IR 05000293/1986037

Insp Rept 50-293/86-37 on 861021-1124.Violations Noted: Inadequate Implementation of Fire Brigade Training Requirements & Mod

ML20207K189
Person / Time
Site:	Pilgrim
Issue date:	12/23/1986
From:	Wiggins J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20207K138	List: IR 05000293/1986037 ML20207K135 ML20207K153
References
50-293-86-37, NUDOCS 8701090349
Download: ML20207K189 (21)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket / Report N /86-37 Licensee: Boston Edison Company 800 Boylston Street Boston, Massachusetts 02199 Facility: Pilgrim Nuclear Power Station Location: Plymouth, Massachusetts Dates: October 21, 1986 - November 24, 1986 Inspectors: M. McBride, Senior Resident Inspector

! J. Lyash, Resident Inspection L. Doerflien, Project Engineer Approved by: uAf- -

/2 /z,3 [N J.giggins,'C(jpf,ReactorProjects ' Datd Section IB Areas Inspected: Routine resident inspection of plant operations, radiation

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protection, physical security, plant events, maintenance, surveillance, outage activities, and reports to the NR Results: Two violations were identified regarding implementation of fire

, brigade training requirements, section 3.e, and inadequate implementation of a modification, section The performance of operations and maintenance personnel in response to the November 19, 1986 loss of offsite power was thorough and effective and described in section 4.c. Several areas of concern were identifie Weakcess in management oversight of station overtime is described in section 2. Similar weaknesses were identified in the 1985 Systematic 3 Assessment of Licensee Performance (SALP) and in inspection 86-2 Corrosion of salt service water piping is described in section 2.

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The lack of permanent maintenance procedures for HPCI steam balance chamber adjustment is discussed in section 2.

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The failure of GE CR 120A relays is described in section Failure to properly install an electrical jumper during a test is described in section Failure to control vital area barriers is described in section I

8701090349 861231 PDR ADOCK 05000293 o PDR l

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Weaknesses in control of extended RWPs is described in section Additional SBGT system single failures are described in section A potential primary containment isolation system design discrepancy is described in section Concern regarding the acceptability of manning the ENS line with an

, administrative assistant is described in section A part 21 report concerning defective cable is described in section

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The poor quality of station drawings is described in section !  :

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Possible seismic qualification deficiencies for GE HGA relays are

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TABLE OF CONTENTS PAGE Summary of Facility Activities .............................. 1 Followup on Previous Inspection Findings .................... 1 Violations, Unresolved Items, Inspector Follow Items, TMI Action Plan Items Routine Periodic Inspections . .............................. 6 Plant Maintenance and Outage Activities ................ 7 Sum eillance and Preoperational Testing ................ 8 P hy s : a l S e c u r i ty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Radiation Protection and Chemistry ..................... 11 Fire Protection ..... .................................. 11 Review of Plant Events ...................................... 14 Standby Gas Treatment System Part 21 Update ............ 14 Primary Containment Isolation Logic Discrepancy. . . . . . . . . 15 Loss of Offsite Power .................... ............. 16 Defects in Cable Supplied by BIW Cable Systems Inc. .... 16 Seismic Qualification of General Electric HGA Relays ........ 17 Review of Licensee Event Reports (LERs) . . . . . . . . . . . . . . . . . . . . 17 Management Meetings ...... .................................. 18

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Attachment I - Persons Contacted (

