IR 05000293/1986025: Difference between revisions

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{{Adams
{{Adams
| number = ML20210P435
| number = ML20215N727
| issue date = 09/02/1986
| issue date = 10/30/1986
| title = Insp Rept 50-293/86-25 on 860708-0804.Violations Noted: Failure to Follow Surveillance Test Procedures & to Initiate Failure & Malfunction Repts for Deficient Fire Barriers. Deviations Noted:Failure to Hold Fire Brigade Drills
| title = Corrected Pages 2 & 16 to Insp Rept 50-293/86-25,correcting Date for Performance of Surveillance Test Procedure 8.M.2-1.5.8.4 to 860626
| author name = Strosnider J
| author name =  
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
| addressee name =  
| addressee name =  
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| license number =  
| license number =  
| contact person =  
| contact person =  
| document report number = 50-293-86-25, NUDOCS 8610060773
| document report number = 50-293-86-25, NUDOCS 8611070201
| package number = ML20210P324
| package number = ML20215N721
| 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 = 27
| page count = 2
}}
}}


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U. S. NUCLEAR REGULATORY COMMISSION
 
==REGION I==
Docket / Report No. 50-293/86-25 Licensee: Boston Edison Company 800 Boylston Street Boston, Massachusetts 02199 Facility: Pilgrim Nuclear Power Station Location: Plymouth, Massachusetts Dates: July 8, 1986 - August 4, 1986 Inspectors: M. McBride, Senior Resident Inspector J. Lyash, Resident Inspector G. Nejfelt, Resident Inspector L. Doer 11 , Project Engineer Approved by: _
A ( . Strosnider, Chief, Reactor Projects 7 /88 Date ection IB Summary: July 8, 1986 - August 4, 1986
:  Inspection Report 50-293/86-25  ,
i Areas Inspected: A routine resident inspection was conducted of the control room, accessible parts of plant structures, plant operations, radiation protec-tion, physical security, plant operation records, plant events, maintenance, surveillance, and reports to the NRC. The inspection totaled 350 hours by three resident and one regional inspecto Results: Two violations were identified regarding the failure to follow sur-ve111ance test procedures (section 3.e) and failure to initiate Failure and Malfunction Reports (F&MR) for deficient fire barriers (section 7). A devia-tion from an NRC commitment concerning fire brigade training was also identified (section 2). Lack of operations personnel sensitivity to control rod drive ac-cumulator status lights is discussed in Section 3a. Inadeauacies in the oper-ating and alarm procedures for the hydrogen and oxygen monitors is discussed in section 3.b. The licensee's plans to replace secondary containment dampers in light of a 1985 commitment to the NRC and recent damper problems is discussed in section 3.d. Possible weaknesses in preventive maintenance on ATWS (antici-pated transient without scram) equipment, in maintenance records control, and in the design of the feedwater check valves are also discussed in section 3.d.
 
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Recent calibration drift in safety bus undervoltage relays is discussed in section 4.e. Concerns about the control, calibration, and testing of certain 480 VAC and 125 VDC undervoltage relays and concerns about the use of fuses and solid links in safety-related motor control circuits are discussed in section 4.e and 4.f respectively. An inaccurate NRC safety evaluation supporting an exemption from the requirement to install a hydrogen recombiner is discussed in section 4.h. Excessive security guard overtime is discussed in section PDR 860902 G
ADOCK 05000293 PDR
 
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TABLE OF CONTENTS Page Summary of Facility Activities ........................ 1 i Followup on Previous Inspection Findings . . . . . . . . . . . . . . 1 Routine Periodic Inspections .......................... 6 Daily Inspection, System Alignment Inspection, Biweekly Inspections, Plant Maintenance and Surveillance Testing Review of Plant Events ................................ 10 q
' Loss of 480 VAC Bus B-23 and Resulting Half Scrams i Low Level Contamination of Onsite Sewage Tanks i Anticipated Transient Without Scram Monthly
;  Functional Test Discrepancies
] Reactor Building Ventilation Sample Pump
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Failures VAC Safety Bus Undervoltage Voltage j  Relay Calibration Failures HPCI Area Unit Cooler Breaker Fire Protective Instrumentation Rack 2205 Upscale Drift Hydrogen Recombiner Safety Evaluation Intermediate Range Neutron Monitors Observations of Physical Security ..................... 14 Radiation Protection and Chemistry .................... 15 Station Fi re Barrier Deficiencies . . . . . . . . . . . . . . . . . . . . . 15 Local Leak Rate Test Program .......................... 16 Independent Verification of Operating Activities . . . . . . 16 1 Review of Licensee Event Reports (LER's) . . . . . . . . . . . . . . 17 11. Confi rmatory Action Letter 86-10 Update . . . . . . . . . . . . . . . 19 12. Congressional Staff and NRC Commissioner Visits to .... 19 Pilgrim 13. Management Meetings and Meetings with Local Groups .... 20 Attachment I - Persons Contacted Attachment II - Summary of Security Force Overtime Attachment III - NRC Questions Regarding the Supplement of Response to CAL 86-10
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OETAILS 1.0 Summary of Facility Activities The plant has been shutdown since April 12, 1986 for unscheduled maintenanc Subsequent to the shutdown, the NRC issued Confirmatory
; Action Letter (CAL) 86-10. Discussion of issues raised in CAL 86-10
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continued throughout the report perio On July 14, 1986, Commissioner James Asselstine met with NRC and licensee representatives on site to discuss the performance of Pilgrim, and
; program improvements made to date. A station tour followed the meetings.
 
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On July 25, 1985, Boston Edison announced that three major tasks will be added to the current outage which will extend the projected startup date from September 1986 until early 1987. The tasks are (1) the completion of fire protection modifications at the station (2) the installation of certain enhancements to the Pilgrim Mark I primary containment structure, and (3) refueling the reactor. The Pilgrim outage was discussed during a i licensee management meeting in the NRC Region I office on July 30, 198 .0 Followup on Previous Inspection Findings l Violations (0 pen) Violation (83-23-01), perform IST of ECCS/RCIC injection check valves. This item was last updated in inspection report 84-16. The licensee has established procedures for performing a manual exercise test of the HPCI and RCIC injection check valves. These procedures verify that the valve discs are free to rotate, but do not verify that the valve seats on reversal of flow. Similarly, no reverse flow testing of the core spray system injection check valves is conducte In response to the Confirmatory Action Letter (CAL) 86-10, the licensee has commi;ted to leak test the RHR injection check valves. During followup of CAL 86-10 the inspector questioned the licensee regarding the need to also leak test the HPCI, RCIC and core spray check valves. No response had been received from the licensee prior to close of the inspection perio Unresolved Items (0 pen) Unresolved Item (86-01-03), review licensee evaluation of the use of fuses and metal links. This item was last updated in inspection report 86-21. During the period High Pressure Coolant Injection System Area Cooler breaker 1822 caught fire due to a control circuit fault, and installation of a solid link. This event is described in section 4;f of this repor .
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(0 pen) Unresolved Item (86-14-01), operation with unqualified diesel generator differential relay. The inspector reviewed Boston Edison Memorandum NED 86-583, Evaluation of Emergency Diesel Generator (EDG)
Differential Relay Issues. The memorandum's conclusions were 1) the use of the unqualified relays placed the plant configuration beyond the design basis as set forth in the FSAR, 2) the use of the Engineering Service Request process for addressing the discrepancies was inadequate with respect to the timeliness and completeness of the disposition, 3)
the use of the company " corrective action program" would have ensured adequate and timely action, including 50.59 safety evaluation and 4)
the safety significance of the unqualified relays was smal If the established corrective action program described in the Boston Edison Quality Assurance Manual, had been followed comprehensive and timely engineering analysis and corrective actions could have been taken. This will be addressed by the licensee in their written response to inspection report 50-293/86-14. This item will remain open pending an NRC review of the General Electric station blackout analysis supporting the licensee's evaluatio (0 pen) Unresolved Item (86-07-02), review licensee corrective action for failed secondary containment seals. The inspector reviewed the licensee evaluation of the two secondary containment boot tears. Thermal movement of the pipe, vibration, localized harsh environment and some material degradation were identified as the most probable cause for the boot failures. The licensee repaired the subject tears by overlaying the area with sealant. Initial plans were to reinspect all penetrations in the steam tunnel, including the damaged boots, during RF0 #7. Other recommendations included replacement of the damaged boots during RF0 # The current maintenance outage has been extended to encompass the
, refueling outage. The inspector questioned the licensee regarding any revised plans, possibly including replacement of the boots during this extended outage. Similar boots on the main steam lines were replaced several years ago. This item remains open pending response from the licensee regarding future boot inspection / replacement plan !
(Closed) Unresolved Item (86-21-01), fire brigade drill requirements not satisfied. Review of licensee training records for the period of  i January 1,1985 through July 31, 1986 indicate that a significant portion of the station fire brigade have not participated in scheduled drill During calendar year 1985 approximately thirty of sixty-nine brigade members did not participate in a drill. Thirty-two of seventy-five brigade members have not drilled in 198 Fourteen brigade members did not participate in any drill during the nineteen month period between January 1,1985 and July 31, 1986. Five individuals added to the brigade in July, 1985, had not participated in a drill.
 
