-26, 1988, the inspector reviewed additional licensee qualification documents to determine the qualifiability of the replaced deficient EQ items as documented by the licensee in its Environm~ntal Qualification Program, Appendix A, enforcement conference presentation of September 29, 198 The deficiencies identified by the licensee, the corrective action and the basis for qualifiability are discussed as Issues 1, 2, 3 and 5 below.
-15-Issue 1 - Limitorque T-drains On April 8, 1986 during the Unit 1 refue 1 i ng outage,_ the 1 i cen see identified eleven Limitorque Valve Operators inside containment *
without T-drain On May 1, 1986, the licensee identified eight Limitorque Valve Operators inside the Unit 2 containment without T-drain Documents reviewed by the NRC inspector indicate the licensee was aware of the requirement_ for T-drain DCPs lEC-1788 and 2EC-1789 issued in 1984 and 1985 included excerpts from Section 6 of the Limitorque test report B-0058 and vendor instructions for installing
- T-drain The licensee determi~ed the underlying cause for the omission of T-drains to be a lack of explicit instructions for the T-drain Corrective action by the licensee included installation of T-drains prior to restart from the March, 1986 outage for Unit 1 and prior to restart of Unit 2 from a voluntary shutdown in May, 198 In addition, PSE&G established a new procedure (S-C-A910-MFD-0342) to provide added assurance that future DCPs include sufficient instructions with respect to T-drains and other EQ requirement To determine qualifiability the licensee provided documentation to show that the referenced qualifying test report (600198) was conducted on Limitorque Valve Operator test specimens without T-drain Since the test temperature profile (328 degrees F) does not envelope the plant profile (350 degrees F) the licensee provided a thermal lag analysis (Report No. F-C2232-0l) which indicates the maximum Limitorque Valve Operator temperature to be 291 degrees Similarity of the original Rad H type motor insulation to the qualified H type motor insulation is presented in the EQ-17 licensee fil Based on the above reviews the NRC inspector concluded that the Limitorque Valve Operators without T-drains were qualifiabl.2 Issue 2 - Solenoid Operated Valves/Conax Seals During the licensee initiated walkdown of March, 1986, the licensee identified eight solenoid valves (Model No. NP8321A1E) that were installed without the required Conax sea The deficient installation was confined to the Post-Accident Sampling System Panel 801-l Similar ASCO solenoid installations and the Unit 2 Post-Accident Sampling System Panel complied with the Conax seal requiremen The licensee determined this to be an isolated incident since only eight
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out of 724 Conax connectors were not installed ~s require In order to establish qualifiability, the licensee references an ASCO Report AQR-67368 revision 1, dated August 19, 198 After reviewing the report, the NRC inspector determined that the report did not conclusively establish the basis for failure of the test anomaly which ciccurr~d on the twelfth da In addition, the DBE test performed by ASCO was a 30 day LOCA exposur To date, there.is no known methodology to extrapolate pressure/humidity test results past the actual time teste To prove that ASCO's sealed" system is qualified for 100 days post-accident, it would have been necessary to test the unit for 100 day This was not don There is no data/
evidence to indicate the SOV's would survive for 100 day The-ASCO report is vague as to the cause of the anomal It is not clear from the test anomaly that the failure was attributed to moisture or radiatio Based on this document review, the inspector concluded that the licensee has not established qualifiability of the SOV'.3. Issue 3 - Electrical Junction Box Seals Seven junction boxes in Unit 1 and nine junction boxes in Unit 2 were identified as not being properly sealed against moisture intrusio The licensee attributed the above deficiencies to inadequate instructions and oversight by the responsible EQ sponsor engineer in not identifying and including the junction boxes in the EQ Master Lis.
In order to show. qualifiability of the junction boxes the licensee has performed a similarity analysis which indicates the installed junction boxes are similar in design and configuration of those tested by Wyle and reported in Wyle Report No. 48365-01 and the Conax Qualification Report No. IPS-40 Engineering Evaluation N S-C-ZZXX-NEE-0252-0 provides additional information with respect to qualifiability in conjunction with the terminal block testing by Wyl Based on the above document review the NRC inspector concluded that the electrical junction boxes are qualifiabl.4 Issue 5 - Terminal Blocks Associated With Auxiliary Feedwater Flow Transmitter Connections During a licensee initiated walkdown, four auxiliary flow transmitters in both Units 1 and 2 were identified that were terminated in junttion boxes with terminal block These terminations should have been made with qualified Raychem splice The licensee promptly made corrections prior to Unit 1 restart in March, 1986 and entered an unscheduled outage for Unit 2 on May, 1986 to implement the correction actio To preclude reoccurrence, the licensee has modified procedures (Procedure No. GM8-EMP-009) to require a field walkdown by project team members prior to closeout of DCP To establish qualifiability the licensee references a Wyle Jest Report No. 48635-01 which documents the testing of terminal blocks inside qualified, closed and gasketed junction boxes with a 3/8 inch drain hol In addition, there was no evidence of leakage currents beyond the minimum de-tectable current of approximately 50 microamp The transmitters functioned as requested with no output signal fluctuation Based on the above document review, the NRC inspector concluded that the terminal blocks associated with the auxiliary feedwater flow transmitter connections were q~alifiabl Issues nos. 1, 3, and 5 are technically resolve The results of this inspection will be evaluated by NRC management and a determination regarding its impact on potential enforcement action will be made in the near futur.
Followup on Outstanding Inspection Items (92701)
(Closed)
TI 2515/93, Inspection for Verification of Quality Assurance*
Request Regarding Diesel Generator Fuel Oil Multi-Plant Action Item A-15 The inspector reviewed the Salem Q list (VPN-QAP-01, Attachment 1) to determine if diesel *fuel oil was liste Diesel fuel is listed in two places, as an expendable item (consumable) and under emergency power system Receipt inspection procedures require samples of fuel oil to be obtained during transfer to the main fuel storage tan Salem Technical Specifications require samples of the 20,000 gallon fuel storage tanks (2 per unit) every 92 day *
The inspector determined that the licensee's actions are acceptabl This TI is complet (Closed)
Unresolved Item 311/84-32-04; BAT pump heat trace temperature control and indication design may be deficien The inspector reviewed results of T.S. 4.1.2.la surveillances for vital heat tracing, observed local temperature indication for primary and
- backup heat tracing, and discussed heat trace concerns with licensee engineering and maintenance personne The inspector was informed that additional insulation has been added around the BAT pump since the 1984 time fram The inspector determined
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-18-that the h~at tracing appears to maintain the boric acid flow path well above the 145 degrees F, T.S. limit (170 - 190 degrees F).
Although the heat tracing and BAT pump seals are frequent maintenance items, the licensee appears to devote adequate resources to promptly repair deficiencies and maintain these systems operabl In addition, the licensee is investigating methods to upgrade both the heat tracing and pump seals and has committed to keep the inspector informed as to the progress of this project~
(Closed)
Inspector Follow Items 272/84-45-07 and 272/84-45-08; Gaseous effluent radiation monitors for accident conditions need improvement The licensee's corrective actions include pro-cedure upgrades, additional personnel training, enhanced dbcu-mentation, and implementation of various design change The in specter wil 1 determine the acceptability of the 1 i cen see 1 s actions in a future inspectio (272/88-19-01)
1 Exit Interview (30_703)
The inspectors met with Mr. L. K. Miller and other licensee personnel periodically and at the end of the inspection period to summarize the scope and findings of their inspection activitie Based on Region I review-and discussions with the licensee, it was determined that this report does not contain information subject to 10 CFR 2 restrictions.