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DETAILS 1.0 Summary of Facility Activities The plant was shutdown on April 12, 1986 for unscheduled maintenance. On July 25, 1986, Boston Edison announced that the outage would be extended to include refueling and completion of certain modification .0 Followup on Previous Inspection Findings Violations (Closed) Violation (86-21-02), inadequate 125 VDC and 250 VDC surveillance test procedure. PNPS Procedure 8.9.8, revision 8, Battery Rated Load Discharge Test, did not contain adequate instructions. Steps addressing required system alteration and restoration were not included. Immediate actions taken by the licensee to ensure proper system restoration were inspected and described in inspection report 50-293/86-21. Boston Edison, in response to the violation, stated that the procedure would be revised to fully address performance of test activitie The inspector reviewed PNPS procedure 8.9.8, revision 12. Attachments E, F and G to the proce-dure have been revised to clearly document all lifted leads, installation and removal of temporary jumpers and test equipment, and isolation of required loads. The inspector witnessed portions of the 125 VDC "A" battery discharge test performed using the revised procedure, and reviewed the completed test results. Test performance and results appeared to be adequate. The inspector had no further questions. This item is close (0 pen) Violation (85-26-05), failure to take corrective action to prevent unauthorized reactor operator overtime. The inspector reviewed memoranda from the Vice President-Nuclear Operations and the Director-Outage Management, dated May 14 and May 24, 1986 respectively, to all station personnel. To control overtime, the licensee established a policy of limiting all employees to sixty hours per week without prior department manager approval. Weekly reports are sent to the Vice President-Nuclear Operations identifying and providing justification for those personnel who worked in excess of sixty hours per week. These overtime reports cover the calendar week, Sunday through Saturday. A Director-Outage Management memorandum dated July 31, 1986 provides clarification that the sixty hour limit applies to any seven day work period. During discussions with several supervisors, the inspector determined that they were familiar with and understood the overtime polic However, the inspector reviewed the overtime records for eight maintenance and operations personnel for the period October 5-26, 1986 and identified two individuals who. worked in excess of sixty hours in a seven day period (70 and 83 respectively) and were not listed on the weekly overtime report. The inspector noted that the unauthorized 83 hours9.606481e-4 days <br />0.0231 hours <br />1.372354e-4 weeks <br />3.15815e-5 months <br /> worked by the one individual, exceeded NRC and procedure 1.3.34 guidance on overtime limits. Based on the above the inspector concluded that the licensee's control of overtime is still not adequat .

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Following the exit meeting, the licensee stated that Radwaste Operators were more likely to inadvertently exceed overtime guidelines because they work rotating shifts. The licensee plans to track their overtime on a computer, using a sliding seven-day time period. Since Maintenance Department personnel do not work rotating shifts, the licensee believes them less likely to exceed overtime guidelines. A licensee audit will be conducted to determine whether the maintenance overtime problem identified during the inspection was isolated or symptomatic of a broader weaknes Lack of management control over worker overtime was an issue in the 1985 Systematic Assessment of Licensee Performance (SALP) and a concern dis-cussed in NRC inspection 50-293/86-2 Unresolved Items (Closed) Unresolved Item (85-03-10), licensee does not have an effective method for verifying proper system configuration following maintenance without a subsequent surveillance test. The inspector reviewed procedures 1.4.5, PNPS Tagging Procedure, Revision 17, and 1.5.3, Maintenance Requests, Revision 18. The licensee revised the tagging procedure to include independent verification when placing protective tags as well as when returning the system to normal during tag removal. The maintenance request procedure was revised accordingly to reflect the changes made in the tagging procedure. Both procedures were approved by the Operatinq Review Committee. The licensee plans to train all operations and mainte-nance personnel on these procedures prior to their implementation. The inspector had no further questions concerning the ite (Closed) Unresolved Item (82-18-01), licensee to review and revise the 3.M.2 series procedures in accordance with the requirements specified in ANSI N18.7. The inspector reviewed several of the 3.M.2 series calibration procedures and held discussion with licensee personnel. The procedures now require recording the "as found" and "as left" calibra-tion data, the test date, and identification of personnel conducting the test and reviewing the results. The inspector noted that data is still recorded on the Visicorder file cards, however, this now serves as a backup source of information. The inspector also reviewed several com-pleted calibration data sheets and determined that the revised procedural requirements were properly implemented. The inspector had no further question concerning this ite Inspector Follow Items (Update) Inspector Follow Item (86-34-05), review licensee evaluation of surface indications identified during ISI. Two additional surface indications were identified during magnetic particle examination of piping in the "A" residual heat removal system. This brings the total number of identified surface indications to ten. Two of the main steam line indications have been examined in detail and found to be markings only. The remaining indications will be evaluated in the future. The inspector will review the licensee's evaluation and any repairs neede u n