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The licensee committed in a letter to the NRC, dated March 1, 1977, to conduct fire brigade training in accordance with item B.6.e.2 of NRC Branch Technical Position APCSB 9.5-1, Revision 1. Item B.6.e.2 states that required training can only be accomplished by conducting drills several times a year (at least quarterly), so that all members of the fire brigade have had the opportunity to train as a team, testing itself in the major areas of the plant. This commitment was reviewed and accepted by NRC:NRR in its fire protection safety evaluation, as referenced in the facility operating license. Failure to ensure that all individuals participate in at least one drill annually raises concern regarding the ability of members to perform if called upo The inspector informed the licensee that the above failure to satisfy commitments made to the NRC is considered a deviation (86-25-01).
 
Inspector Follow Items (0 pen) Follow Item (84-44-02). The individual who performed sludge lancing of a contaminated tank without supervisor's approval, and removed his teledosimetry device, was terminated as an employee. The disregard of radiological monitoring by the individual was outside the expected reasonable activities addressed in the licensee's procedures such as reporting lost, damaged, missing, abnormal reading, or off-scale dosimetry to Health Physics (HP) - PNPS Procedure 6.2-11, Revision 5, dated October 26, 1984. After a discussion with the inspector who opened this item, it will remain open pending a specialist revie (0 pen) Follow Item (84-44-03). The practice of making a verbal change to a radiological work permit (RWP) is no longer permitted by PNPS Procedure 6.1-027 dated June 12, 1986. RWP revisions must now be in writing and reviewed by a supervisor at the same level as for the approval of the original RWP to assure that the radiological controls are within the scope of the RWP or if a new RWP is required. Enforcement of this procedure would prevent the potential problem made by a verbal change to a RWP. After a discussion with the inspector who opened this item, this item will remain open pending a specialist revie (0 pen) Followup Item (84-44-05). A HP technician allowed another technician to perform sludge lancing without a breathing zone air (BZA)
sampler, although required by the RWP. Use of BZA sampler and regulated air sampler is stated in PNPS Procedure 6.3-160, Revision 9, dated April 11, 1986. Special precautions and equipment needed to work safely within existing radiological conditions is stated in PNPS Procedure 6.1-022, Revision 20. The current procedure controlling RWPs, PNPS Procedure 6.1-027 dated June 12, 1986, requires an HP supervisor to change the RWP in writing. This item will remain open pending a specialist review.
 
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(Closed) Inspector Follow Item (85-27-51), H202 monitor acceptance criteria not adequate for inspectio The inspector reviewed the environmental qualification (EQ) files for the containment hydrogen monitors. The component test report and evaluation sheets originally identified a required yearly inspection. . Subsequent discussion between the licensee and vendor determined that a yearly zero adjust and span adjust is adequate. This determination was documented in a telephone call record and Revision 1 to the EQ Evaluation Sheet dated November 8, 1985. System calibration is performed on a six month interval as required by technical specification This item is close (Closed) Inspector Follow Item (85-31-02), review licensee evaluation of potential problems with RHR pump impeller wear rings. This item was last updated in inspection report 86-21. During the current inspection period the licensee began disassembly and inspection of all four residual heat removal pumps and motors. This effort is scheduled to complete in mid September. The inspectors observed portions of the pump motor work. GE supervisors and GE QC inspectors were present during NRC review and appeared actively involved with the ongoing work. The NRC inspectors will continue to monitor work activities during routine inspection Specialist inspection of this activity is documented in NRC inspection report (86-27).
 
(0 pen) Inspector Follow Item (86-14-04), evaluate implementation of RHR minimum flow logic modifications, The inspector reviewed PNPS Plant Design Change 86-33, Revision 1, MO 1001-18 A&B control modificatio This design change was initiated in response to the si:gle failure susceptibility of the RHR pump minimum flow protection logic identified by the licensee and discussed in IE Bulletin 86-0 PDC 86-33 changes the minimum flow valve position from normally closed to normally ope It also deletes the valve automatic close input from the flow sensing instrumentation. The net effect of these changes is that the minimum flow valves will initially be open and remain open during Low Pressure Coolant Injection System (LPCI) operation. Because the valves remain open throughout LPCI injection approximately 500 gpm per pump will be diverted from the vessel. The licensee evaluation of the affect of the reduced LPCI flow on the station accident analysis and technical specifications will be reviewed in a future inspectio TMI Action Plan Items (0 pen) TAP Item II.D.3, Safety Relief Valve Position Indicatio Guidance provided in NUREG 0737 indicates that the safety / relief valve position indication system should be environmentally qualified. The licensee committed to install environmentally qualified indication prior to startup from RF0 #5. Qualified indication was installed under Plant Design Change Request 77-78. The design installation was reviewed in inspection report 82-1 .
 
Regulatory Guide 1.97 designates primary system safety / relief valve position indication as a category two variable. Guidance provioed on category two equipment qualification states that instrumentation should be environmentally quali-fied. The licensee, in submittals discussing compliance with regulatory guide 1.97, designated this equipment as not requiring environmental qualificatio The NRC:NRR safety evaluation addressing this area is not expected until 198 Based on the regulatory guide 1.97 submittals the licensee deleted the position indication system from the EQ Master List and no longer believes that the equipment must be maintained as environmentally qualified. This item remains open pending resolution of this discrepanc (Closed) TAP Item II.F.1.6, Post Accident Containment Hydrogen Monitoring. The licensee has installed a primary containment hydrogen M oxygen (H202) monitoring system. The system has been designated as 5 fgty related and applicable quality control requirements applied. The WMM consists of two redundant safety trains, each independently cace.ia .of taking samples from two drywell and one torus locatio Samp1M; system control and calibration can be accomplished locally or remotely from the control room. System components are powered by class IE power. Sample valves close on a containment isolation signal, but may be reopened from the control room using an isolation signal override feature after an accident. Reagent and calibration gas fill connections outside secondary containment have been provided to allow recharge following an accident if secondary containment entry is not possibl Both H202 sample trains are maintained in a standby condition. This ast.ures their availability within thirty minutes, but does not result in the excessive equipment wear associated with continuous service. Oxygen monitoring during normal operations is provided by a separate oxygen analyzing system which alarms at 3% concentration. Technical specifications addressing operability of containment combustible gas monitoring were added undee amendment 55. These specifications were reviewed by NRC:NRR and found acceptable as documented in a safety evaluation provided to Boston Edison on July 5, 198 Based on the above this item is close The inspector performed a walkdown of accessible system components and reviewed applicable drawings and procedures. This is described in section 3.b of this repor Followup on a Part 21 Report - On March 13, 1986, the Philadelphia Electric Company submitted a 10 CFR Part 21 report concerning a failure of a Clow Corporation butterfly valve due to galvanic corrosion between the valve's carbon bushings and stainless steel shaft. The inspector questioned BECo to see if they knew of this potential problem. The licensee indicated that they were aware of the Part 21 report and that it was currently being reviewed by engineering for applicability. The licensee further stated that any corrective action required would be
 
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completed prior to the next reactor startup. The inspector will review the results of the licensee's evaluation and corrective action during a subsequent inspection (86-25-02).
 