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4 v (Update) Inspector Follow Item (86-34-01), salt service water piping corrosion. The licensee identified a through wall leak in a section of salt service water (SSW) piping at the outlet of the "A" reactor building closed cooling water heat exchanger. During this inspection period the licensee removed the affected section of piping for examination and repairs. The anti-corrosion coating applied to the piping inside diameter had been torn away resulting in accelerated corrosive attack in the area of the leak. In addition, other areas on the pipe internal surface and piping flanges were observed to have significant corrosion damage. A circumferential carbon steel patch was welded in place over the area of the leak. All internal pipe and flange surfaces were recoate The inspector reviewed Temporary Modification 86-30 and Safety Evaluation (SE) 2014 which contain approvals of, and restrictions on, these repair SE 2014 stipulates that the defective section of piping must be replaced prior to plant startup or within six months. In addition monthly ultrasonic reexamination of the damaged piping flange area is require This item will remain open pending implementation of permanent repairs and completion of the licensee's root cause analysi (Update) Inspector Follow Item (86-29-03), review licensee analysis of SBGT system single failures. Two additional SBGT subsystem single failures were identified by the licensee and reported to the NRC. These failures are described in section 4.a of this *epor (Update) Inspector Follow Item (86-14-07), Review licensee evaluation of loose wiring. On November 17, 1986, the inspector met with licensee representatives to discuss evaluation preliminary results. The licensee stated that a review of failure and malfunction reports, deficiency reports, nonconformance reports, and maintenance requests had identified 17 termination failures. Based on a comparison of the total failures to the numbe. of existing terminations the licensee concluded that these cases appear to be isolated. The inspector questioned the distribution of the identified failures in relation to time of occurrence, type of activity, type of connection and location. The inspector also questioned the status of the root cause analysis specific to the recent occurrence This item remains open pending completion of the licensee's evaluation in f these area (Closed) Inspector Follow Item (84-01-01), licensee to revise operating experience review (OER) progra The inspector reviewed procedure 1.3.33, " Operating Experience Review", Revision 4, dated June 5. 1986, various records, and interviewed personnel to determine the adequacy of the licensee's OER program. The inspector noted that external and internal operating experience feedback is screened for applicability and significance by the Onsite Safety and Performance Group. Action items, assigned through the plant manager, are initiated for recommendations not covered by existing proceoures or desig .

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Action items are tracked for completion and the responses are reviewed for adeque.cy. Recommendations initially determined to be not applicable are reviewed and approved by the Technical Section Manager. Monthly OER status reports are distributed to management personnel which describe new documents received and action items closed during the report period as well as a listing of open action items, including responsible managers and due dates. The inspector noted that the licensee recently added approximately 300 old documents to the system, particularly GE Service Information Letters, to ensure proper closeout. A large backlog exist However, the licensee has recently maintained a positive trend in reducing the backlog. In addition to annual QA audits of the OER program, the licensee exchanges OER program " effectiveness" audits with another utility on an annual basi The inspector reviewed the latest effectiveness audit and noted that the findings and recommendations were relevant and useful. The licensee initiated an open item to track re;olution of the audit findings. Based on this review, the inspector

@ termined the licensee was adequately implementing the OER progra {!%ie) Licensee Event Report (LER) Follow Item (82-LC-06), HPCI stop W.v4 eain disc flange broken capscrews. This item was last updated in ingeMn report 50-293/82-10. General Electric SIL number 352, Steam Balance (;aamber Adjustment, was issued to advise licensees of the need for careful adjustment of stop valve balance chamber pressur Insufficient balance chamber pressure could result in failure of valve internals due to severe transients during opening. Excess pressure could result in failure of the valve to open on demand. On March 9, 1982 during inspection of the HPCI stop valve and implementation of SIL 352, the licensee found that three of four internal valve disc capscrews were broken. Engineering analysis of the failure determined the cause to be impact loading of the components due to improper steam balance chamber adjustmen Subsequent adjustments in accordance with the SIL were made using Temporary Procedure TP 82-17. However, no permanent corrective or preventive 'naintenance procedure was established. In May 1985, during troubleshooting efforts in response to turbine overspeed trips, a steam balance adjustment was again performed. A temporary procedure was again utilized. The as-found chamber p* essure was unacceptabl Balance chamber adjustment at periodic intervals and following stop valve maintenance appears to be necessary to prevent recurrence of cracked cap screws. The licensee however, presently has no established schedule or procedure for performance of this adjustment. At the exit meeting, licensee maintenance management informed the inspector that appropriate controls would be established. This item remains open pending

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3.0 Routine Periodic Inspections The inspectors routinely toured the facility to assess general plant and equipment conditions, housekeeping and adherence to fire protection, security and radiological control measures. Ongoing work activities were monitored to verify that they were being conducted in accordance with approved administrative and technical procedures, and that proper communi-cations with the control room staff had been established. The inspector observeo valve, instrument and electrical equipment lineups in the field to ensure that they were consistent with system operability requirements and operating procedures.

t During tours of the control room, the inspectors verified proper staffing, access control and operator attentiveness. Adherence to procedures and limiting conditions for operations were evaluated. The inspectors examined equipment lineups and operability, instrument traces and status of control room annunciators. Various control room logs and other available licensee documentation were reviewe In addition to routine equipment operability confirmation, the inspectors performed independent walkdowns of selected safety systems. Confirmation of the as-built system configuration, identification of degraded conditions and procedure adequacy were evaluate The inspector observed and reviewed outage activities, maintenarece and problem investigation activities to verify compliance with regulations, procedures, codes and standard Involvement of QA/QC, safety tag use, personnel qualifications, fire protection precautions, retest requirements, and reportability were assesse The inspector observed tests to verify: performance in accordance with approved procedures and LCO's, collection of valid test results, removal and restoration of equipment, and deficiency review and resolutio 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 inspecto Checks were made to determine whether security conditions met regulatory requirements, the physical security plan, and approved procedures. Those checks included security staffing, protected and vital area barrier in-tegrity, personnel identification, access control, badging, and compen-satory measures when require _ _ _ _ _ _

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a. Plant Maintenance and Outage Activities

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The licensee is presently installing a new plant process computer. The final step in this installation is the connection of computer cables to the process systems tap points. Signal cut-in sheets specifying the point to be tied in, the affect on system condition during the tie-in process, post work testing and Watch Engineer approval are prepared and implemented by Boston Ediso On October 27, 1986, during tie-in of High Pressure Coolant Injection (HPCI) steam supply valve MOV 2301-5 position ;

indication, a valve close signal was generated. The valve was ;

already full closed. The signal bypassed all torque and limit '

switches resulting in operation of the motor operator at locked rotor for a period of time. The HPCI tie-in was supposed to be done on-line and affect valve indication only. Because the tie-in was done during an outage, certain valve automatic closure signals existed which had not been considered during development of the post work testing. Execution of the pre- [

scribed testing during the outage resulted in the inadvertent \

valve closure. The licensee performed a review of all similar (

tie-ins and concluded that the event was isolated. Maintenance

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Request MR86-23-64 was initiated to replace the MOV 2301-5 operator moto The inspector reviewed a sample of four computer point cut-in sheets to determine the effect on system operability and the adequacy of post work testing. The tie-in of position indication for Reactor Core Isolation Cooling System Minimum Flow valve, MOV 1301-60, was also supposed to be done on-lin The cut-in sheet further stated that only remote valve position indication would be affected and that no system operability concerns existed. The inspector noted that system isolation and initiation signals could be affected depending on the exact placement of computer cables on the associated terminal stri The licensee stated that the computer tie-in was to be landed on the cabinet side of the terminal strip, and that for this situation the tie-in sheet was adequate. In response to the inspector's questions the licensee re-evaluated the tie-in and identified that terminations had actually been made on the field side of the terminal strip. Had the tie-in been per-formed on-line as planned the operability of the valve would have been affected. Because the tie-in was done on the wrong a side of the terminal strip, the post work testing performed did not adequately test the circuit. Only the continuity of the indicating light circuit was checked. Proper restoration of the initiation and isolation circuit was not tested.

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All ongoing tie-in activity was stopped by the licensee pending review of the situation. Further evaluation by the licensee identified a total of sixteen computer point tie-ins which had been performed incorrectly, at least ten impacting safety related systems. The licensee stated however, that no additional component operability concerns similar to those of MO 1301-60 had been locate The inspector informed c'ne licensee that failure to properly implement design modifications to safety-related components and to perform adequate post work inspections constitute a violation of technical specifications (86-37-01).

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On October 31, 1986, Failure and Malfunction Report (F&MR) N P6-353 was originated to investigate the loss of position indication for the shutdown cooling suction isolation valve (MO-1001-50). During the subsequent troubleshooting, the licensee determined the cause of the problem was a burned out coil in relay 16A-K66. This is a GE type CR 120A relay which is normally energized and used to provide indication of MO-1001-50 valve position in the control circuit of the A residual heat removal injection valve (M0-1001-29A). The coil in relay 16A-K66 was replaced and the system returned to normal. The licensee also informed the inspector that there have been at least three other type CR 120A relay coils burned out since the startup in December 1984 from the sixth refuel outage. As a result, the licensee plans on further evaluation, including contacting the relay vendor, to determine the root cause of the relay coil failures. The inspector will review the results of this evaluation in a subsequent inspection (86-37-02).