3.0 Routine Periodic Inspections Daily Inspection During routine facility tours, the following were checked: manning, access control, adherence to procedures and limiting conditions for operations (LCO's), instrumentation and recorder traces, control room annunciators, safety equipment operability, control room logs and other licensee documentatio During a tour of the control room the inspector noted that several control rod drive accumulator trouble lights were not in alarm with accumulator charging water isolated. The inspector verified locally that all accumulator pressures were below the alarm point. In addition numerous alarm lights on the local accumulator trouble
 
alarm panel were not li In response the licensee operations staff replaced those alarm lights which had burned out, and wrote maintenance requests for the remaining nonfunctional indication These indications should have been in an alarmed state for a period of days prior to the inspector's observation. Operations personnel were not sensitive to the indication statu This lack of sensitivity was also noted in inspection report 86-0 Systems Alignment Inspection Operability confirmation was made of selected systems. Major motor operated and manual valve positions were verified during routine checks of the control room. Valve power supply, breaker alignment, and safety equipment controller set points were also checke The inspector walked down accessible portions of the Primary i Containment Hydrogen /0xygen (H202) Monitoring Syste The accuracy of system valve / breaker lineups and operating instructions was reviewed. The adequacy of surveillance testing for the components was evaluate During normal system operation the safety related Comsip post I
accident H202 monitors are in standby mode. A separate nonqualified 02 (C-41) monitor is used to continuously indicate containment oxygen concentration. If 02 concentration increases to 3% a control room alarm is received from the C-41 monitor. The Comsip H202 monitors are to be placed in service and alarm at 4% H202 concentration _ ___ _
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The inspector noted that alarm response procedure 2.3.2.20, Revision 7 did not direct the operator to place the safety related H202 analyzers in service upon receiving the containment Hi/ Low (3%)
02 alarm. Discussion with the control room staff indicated that the need to place the H202 system in service if the alarm is received had not been conveyed. The licensee informed the inspector that proce-dure 2.3.2.20 would be changed to provide this guidanc Nuclear Operations Procedure 2.2.133, Revision 3, H202 Analyzer and C-19 system details system alignment and operating instruction The valve lineup in the procedure precludes operation of the C-41
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oxygen monitoring system. However, this equipment is normally in service. The inaccurate procedure had neither been followed nor corrected. This procedure also provided inaccurate instructions for overriding a containment isolation signal and reopening the H202 sample valves post accident. The licensee is processing changes to procedure 2.2.133 to correct the valve lineup and add steps to recover from an isolation signa Technical specifications require measurement of containment oxygen concentration at least twice weekly. The requirement is satisfied by reading the C-41 02 analyzer. Periodic calibration of the 02 analyzer is accomplished by procedure 7.4.18. The inspector noted that procedure 7.4.18 was not included on the Master Surveillance Tracking Program (MSTP) to ensure its implementatio Procedure 7.10.7, Calibration Checks of Comsip H202 Analyzers is performed monthly as a functional test. As part of this test chemistry department personnel verify that correct calibration gas concentrations are posted in the main control room. The inspector noted that no calibration gas concentrations had been posted and that procedure 7.10.7 was not on the MSTP. The licensee, when informed, posted the correct gas concentration and added procedures 7.4.18 and 7.10.7 to the MST Biweekly Inspections During plant tours, the inspector observed shift turnovers, plant conditions, valve and instrumentation lineup, radiological controls, security, safety, and general adherence to regulatory requirement Plant housekeeping and cleanliness were evaluated. The inspeetor had no further question Plant Maintenance The inspector observed and reviewed maintenance and problem investigation activities to verify compliance with regulations, administrative and maintenance procedures, codes and standards, proper QA/QC involvement, safety tag use, equipment alignment, jumper use, personnel qualifications, radiological controls for worker protection, fire protection, retest requirements, and l reportability per Technical Specification I
 