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b. Surveillance and Preoperational Testing

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On October 31, 1986, the inspector witnessed portions of Surveil-lance Procedure 8.E.23, Revision 11, HPCI System Instrumentation Calibretion. Step three of the procedure addresses isolation, calibration and return to service of pump discharge flow trans-mitter FT-2358. The recommended calibration method for the Rosemount transmitter is to remove the instrument side cover and measure output at the test points provided. Procedure Step documents replacement of the side cover 0 ring, application of silicone grease and retorquing of the side cover. The inspector noted that step 3.C had been marked as not applicable by the technicians. Discussion with the technicians revealed that the actual calibration had been performed by removing a nearby junction box cover, lifting the transmitter cables from the terminal block and connecting an ammeter in series. By using this method the transmitter side cover was not removed. The inspector questioned the acceptability of both lif ting leads and

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using a test method not documented in the procedure. Licensee maintenance personnel stated that the ability to perform this type of calibration was within the skill of the craft and need not be documented by procedural steps. The licensee further stated that a sign-off indicating instrument return to service would provide adequate assurance that the leads had been relanded. The inspector will review the acceptability and application of this practice in a future inspection (86-37-03).

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On October 31, 1986, the inspector witnessed a simulated loss of offsite power test of the "A" diesel generator. The testing was conducted following 10 CFR 50 Appendix R modifications to the system and was controlled by a portion of temporary proce-dure, TP 86-135, "Preoperational Test of the Standby AC Power System (Diesel Generator A)". During the test, jumpers were used to (1) generate a loss of offsite power logic signal to start the diesel generator and (2) simulate the opening of the normal feeder, breaker to the 4160V safety bus to allow the diesel generator breaker to close. The test checked that the diesel started and the generator breaker (in the racked down position) closed when the remote control panel was active

. instead of the normal control room pane A test director was stationed in the control room during to test and directed personnel in the upper switchgear room and in the diesel generator _ buildin The inspector noted the following during the test:

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The inspector found that a jumper was incorrectly placed in step 6.L. This jumper was supposed to signal the diesel generator logic that the 4160V AC feeder breaker

! from the startup transformer to bus A5 had been opene Instead of jumpering terminals J2 and J3 in cubicle A504 j as required by the test procedure, the licensee worker

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jumpered terminals J1 and J2. A few minutes before the i incident, the worker had questioned the test director  !

about the jumpering step in the procedure to ensure that i the proper terminal strip was selected. The inspector observed the worker read the procedural step just prior to installing the jumper. The inspector noted that in-dependent verification of the procedural step, although not. required by the NRC, might have prevented this mistak Independent verification steps were used in the test pro-- ,

cedure to verify that jumpers were removed and the equipment

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I After the improper jumper was identified by the inspector, the licensee halted the test and reviewed electrical draw-ings to verify that the' jumper had not damaged plant equip-

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ment. .The test was successfully rerun the next day. At the exit meeting, the licensee stated that jumper installation under temporary test procedures would be independently veri-fled in the futur An operator was asked to time the closing of the diesel generator output breaker but was not clearly told when to start the timing interval. As a result, he did not properly time the closing sequence. Although the licensee workers recognized the problem immediately, the mistake invalidated the test run and could have caused extra equipment wea Despite these mistakes, the test appeared to be closely controlled by the test director. The A diesel generator was subsequently returned to servic The inspector had no further questions concerning this portion of the preop test. Additional 4 preoperational tests will be reviewed during future routine inspection ,.

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4 Physical Security On November 7, 1986, licensee security personnel determined that a temporary security vital area access barrier was not adequately secured and may not have prevented access. The questionable barrier was identified by licensee security supervisors. The barrier was promptly secured and all other similar temporary barriers were inspected. A 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> report in accordance with 10 CFR 73.71 was initiated. Actions taken by the licensee in this case appeared appropriat Later that day, the licensee identified a second degraded vital area access barrier. Contractors apparently removed part of the barrier without prior security notification, creating an opening into the area. This condition existed for approximately one hour before com-pensatory security measures were taken. The NRC was notified of the incident. Periodic security reviews and walkdowns of all ongoing modification activities have been instituted to prevent recurrenc Instructions and training addressing the required controls applied when impacting a vital area barrier were provided to all licensee and contractor personnel involved in plant modification work. In addition both those supervising the work activity, and security supervision, will be required to document communications concerning barrier com-pensatory actions. Other established security measures provided additional access control to these areas. This. item' remains unre-solved pending review of the effectiveness of compensatory measures and corrective actions taken (86-37-04).