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The licensee has begun disassembly and inspection of all four residual heat removal system pumps. The primary reason for disassembly is the examination of the pump wear rings for signs of cracking. The project has been contracted to General Electric with Boston Edison oversight. A regional inspector arrived on site August 4,1986 to examine the ongoing work (NRC Inspection Report 50-293/86-27). Resident inspectors will continue to monitor work activitie The inspector reviewed a series of recent secondary containment isolation damper problems. The dampers in question appear to be deficient in design. Failure of the dampers was the subject of special inspection 85-21. The licensee stated that replacement of the dampers with a nuclear grade design would be campleted during this outage. During the inspector's exit meeting station management reiterated its commitment to replace the dampers prior to startu During a plant tour on July 8,1986 the inspector noted deficiency identification (DI) tags hanging from the alternate rod insertion valves. The maintenance requests had been written, and the DI tags hung during 1984 to rebuild the ASCO valves. General Electric Service Information Letter (SIL) 128 advises licensees that valve internal parts made nf Buna N deteriorate with age, and recommends replacement of these components at intervals of less than seven years. The licensee policy has been to rebuild the valves listed in the SIL on a five year interval. While SIL 128 does not expressly identify the ARI valves, these valves also have internal components made of Buna N. The two ARI valves were received January 10, 1980, approximately six years and six months ago. In response to the inspectors questions, the licensee scheduled the ARI valves to be rebuilt prior to startu The inspector noted that the requirement to rebuild the affected valves on a five year interval was not listed on the
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station preventive maintenance program. Because of the large number of valves the rebuild effort is staggered over a number of outages; completing a percentage of the valves each tim In the past, individuals have informally tracked the work progress. The licensee stated that a formal method of tracking the valve rebuild program, including the ARI valves, would be implemente While reviewing the quality assurance records of post-maintenance testing in the Document Control Center (DCC),
the inspector found that post-maintenance valve actuator testing was neither maintained with the maintenance request (MR) package nor filed under surveillance data sheet, 3.M.4-10C. .This was subsequently confirmed by the DCC staf i
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The inspector noted that post-maintenance test records, local leak rate testing and motor operator testing, were not always available in the licensee's document control cente Although the records could ultimately be produced, the inspector questioned whether the maintenance test results are maintained as a quality assurance record (i.e., storage, preservation, and safekeeping) and are processed into the Nuclear Records Management System in a timely manner, as required by the Boston Edison Company Quality Assurance Manual (BQAM), Chapter 17. At the exit meeting, the licensee agreed to review these concern Feedwater Check Valves - All four feedwater check valves were removed for maintenance to correct excessive back leakage. It was found while inspecting the valves for repair, that 17 of 32 wrist pin bushing tack welds may have been cracked. However, none of the bushings, which permits rotation of the check valve disk on the wris- pins, were able to be moved by hand. A design change to eliminate the bushing tack welds for the Anchor Darling feedwater check valves is planned prior to the valve installation. At the exit meeting, the inspector questioned the potential reporting requirement for this problem under 10 CFR 21. The acceptability of licensee actions is unresolved (8C-25-03).
e. Surveillance Testing The inspector observed tests to assess performance in accordance with approved procedures and LCO's, test results, removal and restoration of equipment, and deficiency review and resolutio During followup of recent containment damper failures, described in section 3.d of this report, the inspector reviewed the results of several secondary containment isolation surveillance test Proce-dure 8.M.2-1.5.8.4, Revision 12, Logic System Functional Test of System B Standby Gas Treatment Initiation, Reactor Building Isolation, and Outboard Drywell Isolation Valves, was performed on June 26, 198 During the test a secondary containment damper failed to fully clos At that point the test was stopped. Neither restoration of the system to normal nor independent verification of restoration were documente In addition, previous procedure verification steps were not completed and the operating supervisor and watch engineer review of the test results were not completed with abnormal test results properly docu-mented. Failure to verify completed procedure steps and independently verify restoration of the system following the test is a violation of procedure 8.M.2-1.5. ;
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On July 10, 1986, the inspector observed during the performance of PNPS Procedure 8.M.2-1.4.1, Revision 12 that the "K2s" and "K7s" relays were not independently verified, as specified in the procedure, in the restored energized positio These relays provided input to the alarm and main steam isolation valve (MSIV)
closure logic, respectively. Upon questioning, the technician was not aware of the necessity of independently verifying these relay Upon further investigation, the same surveillance procedure was performed on April 5, 1986, and on May 7, 1986 without independent verification'of the "K2s" and "K7s" relay restoratio The inspector informed the licensee that failure to adequately follow procedures as noted in the above examples, constitutes a violation (86-25-04).
The inspector reviewed surveillance procedures associated with the H202 analyzer system as described in section 3.b. Other surveillance testing witnessed by the inspector during this reported period were HPCI Condensate Storage Tank Level Channel Check, 8.M.2-2.5.6, Revision 7, Strong Motion Accelerograph Functional Test, 8.M.3-10, Revision 7, and Reactor Water Level Functional Test, 8.M.1-19. No discrepancy was observed for these surveillance .0 Review of Plant Events Loss of 480 VAC Bus B-23 and Resulting Half Scrams The power for Reactor Protection System (RPS) Motar Generator (MG)
set "A" is supplied from Motor Control Center (MCC) B-23. MCC B-23 is in turn supplied through 480 VAC load center breaker B30 Several times during the report period breaker B-306 tripped, resulting in loss of powar to RPS MG set "A" and a nalf scra Initial performance testing of breaker B306 did not reveal any performance abnormalities. Supplementary testing at lower current values identified erratic performance of the breaker overcurrent trip devices. Preliminary indication is that a missing lock nut on the "C" phase long time delay trip mechanism may be the cause. The licensee has shipped all three breaker overcurrent trip devices to the vendor for root cause analysis and will evaluate the generic implications of any test results obtaine Low Level Contamination of Onsite Sewage Tanks On July 16, 1986, the reactor building auxiliary bay sewage ejector pump tank was found to be slightly contaminated. This was considered by the licensee as a potential unmonitored radioactive material release path and the system was tagged out for repair Also on July 16, 1986, the licensee initially determined that an onsite septic tank contained radioactive Cobalt-60 at 1.1E-06 microcuries per milliliter. However, a second sample from this tank
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did not detect any radioactive contaminatio Prior to the backup sample the licensee performed a review which identified possible sources of contamination into this tan The licensee samples the sewage tanks regularly, prior to removing waste for shipment offsit Licensee plans are in place for decontamination of all onsite sewage tanks. Previous traces of contamination had been detected in onsite sewage tanks and were reviewed during NRC inspection 50-293/85-2 Sewage pumping trucks are routinely checked for contamination prior to leaving site. No activity has been detected in these truck The inspectors aise noted that the licensee is performing a re-review of IE Bulletin No. 80-10, " Contamination of Nonradioactive System and Resulting Potential For Unmonitored, Uncontrolled Release to Environ-ment". The inspectors will review the results of the licensee's evaluation and any corrective actions during subsequent inspection ATWS Monthly Functional Test On July 15, 1986, the licensee notified the NRC via the ENS telephone line that functional tests for the ATWS (anticipated transient without scram) system were not conducted in the manner required by the technical specification Specifically, the licensee's functional test, procedure 8.M.1-29, did not activate the system primary sensors during the test. Instead, the test injected test signals directly into the ATWS trip units. The technical specification definition of instrument functional test requires that
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the primary sensors be activate The technical specification test definition may not be appropriate for the ATWS instruments because they are Rosement transmitters and analog trip units. Because of the reliability of these instruments,
; the licensee believes that it is common practice to initiate monthly functional tests at the trip units instead of the primary sensor The sensors are normally tested less frequently, i.e., every eighteen
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months. This minimizes the chances of causing inadvertent reactor scrams. The licensee is planning to modify the technical specifica-tions to allow testing in this manne The inspector reviewed the QA deficiency report that identified the
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problem, OR 1559, and the plant's response. The inspector also verified that the ATWS functional tests were properly scheduled on the stations Master Surveillance Tracking Program (MSTP). The inspector discussed the testing problem with licensee personnel and noted that a similar problem exists for the other analog-trip devices currently installed, i.e., the scram discharge volume level
, -instruments. The licensee subsequently notified the NRC of the discharge volume test inadequac The inspector had no further i questions. This item is licensee-identified and will be reviewed i
during future routine inspections.
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, Reactor Building Ventilation Sample Pump Failures On July 17, 1986 the "A" reactor building sample pump tripped due to pump motor failure. This pump and similar sample pumps are rebuilt every 3 months because of a history of failures. The other reactor building sample pump was started when the alarm for the pump trip was receive While reviewing the history of this tyoe of sample pump, it was found that either the wrong number or no equipment number was used to specify the reactor building sample pump on Maintenance Requests (MRs) 85-4-68 and 85-628. The correct equipment numbers for the reactor building sample pumps were P236A and P-2368 according to
drawing number M-287. This matter was discussed with the licensee maintenance personne e. 4160 VAC Safety Bus Undervoltage Relay Calibration Failures On June 21, 1986 the licensee discovered that surveillance testing of safety related emergency bus undervoltage relays was overdue. A discussion of the circumstances leading to the problem is contained in inspection report 35-21, section Followup of the item will be conducted under unresolved item 85-21-08 as stated in that report.
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On July 23, 1986 calibration of the subject relays identified that eleven of the total population of twenty were outside the calibration limit. The inspector questioned the acceptability of the current calibration interval, given the high failure rate. An NRC special team inspection 86-24, (generic letter 83-28 followup), is evaluating the adequacy of the licensee's undervoltage protection and surveillanc During the review of undervoltage relays at Pilgrim, the inspector noted that the Low Pressure Coolant Injection (LPCI) valves for both LPCI loops are pnwered through the same 480 VAC lead center, B Bus B6 can be supplied from either diesel generator through their associated distribution systems. Two undervoltage relays are installed on each of these two B6 power supplies. The undervoltage relays will, if loss of the normal supply is sensed, transfer B6 to its alternate suppl In order to complete this transfer 125 VDC control power from bus D6 is required. Bus D6 can be supplied from either 125 VDC battery "A" or "B". Like 480 VAC bus B6, an auto transfer from the normal to alternate battery source on loss of
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voltage is provided for 125 VDC bus D6. These two auto transfer I functions are critical in supporting the licensees assumptions regarding available ECCS in the accident analysis. The inspector noted that these undervoltage relays / functions are not addressed by technical specification Initial indications are that no station calibration / test procedures are in place. The inspector was informed
  = Appendix A  2
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Contrary to the above, on the dates indicated below, the following surveil-lan'ce test procedures were performed and steps implementing verification and independent verification of system response and system restoration were not completed: PNPS Procedures 8.M.2-1.S.8.4, Logic System Functional Test of System
  "B" Standby Gas Treatment Initiation, Reactor Building Isolation and Outboard Drywell Isolation Valves on June 26, 198 . PNPS Procedure 8.M.2-1.4.1, Revision 12, Main Steam High Temperature Sensors Functional Test, on April 5, 1986, and May 7, 198 This is a Severity Level V Violation (Supplement I).