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11 Radiation Protection and Chemistry On October 31, 1986, the inspector noted that the extended radiation work permit (RWP) briefing sheet for the High Pressure Coolant Injec-tion (HPCI) room had not been updated to reflect ongoing work in the area. The extended RWP system was established to allow individuals ease of access to radiologically controlled areas, including high radiation areas, during routine plant tour Individuals are respon-sible for reviewing the extended briefing sheet and adhering to the specified requirements. PNPS procedure 6.1-022, Radiation Work Per-mits, requires that the extended RWP briefing sheets be updated by health physics personnel to reflect the issuance of other RWPs in the same area. This ensures that individuals entering an area under the

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extended RWP are appraised of the status of work and adhere to the most restrictive clothing, monitoring, respiratory protection and ALARA requirements. At least two RWPs had been issued for work in the HPCI room, but the briefing sheet had not been updated. When

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informed by the inspector, radiation protection personnel immediately withdrew the extended RWP covering the HPCI roo The licensee conducted a review of all working RWPs to assess their impact on the extended RWP system. Three additional cases of failure to properly update ^the extended RWP briefing sheet were t

identified. None of the instances involved locked high radiation areas. Dress requirements specified on the outstanding RWPs were similar to those listed on the extended RWP The licensee counseled all radiation protection personnel ctncerning their responsibility to update extended briefing sheets. Twice daily comparison of RWPs issued for work against the extended RWP briefing book were initiated. The RWP issue log was revised to include a technician sign off stating that the applicable extended RWPs have been updated prior to issuance of any additional RWP. The inspector noted that the RWP issue log and the twice daily review are informal and are not proceduralized. At the exit meeting the licensee stated that existing procedures, supplemented by these informal controls, will be adequate to prevent recurrance. The inspector expressed con-cern about the use of informal controls in the RWP process. This item remains unresolved pending review of the effectiveness of these measure (86-37-05) Fire Protection

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On November 11, 1986, the licensee found that most of the water supply for the site fire suppression system had been inadvert-ently valved out of service for several days. On November 5, one of the two fire water storage tanks (T-1078) was' drained in preparation for repairs to a heater coil in the tank. The A tank, however, was inadvertently isolated from the fire water system instead of the B tank, because of a drawing error. The

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problem was identified on November 11, when fire water system pumps activated to supply water to a fire hose being used to wash down the inside of the B tank. Both the diesel and the electric fire pumps started, but fire water pressure and flow could not be maintaine The pumps were manually shut down after several minutes of operation without a suction sourc The electric fire pump sustained packing damage and could not maintain required flow during a subsequent check. The diesel fire pump was not damaged during the incident. The A storage tank has been returned to service, and repairs are continuing on the B tank. NRC special inspection 50-293/86-38 evaluated the circumstances surrounding this even On November 4,1986, the inspector observed a fire brigade l drill. The brigade was summoned to the turbine deck using the plant fire alarm and page. The brigade donned fire fighting clothing and brought self contained breathing apparatus (SCBA) l and radios to the scene of the hypothetical fire. The inspector l observed two brigade members get their SCBA's at the fire lockers '

and subsequently, followed them to the fire site. The brigade leader was already at the scene. Three additional brigade members arrived within a few minute Although the brigade members demonstrated that they could respond promptly to the scene of the hypothetical fire, they did not actively participate in the remainder of the dril ;

The inspector noted the following problems: l

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The fire (a hypothetical pile of combustible material) was not simulated. The drill scene was an empty area of floor i on the turbine dec )

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Except for health physics surveys, no fire-related activities were acted out. Instead, the brigade leader discussed his plans with the Fire Prevention and Protection Officer (FPP0)

who conducted the drill. The brigade stood nearby during these discussion No fire hoses or fire extinguishers were broken ou Communications were not established with the control room during the drill. At one point, the brigade leader indi-cated that he would summon additional personnel to check for fire on lower levels of the turbine building. However, no one was summoned. The' brigade leader also indicated that he would shut down turbine building roof exhaust fans

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I to limit radiological releases from the fire but he did not simulate this actio . --