4 that setpoints and testing of these components may be controlled by the corporate relay test group. This group is not part of the nuclear organization. The inspector will continue to evaluate the acceptability of the technical specifications, control, calibrations and testing of those components during the next inspection period (86-25-05), HPCI Area Unit Cooler Breaker Fire On July 28, 1986 smoke was observed coming from breaker 52-1822 in the reactor building. This breaker supplies power to a High Pressure Coolant Injection (HPCI) pump compartment unit coole Investigation determined that a circuit lead disengaged from its terminal block and touched ground. A solid link had been installed
Pursuant to the Provision of 10 CFR 2.201, Boston Edison Company is hereby re-quired to submit to this office within thirty days of receipt ~of the letter
.which transmitted this Notice, a written statement or explanation in reply in-
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cluding (1) the corrective steps which have been taken and the results achieved; (2) corrective steps which will be taken to avoid further violations; and (3)
the date when full compliance will be achieved. Where good cause is shown, consideration will be given to extending this response tim 'PDR ADOCK 05000293 G  PDR
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rather than a protective fuse in the control power circuit. Because  ,
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no fuse had been installed the fault was not cleared, and the
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  : control power transformer located in the breaker compartment burned u Control of the application of solid links and fuses is the subject of an ongoing licensee engineering evaluation and is being reviewed under unresolved item 86-01-0 Previous licensee
k  16
; indications were that installation of solid links was conservative because loss of equipment due to spurious fuse failure was
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i eliminated. In response to this incident the inspector pointed out that a resulting electrical bus fire may not be conservative.
 
The loose lead which caused the fire became disengaged because the terminal block to which it was secured was cracked. The licensee
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stated that an examination of similar terminal blocks and an evaluation of the cause of the cracking were being conducted. The
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inspector will review the licensees evaluation of this matter during l a future inspectio g. Protective Instrumentation Rack 2205 Upscale Drift On July 31, 1986 the licensee noted that all reactor vessel level instrumentation on instrurint rack 2205 was indicating high. This instrumentation provides input to the reactor protection system, emergency core cooling system initiation and primary containment
established in 1985. The inspector will review the individual discrepan-cies, and any compensatory measures taken, to determine compliance with the technical specifications during a future inspection (86-25-10).
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isolation system. Indicated level discrepancy between the instruments on rack 2205 and similar instruments on rack 2206 was approximately 10 inche Investigation by the licensee identified that the reference leg common to all the affected instruments had partially drained. Daily log information plotted by the inspector indicates an increasing trend over a number of days for the instruments in question. Pertinent valve lineups were checked, the reference leg was backfilled and all indication returned to norma The licensee is currently monitoring instrument performance to
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detect any additional problems. The inspector had no further questions.


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Boston Edison Quality Assurance Manual (BEGAM) Section 16 establishes the corrective action program, and requires that deficiencies be identified and processed in accordance with Section 15 of the BEQAM. Section 15 states that nonconforming components are documented and reported via a Failure and Malfunction Report (F&MR). PNPS procedure 1.3.24, Revision 12, Failure and Malfunction Reports states that an F&MR shall be initiated
.whenever any abnormal plant condition has the potential to adversely affect safe operation Timely and effective processing of an F&MR is important in establishing-operations staff awareness of potential or actual ~ problems. Technical specifications _ require establishment of a fire watch within _one hour of finding an inoperable fire barrie Failure to effectively use the cor-rective action program both as the individual discrepancies were identified, and after the summary of discrepancies was compiled on July 2,1986, demon-strates a programmatic weakness. ~ The inspector informed the licensee that the above constitutes a violation of 10 CFR 50 Appendix B (86-25-09).


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8.0 Local Leak Rate Testing Status During this reporting period, 1 type "B" as-found local leak rate test (LLRT) failure was found. The outboard flange of the inboard drywell purge exhaust valve had leakage greater than 20 sim. This leakage will be. quantified prior to its repair work. Also 3 type "C" as found LLRT failures were found, i.e. , the outboard drywell purge exhaust valve, the inboard post accident sample system (PASS) return valve, and the inboard drywell' equipment drain valve. Between August 4, 1986 and April 11, 1986, 87 of approximately 101 type "B" components have been tested with 2 fail-ures, and 123 of approximately 133 type "C" components have been tested with 15 failure During conduct of leak rate testing on the containment floor drain sump isolation valves the inspector noted that while two LLRTs had been per-formed on that day, no test cart bypass valve leak test had been performed as required by procedure. This concern had been previously identified by the. inspector and discussed with licensee personnel. While the signifi-cance of the incidents is minor, the licensees failure to correct them raises concern. ~The inspector discussed this problem at the exit meetin l l
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OFFICIAL RECORD COPY 403STROSNIDER10/27/86 - 0004.0.0 1 10/27/86  l t
 
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14 Hydrogen Recombiner Safety Evaluation During the inspection period, the licensee noted that the NRC safety evaluation dated April 30, 1986, which supports an exemption from the hydrogen recombiner requirements of 10 CFR 50.44 (c)(3)(ii)
contained statements that did not accurately reflect the condition of the plant. Specifically, the licensee noted that items 2.b.1 and 2.b.2 in the evaluation might not reflect actual practices at the plant. These items involve (1) a requirement to shut the plant down i  within 24 hours if the nitrogen supply system (or an alternate nitrogen system) is not operable and (2) the isolation of the
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instrument air system from the nitrogen supply system by a locked closed valv The inspector discussed the safety evaluation with the licensee and with the NRR Project Manager. At the end of the inspection period, the licensee had not completed its review of this issue. This review will determine which statements are inaccurate and the source i  (licensee or NRC) of any misinformation. The acceptability of the licensee's actions are unresolved pending the completion of the licensee's review (86-25-06)).
i Intermediate Range Neutron Monitors Based on a General Electric (GE) Rapid Information Communication Services Information Letter (RICSIL) Number 007, the licensee investigated and found an undetected failure mode of the neutron intermediate range monitors (IRMs) that may not provide the reactor protection system scram during startup. Specifically, loss of the IRM negative power supply voltage will not cause an inoperable IRM i
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trip card light, but will cause a signal output from the amplifie This causes the IRM to lock above the downscale trip and below the upscale trip regardless of the actual core neutron flux.
 
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,  GE is examining a relay / contact modification, which would monitor
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the IRM negative power supply and would initiate an inoperable trip light if a loss of power occur The results of GE's final recommendation will be in a GE Services Information Letter.
 
i  The unit is currently in an outage and reactor power operations are
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not anticipt.ted until the first quarter of 198 The resolution o this problem will be reviewed during a future routine inspection (86-25-07).
 
, 5.0 Observation of Physical Security
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On July 23, 1986 the inspector received an anonymous allegation concerning excessive security force overtime. On July 24, 1986 the inspector reviewed security force time sheets for the period June 16, 1986 through July 20, 1986. This period began after the end of the Boston Edison labor union
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strik In order to focus on the routine schedules maintained by the normal security guard force, time immediately before, during and after the security force labor action of June 30, 1986 was not considered. A summary of individual cases of excessive overtime identified is included as Attachment II to this reror The inspector noted during the review that security per:onnel routinely work up to twenty-e'qht hours in a forty-eight hour period. Instances of up to thirty-si. . cues in a forty-eight hour period were also identifie One individual tm ked twenty-three of twenty-seven hours. The time onsite for individuals in twenty-four and forty-eight hour periods is not monitored by the license Cases of up to eighty-eight hours worked in a seven day period, with individuals on duty as many as ten consecutive twelve hour days, were identified. While the licenses does monitor time worked in a seven-day period, only the seven-day periods starting Monday and ending Sunday are reviewe The excessive number of security force overtime hours raises concern regarding the ability of individuals to perform their function. The inspector discussed these observations with licensee corporate and station management. The licensee immediately reviewed the overtime status for onshift security personnel and took steps to reduce or eliminate the overtime proble Security overtime was subsequently discussed during an NRC Management meeting (50-293/86-26) and also reviewed during a security specialist inspection (50-293/86-26). The corrective actions will be reviewed during a future inspection (86-25-08).
 
6.0 Radiation Protection and Chemistry Radiological controls were observed on a routine basis during the reporting period. Standard industry radiological work practices, conformance to radiological control procedures and 10 CFR Part 20 requirements were observed. Independent surveys of radiological boundaries and random surveys of nonradiological points throughout the facility were taken by the inspector.
 
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7.0 Station Fire Barrier Deficiencies During 1985 a series of fire barrier walkdowns were conducted to verify that the required Appendix R barriers provide a minimum 3 hour fire resistance. Nineteen specific deficiencies were identified. On July 2, 1986 a memorandum summarizing these deficiencies was transmitted from the ;
nuclear engineering department to the station. This memorandum '
recommended that compensatory fire watches be implemented. The results of the walkdowns were received at the site on July 2,1986. On July 8, 1986 a Failure and Malfunction Report was initiated to officially ,
identify the problem and initiate corrective actions. The licensee is i reviewing its records to determine whether compensatory fire watches were i
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established in 1985. The inspector will review the individual discrepancies, and any compensatory measures taken, to determine compliance with the technical specifications during a future inspection (85-25-09).
 
Boston Edison Quality Assurance Manual (BEQAM) Section 16 establishes the corrective action program, and requires that deficiencies be identified and processed in accordance with Section 15 of the BEQAM. Section 15 states that nonconforning components are documented and reported via a Failure and Malfunction Report (F&MR). PNPS procedure 1.3.24, Revision 12, Failure and Malfunction Reports states that an F&MR shall be initiated whenever any abnormal plant condition has the potential to adversely affect safe operation Timely and effective processing of an F&MR is important in establishing operations staff awareness of potential or actual problems. Technical specifications require establishment of a fire watch within one hour of finding an inoperable fire barrie Failure to effectively use the corrective action program both as the individual discrepancies were identified, and after the summary of discrepancies was compiled on July 2, 1986, demonstrates a programmatic weakness. The inspector informed the licensee that the above constitutes a violation of 10 CFR 50 Appendiv B (86-25-09).
 
8.0 Local Leak Rate Testing Status During this reporting period, I type "B" as-found local leak rate test (LLRT) failure was found. The outboard flange of the inboard drywell purge exhaust valva had leakage greater than 20 si This leakage will be quantified prior to its repair work. Also 3 type "C" as found LLRT failures were found, i.e., the outboard drywell purge exhaust valve, the inboard post accident sample system (PASS) return valve, and the inboard drywell equipment drain valve. Between August 4,1986 and April 11, 1986, 87 of approximately 101 type "B" components have been tested with 2 failures, and 123 of approximately 133 type "C" components have been tested with 15 failure During conduct of leak rate testing on the containment floor drain sump isolation valves the inspector noted that while two LLRTs had been performed on that day, no test cart bypass valve leak test had been performed as required by procedur This concern had been previously identified by the inspector and discussed with licensee personnel. While the significance of the incidents is minor, the licensees failure to correct them raises concer The inspector discussed this problem at the exit meetin .0 Independent Verification of Operating Activities The inspector reviewed fifty eight administrative, operations, maintenance, and surveillance procedures to determine if the licensee established an acceptable system of verifying the correct performance of
 
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operating activities. The procedures were reviewed against Section 5.2.6, " Equipment Control", of ANSI N18.7, 1976 as supplemented by NUREG 0737 item I.C.6, " Guidance on procedures for verifying correct performance of operating activities". The inspector determined that, with the exception of the tagging procedure, the licensee had revised the procedures to provide for independent verification. The inspector found that precedure no. 1.4.5, "PNPS Tagging Procedure", Revision 16, was inadequate in that it did not require independent verification when hanging tags or during tag removal / equipment restoration. Similar problems were also noted in inspections 50-293/85-03 and 86-06. The licensee informed the inspector that a revision to the tagging procedure was being prepared which would include independent verification of tagging activities and the inspector was shown the proposed tag record which would implement it. The inspector found the propcsed revision acceptable and will review the revised tagging procedure in a subsequent inspectio The inspector also had a concern regarding the implementation of the independent verification program. As noted in paragraph 3.e of this report, a violation for failing to perform an independent verification when required was identified. During discussions with licencee personnel, the inspector also noted some confusion as to which systems required independent verification. The inspector noted that procedure no. 2.1.11, " System Lineup File", is the only procedure which identifies systems requiring independent verificatio However, this procedure is used for valve lineups after refueling outages and is not used by other than operations department personnel. The licensee acknowledged the inspector's concern and indicated that the controlling administrative procedure (procedure no.1.3.34 " Conduct of Operations") would be revised to reference procedure 2.1.11. The licensee also indicated that procedure no. 1.3.34 would be revised to include the management objectives as stated in memorandum M85-137, Control and Verification of Operating Actions, as additional guidance on implementation of the independent verification progra The inspector informed the licensee that the revised 1.3.34 and 1. procedures would be reviewed during a subsequent inspection and would be necessary to complete the licensing action review for NUREG 0737, item I. .0 Review of LER's LER's submitted to NRC:RI were reviewed to verify that the details were clearly rerorted, including accuracy of the description of cause and adequacy of corrective action. The inspector determined whether further information was required from the licensee, whether generic implications were indicated, and whether the event warranted onsite followup. The following LER's were reviewed:
 
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LER N Event Date Report Date  Subject 86-13 5/30/86 6/30/86  Use of non-seismic CFD relays for D/G differential protection
 
86-14 6/10/86 7/9/86  Insufficient once per cycle RCIC surveillance ,
procedure  '
86-15 6/13/86 7/14/86  Primary containment local leak rate test i frequency 86-16 6/21/86 7/21/86  Bus AS, Bus A6, and Startup degraded  >
'    voltage relay calibrations overdue'
The following deficiencies in LER 86-13, "Use of Non-Seismic General Electric Type CFD Relays", were noted:
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The LER indicates that operator action will be initiated by non-seismically qualified annunciators after a seismic even The LER did not clearly indicate that a General Electric evaluation of a short-term station blackout was not completed until 1986, two years after the relay problem was identifie The LER indicated that no failure (presumably spurious activation)
of the CFD relays had occurred in thirteen years. However, this statement may be inaccurate because spurious activations of the relays would probtbly not have been logge This event was also reviewed during NRC inspection 86-1 l The event described in LER 86-14, " Primary Containment Local Leak Rate Test Frequency", was discussed in NRC inspection 50-293/86-21. The adequacy of licensee surveillance test scheduling methods is currently  l unresolved and will be tracked under open item 86-21-08. The inspector  l noted two deficiencies with the LER:
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The LER stated that containment local leakage tests were previously  ,
scheduled on a " program basis". However, the scheduling method  '
(i.e., " program basis") was neither explained nor justified in the
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LER. This description is needed to explain why there was an apparent conflict between the licensee's scheduling method,10 CFR 50 Appendix J scheduling requirements, and technical specification scheduling requirement . .
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The technical specifications have two definitions of ope : ting cycle. The LER only mentions the less restrictive defin. Lion (definition "0"). The leakage tests in question were not overdue using this definitior.. However, if the more restrictive definition (definition "U") is used, the tests would have been overdue. The LER should justify using the less restrictive cas The licensee stated at the exit meeting that the deficiencies identified by the inspector would be reviewed and the LER's appropriately updated.
 