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The FPP0 repeatedly prompted the brigade leader during the dril Examples of the prompting included asking the leader to brief the last three brigade members who assembled at the drill scene and instructing the brigade leader on fire dis-persal technique In some cases, the prompting occurred before the brigade leader had the opportunity to initiate (on his own) the prompted action The licensee s completed fire drill checklist, procedure 1.4.23, i

stated that the drill's objective was to evaluate the brigades response to the fire scenario, i.e. a loose combustible fire on the turbine deck with possible radiant heat and smoke exposure to the turbine generator. However, the inspector concluded that the brigade could not be judged against this objective, due to the lack of active drill participation by the brigade members and the excessive prompting and training during the drill. A similar criticism of fire protection dr. ills was made in NRC in-spection report 50-293/81-24. At that time, practice exercises were incorrectly classified as drill The vagueness of this drill objective made conducting the drill and critiquing the drill objective difficult. Two additional, more detailed drill objectives were identified for the November 4 drill, but only one of the two was mentioned in the drill critiqu Procedure 1.4.23,Section II suggests that the drill objectives be clearly established to ensure brigade actions conform to the drill scenario. In addition, the NRC guidance document, " Nuclear Plant Fire Protection Functional Responsibilities, Administrative Controls and Quality Assurance", requires that training objectives be established for the drills and the drills critiqued to determine how well the objectives were me The licensee's completed drill checklist indicated that the drill had acceptably .2monstrated brigade performance. One drill ciriticism was noted, i.e., some brigade members did not

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bring lignts to the drill scene. An action request was initiated for this proble Technical Specification 6.4, " Training", requires that fire bri-gade training meet or exceed the requirements of NFPA Standard No.27-197 Section 51 of NFPA Standard No. 27-1975 requires that practice drills check the ability of members to perform the operations they are expected to carry out with the fire equipment provide In addition, Section 52 of NFPA Standard No. 27-1975 states that during drills, equipment should be operated whenever possible. Failure to adequately check the ability of fire bri-gade members to perform the operations they are expected to carry out with the fire equipment provided on November 4, 1986 is a violation of the technical specifications (86-37-06).

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On December 11, 1986, the licensee indicated that the following corrective actions would be taken to address this apparent violation:

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The November 4,1986 fire brigade drill will be declared invalid and the brigade training records will be appropri-ately revise Fire brigade activities will be more actively simulated in drills after December 11, 1986. These drills will include breaking out fire hoses, establishing communications, and simulating other fire brigade activitie Procedure 1.4.23 will be revised by January 22, 1987 to require a written evaluation of the brigade's ability to meet the drill objective The licensee stated that the licensee's emergency planning group would be asked assist in preparing drill scenarios. A meeting between the two groups is scheduled for December 22, 1986. The licensee also stated that full compliance with the technical specification requirement for fire brigade training was achieved by December 12, 198 The inspector concluded that the above corrective measures were acceptabl l 4.0 Review of Plant Events l The inspectors followed events occurring during the period to determine if licensee response was thorough and effective. Independent reviews of the events were conducted to verify the accuracy and completeness of licensee informatio Standby Gas Treatment (SEGT) System Part 21 Report Update  ;

On August 21, 1986 licensee personnel identified a potential single '

failure which could affect the ability of the SBGT system to perform as designed. The redundant SBGT system trains are crosstied by an air *

operated fail-open damper. With a loss of offsite power, motive air to the crosstie damper would be unavailable. A single failure could  !

cause activation of the charcoal bed deluge spray system in one train, rendering it unable to remove radiocctive iodine as designed. The affected train could not be isolated from the remaining train because of the failed-open crosstie damper. Approximatcly twenty-five percent of the system flow would be drawn through the ineffective charcoal bed resulting in elevated release levels. This design problem was des-cribed in Inspection Report 50-293/86-2 .

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On October 30, 1986 the licensee informed the NRC via Emergency Notification System telephone that two additional SBGT subsystem single failure potentials had been identified which could impair SBGT system performance. These potential failures were discovered during an engineering review conducted as follow up to the initial Part 21 repor Each SBGT train is provided with a humidity control system. A multi-element heater-is installed upstream of the HEPA filters on the train inlet. The heater energizes whenever the associated blower is energized and the temperature is less than 150 degrees In the present configuration, the blower in the inactive train is not energized therefore the heater would not energize. In post. accident conditions the twenty five percent bypass flow through the inactive train would not be subject to humidity control; resulting in moisture buildup in the charcoal bed Furthermore, a single failure in the humidity control system of the active train could also result in charcoal bed moisture absorption and reduction in efficienc The second single failure reported on October 30 involves the system crosstie damper. If this damper were fully or partially close, it would restrict the cooling air flow ,2* red to remove the decay heat of the radiciodines deposited on the inactive treatment train charcoal beds. This could lead to elevated temperatures, possible fire and the release of the deposited radiotodine The inspectors will review the licensee's evaluation results and the affect of these finoings on the operability of the SBGT system for I refueling purposes. This followup will be conducted under established item 86-29-0 b. Primary Containment Isolation Logic Discrepancy l The licensee notified the NRC via ENS on October 31, 1986 that a pos- ,