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! The events described in LER 86-16, " Bus A5, Bus A6, and Startup Degraded Voltage Relay Calibrations Overdue", were initially reviewed during NRC inspection 50-293/86-21. A followup review is descr9,ed in Section 4.e
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of this inspection report. No problems were identified. An LER update will be required if the as-found calibrations of the relays are outside the plant design base .0 Confirmatory Action Letter 86-10 Update Attachment III lists followup NRC questions concerning issues in Confirmatory Action Letter (CAL) 86-10. These questions were discussed
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between the licensee and the inspector. The preliminary licensee response was also discussed during a telephone call on July 31, 1986 between the licensee, the inspector, and Region I management. At that time, the licensee agreed to submit a written response to the questions to Region I within 30 days of the telephone call. The response will be reviewed during future followup of CAL 86-1 O 12.0 Congressional Staff and NRC Commissioner Visits to Pilgrim
 
Members of the congressional staffs of Un,ited States Senator Kennedy, Senator Kerry, and Congressman Studds toured the Pilgrim site on July 10, 1986. They met with Boston Edison representatives and the Pilgrim
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resident inspectors during the afternoon. A congressional heering
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concerning problems at Pilgrim and selected other U.S. power reactors was held the following wee L'
l' On July 14, 1986, NRC Commissioner J. Asselstine and the NRC Region I Administrator, Dr. T. Murley, also toured the Pilgrim site. Prior to the tour, they met with the Pilgrim resident inspectors, Boston Edison officials and local public official Commissioner Asselstine held a press conference at the end of the day. Among the topics discussed during the tour were deficiency stickers located by the control rod select panel in the control room, the status of preventative mainterance for the onsite liquid nitrogen storage tank, and the status of preoperational testing of the air filtration system for the Emergency Offsite Facility (EOF). Licensee plans for completing required fire protection modifications were also reviewed.
 
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The deficiency stickers in the control room indicated that maintenance requests had been issued to repair control rod position indication probes (PIPS). These problems were generally limited to one or two positions on an individual control rod. The inspectors had previously verified that the control rod position problems had not prevented the licensee from conducting required control rod scram tests. The Pilgrim technical specifications allow PIP's to be out of service as long as redundant nuclear flux instrumentation is operabl The licensee indicated that the PIP problems were scheduled to be fixed during the next refueling outage, when all PIP connectors undervessel would be changed out. At the time of the discussions, the next refueling outage was scheduled to start in January 1987. The licensee justified not fixing the PIPS during the current shutdown, because much of the work would have to be duplicated during the subsequent PIP connector changeout, causing over 10 person-rem of duplicated radiation exposur The inspector questioned whether some of the indication problems, e.g. ,
no full-in indication, could be caused by faulty light sockets in the control room. These problems could be fixed immediately. The licensee rev'ewed the work and stated that the sockets were functioning normally indicating that the problems will require undervessel repairs. Based on a review of the maintenance requests and discussions with the licensee about the nature and scope of planned undervessel work, the inspector agreed with the licensee's decision to defer the PIP maintenance until the PIP connectors are changed ou Subsequent to their announcement to extend the current outage into 1987 BECO decided to fix the PIP problems prior to restar .0 Management Meetings and Meetings with Local Groups At neriodic intervals during the course of the inspection period, meetings were held with senior facility management to discuss the inspection scope and preliminary findings of the resident inspecto No written material was given to the licensee that was not previously available to the publi On July 30, 1986 a meeting between Region I and Boston Edison senior management was conducted at Region I offices in King of Prussia. The purpose of the meeting was to discuss licensee management program improvements and plans for the upcoming plant outage. The meeting is summarized in NRC Inspection Report 50-293/86-2 The Pilgrim Senior Resident Inspector addressed a special meeting of the Plymouth Area Chamber of Commerce on July 23, 1986. The meeting was held at the request of the Board of Directors of the Chamber of Commerce to discuss recent activities at Pilgrim. Representatives from Boston Edison and a local public interest group, Plymouth County Nuclear Information Committee, also participated in the meeting. The meettna was held in Memorial Hall in Plymout .
 
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i j    Attachment I to Inspection Report 50-293/86-25
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Persons Contacted L. Oxsen, Vice President, Nuclear Operations      ,
j,  *A. Pedersen, Nuclear Operations Manager l  P. Mastrangelo, Chief Operating Engineer j  D. Swanson, Nuclear Engineering Department Manager i  K. Roberts, Director Outage Management
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N. Brosee, Maintenance Section Head T. Sowdon, Radiological Section Head
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J. Seery, Technical Section Head E. Ziemianski, Management Services Section Head
)  S. Wollman, On-Site Safety and Performance Group Leader i B. Eldridge, Acting Chief Radiological Engineer R. Sherry, Chief Maintenance Engineer
:  J. McEachern, Resource Protection and Control Group Leader i  E. Graham, Compliance and Administrative Group Leader
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{  * Senior licensee representative present at the exit meetin I l
 
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,  Attachment II to Inspection Report 50-293/86-25 i
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Security force overtime records were reviewed for the period of June 16 to July 20, 1986. Overtime hours worked in connection with the security force and Boston Edison union strikes were not include Seven Day Work Period Work Period Hours Worked Comments 6/19 - 6/25  84 This individual worked 10 consecutive 12-hour days 6/20 - 6/26  84 6/20 - 6/26  84 6/20 - 6/26  88 This individual worked 8 twelve and one 16-hour days consecutively 7/3 - 7/9  80 7/3 - 7/9  80 A single individual in two
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7/10 - 7/16  80 consecutive weeks
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7/5 - 7/11  78 7/5 - 7/11  88 7/5 - 7/11  88
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7/6 - 7/12  76 7/11 - 7/17  80 Two Day Work Period i
Work Period Hours Worked Comments
,  7/6 - 7/7  32 7/14 - 7/15  36 This individual worked 39 hours in a 51-hour period 7/18 - 7/19  32 This individuai worked 40
;    hours in a 56-hour period  ;
6/16 - 7/20  28 During the period specified 14 different individuals worked  l 28 hours in a 4,-iour period  ' fwenty-four Hour Period
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Work Period Hours Worked Comments
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7/14 - 7/15  20 In a 27 hour period this individual worked 23 hours'
 
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-'      l ATTACHMENT III NRC QUESTIONS REGARDING THE SUPPLEMENTAL RESPONSE -
TO CAL 86-10 The following is a list of comments and questions from NRC Region i about the BECo supplemental response letter, dated June 16, 1986, to CAL 86-10. This list was given to the licensee on July 21, 198 . Has BECo evaluated the merits of periodic checks of RHR system pressure and temperature after (1) startups, (2)
any RHR system high pressure alarm, or (3) after the leakoff system is initially placed in service? Also, has BECo considered periodic checks of RHR system pressure in the absence of high pressure alarms? The first paragraph of BECo's response to NRC question
  "e" describing the proposed leakoff method appears to differ from the method in procedure TP 86-85 and should be clarified. The paragraph infers that the bypass valve will be opened during a measurement step, closed, and reopened to establish the leakage pat . Will a reactor shutdown just be intitiated or will the plant be shutdown (pending an engineering evaluation) if i the 1.0 gpm limit is exceeded? Also, has BECo considered evaluating leakage rates above 1.0 gpm now; rather than waiting to conduct the evaluation until the leakage limit is exceeded? The BECo response and the associated safety evaluation state that leakage into the RHR system will not be allowed to exceed 1.0 gpm. This is not strictly true, since the measured parameter will be leakage through the bypass valve at 150 psig. Changes in RHR check valve leakage (such as after a pump has been operated) could make the leakoff measurements inaccurate and misleadin Has this been considered? Has BECo considered tracking the leakage rate into the torus over extended periods of time as a method of verifying stable RHR system inleakage?
The safety evaluation also states that all RHR pump flow will go into the RHR system. However, some flow could be ,
diverted through the leakoff path if the "D" pump is idle (LPCI only requires 3 pumps operate). BECo should consider modifying the safety evaluation to address these two Concern . The data sheet to procedure TP 85-A2 requires that an RHR pump suction block valve (MO-1001-7D) be closed during the initiation of a controlled leakage path but not reopened (although the procedure does require this). Why has the latter step been left off the data sheet? The acceptance criteria for tests of the RHR injection check valves are not included in the response, as requested (NRC question "f"). The criteria should be determined and submitted to Region . The RHR pressure guage calibration frequency was stated
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to be "once per refueling outage" in the response to question "h." This frequency is not defined in the technical specifications. How is it defined and what is the justification for the frequency?
    . The calibration histories of the RHR high system pressure alarm switches (PS-1001-74A and B) should be submitted to Region I. How is the proposed calibration frequency,"once per cycle," defined and justified? Will the 1001-28 or 29 valve on the "A" RHR loop be maintained normally closed? Procedure TP 86-84 indicates that the -28A valve will be left closed, but the licensee has previously indicated that the 28A will be open and the 29A close . What is the accuracy and reliability of the temperature measuring markers? What specific change in temperature will require that additional measurements be taken with a portable measuring device? What are the accuracy and reliability of the portable temperature measuring device?
11. Will the licensee verify seating of the RHR check valves after operation? If not, why not?
12. Why will it take 9 months to submit a technical specification change to reduce compensatory surveillance testing in LCO's; considering that the issue was identified mid-1985 in connection with the on-line EQ modifications and also noted in the 1985 SALP report? Has the licensee considered contacting other facilities of a similar age to see if they have information that could be used to speed the evaluation and submittal process?
13. What is the justification for limiting RHR pipe temperature to no less than 15 degrees of saturation temperature? Is this temperature margin adequate, considering that pipe wall temperature (rather than interior water temperature) is the measured parameter?
14. Calculation M-269 should be submitted to Region I for revie . The following comments concern the draft procedure TP 86-81 which will control the test for spurious group I primary containment isolations during the neFl reactor startu Will reactor level instrument vibration be monitored? If not, why not?
  -- Step VI.A indicates that the reactor mode switch will be placed in run for 24 hours. Why?
  -- Was a functional test be conducted of the PCIS logic after the GETARS modification was installed?
What procedure was used for the functional test?
  -- Can the spurious isolation test be conducted at a ...a-. . . . .
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power below the stated 30%?
16. Does BECo plan to conduct a sampling review of other systems, given the large number of drawing / loose wire problems discovered during werk on the reactor mode switch?
17. Why is local venting of the RHR system needed in addition to the keep fill system?
18. Is the RHR system always filled and vented after the 1001-34 and -36 valves are opened to depressurize the system?
19. Has BECo considered the personnel safety aspects of the leakoff measu>ement process? At what location will system pressure be measured and what will be the expected water pressure at the measuring point? Will the measurement, equipment withstand this water pressure?
20. Has BECo considered testing the leakage of injection check valves in ECCS systems other than LPCI?
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Latest revision as of 08:18, 18 December 2021

Corrected Pages 2 & 16 to Insp Rept 50-293/86-25,correcting Date for Performance of Surveillance Test Procedure 8.M.2-1.5.8.4 to 860626
ML20215N727
Person / Time
Site: Pilgrim
Issue date: 10/30/1986
From:
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20215N721 List:
References
50-293-86-25, NUDOCS 8611070201
Download: ML20215N727 (2)
v • d • e


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= Appendix A 2

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Contrary to the above, on the dates indicated below, the following surveil-lan'ce test procedures were performed and steps implementing verification and independent verification of system response and system restoration were not completed: PNPS Procedures 8.M.2-1.S.8.4, Logic System Functional Test of System

"B" Standby Gas Treatment Initiation, Reactor Building Isolation and Outboard Drywell Isolation Valves on June 26, 198 . PNPS Procedure 8.M.2-1.4.1, Revision 12, Main Steam High Temperature Sensors Functional Test, on April 5, 1986, and May 7, 198 This is a Severity Level V Violation (Supplement I).

Pursuant to the Provision of 10 CFR 2.201, Boston Edison Company is hereby re-quired to submit to this office within thirty days of receipt ~of the letter

.which transmitted this Notice, a written statement or explanation in reply in-

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cluding (1) the corrective steps which have been taken and the results achieved; (2) corrective steps which will be taken to avoid further violations; and (3)

the date when full compliance will be achieved. Where good cause is shown, consideration will be given to extending this response tim 'PDR ADOCK 05000293 G PDR

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established in 1985. The inspector will review the individual discrepan-cies, and any compensatory measures taken, to determine compliance with the technical specifications during a future inspection (86-25-10).

Boston Edison Quality Assurance Manual (BEGAM) Section 16 establishes the corrective action program, and requires that deficiencies be identified and processed in accordance with Section 15 of the BEQAM. Section 15 states that nonconforming components are documented and reported via a Failure and Malfunction Report (F&MR). PNPS procedure 1.3.24, Revision 12, Failure and Malfunction Reports states that an F&MR shall be initiated

.whenever any abnormal plant condition has the potential to adversely affect safe operation Timely and effective processing of an F&MR is important in establishing-operations staff awareness of potential or actual ~ problems. Technical specifications _ require establishment of a fire watch within _one hour of finding an inoperable fire barrie Failure to effectively use the cor-rective action program both as the individual discrepancies were identified, and after the summary of discrepancies was compiled on July 2,1986, demon-strates a programmatic weakness. ~ The inspector informed the licensee that the above constitutes a violation of 10 CFR 50 Appendix B (86-25-09).

8.0 Local Leak Rate Testing Status During this reporting period, 1 type "B" as-found local leak rate test (LLRT) failure was found. The outboard flange of the inboard drywell purge exhaust valve had leakage greater than 20 sim. This leakage will be. quantified prior to its repair work. Also 3 type "C" as found LLRT failures were found, i.e. , the outboard drywell purge exhaust valve, the inboard post accident sample system (PASS) return valve, and the inboard drywell' equipment drain valve. Between August 4, 1986 and April 11, 1986, 87 of approximately 101 type "B" components have been tested with 2 fail-ures, and 123 of approximately 133 type "C" components have been tested with 15 failure During conduct of leak rate testing on the containment floor drain sump isolation valves the inspector noted that while two LLRTs had been per-formed on that day, no test cart bypass valve leak test had been performed as required by procedure. This concern had been previously identified by the. inspector and discussed with licensee personnel. While the signifi-cance of the incidents is minor, the licensees failure to correct them raises concern. ~The inspector discussed this problem at the exit meetin l l

OFFICIAL RECORD COPY 403STROSNIDER10/27/86 - 0004.0.0 1 10/27/86 l t

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