sible design deficiency in the Primary Containment Isolation System l (PCIS) logic had been identified. Pilgrim Technical Specifications '

require that a PCIS Group One isolation on reactor high water level be operable in all modes except run. The actual PCIS design contains reactor high water level and main steam line low pressure isolations signals in paralle Therefore with reactor pressure greater than 880 psig and the mode switch not in run, the high water level isola-tion is not operable in conflict with technical specification The l FSAR and technical specifications are not consistent regarding the I design bases and safety function of this isolation function. The licensee is evaluating this discrepancy. The inspectors will follow licensee actions on this issue (86-37-07).

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16 Loss of Offsite Power

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On November 19, 1986 at approximately 8:05 am Pilgrim Nuclear Power Station lost all sources of offsite power. The unit was in cold shut-down with a moderator temperature of 100 degrees The loss of power was a result of distribution network or switchyard problems, possibly caused by an ongoing winter storm. Both emergency diesel generators started automatically and energized the station vital electrical buse :

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The NRC was notified via ENS at 8:52 am. At approximately 9:00 a.m.,

a reactor building evacuation was ordered due to lack of general area lighting and personnel safety considerations. Vital electrical power

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was aligned to energize one reactor protection system power distri-bution channel allowing reset of certain contair. ment isolation signals

and resumption of reactor vessel shutdown cooling at 9:20 a.m. Moder-ator temperature had risen to approximately 112 degrees F. The ENS line was determined to be nonfunctional at 9:35 am and an alternate

communication to the NRC Operations Center by commercial telephone was established. An open line to NRC Headquarters and Region I was maintaine By about 11

30 am, November 19, 1986, both normal offsite power sup-plies had been restored and non-vital loads were transferred to off-site power. Normal offsite power to both vital buses was restored at 12:38 p The licensee performed the monthly full load surveil-lance test on both diesel generators because of their prolonged run at low load. A definite cause of the loss of offsite power has not been determine Operations and maintenance personnel performance during the incident appeared to be effective, thorough and safety conscious. The inspec-l'

tor noted that during the incident, the licensee utilized an admini-strative assistant (AA) to man the ENS line. Inspection and Enforce-ment Information Notice 86-97 explains that licensee's must provide qualified personnel to maintain the ENS. Even though the licensee had not entered an emergency condition, the inspector questioned whether an AA should have been used to convey technical information over an open ENS link to NRC. The licensee acknowledged the inspec-toi's concern d. Defects in Cable Supplied by BIW Cable System In On November 3,1986, BIW Cable Systems, Inc., reported a defect in Bostrad 7E, 600 volt instrumentation cable to Region I under 10 CFR 21. The defect involved non-uniform insulation wall thickness. Due to a manufacturing process problem, the individual conductor insula-tion was not adequately cure Consequently, insulation performance over the life of the cable cannot be assured under this conditio Subsequently, the licensee announced that approximately 18,000 feet of this cable, recently installed in the plant for analog-trip instru-mentation upgrades, would be replaced. None of this cable is currently installed in active plant systems. The inspectors will follow the licensee's cable replacemcnt efforts (86-37-08).

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17 Poor Quality Plant Drawings On several occasions, the inspector noted that the quality of plant drawings issued by the site document control office was poor. One drawing, E40, a schematic of 4160V safety related breakers 152-509 and 152-609, was so faint that only the outer border of the drawing was visible. Other drawings of safety related equipment were issued with large areas illegibl The drawings were marked " Issued for Construction" by the document control office and are representative of the quality of drawings issued to the plant staf Subsequently, legible drawings were furnished to the inspector by the document con-trol offic The inspector discussed the drawing problem with the Plant Manager. No examples of licensee personnel using illegible drawings in the performance of safety-related work activities were noted during the inspectio At the exit meeting, the licensee indicated that measures would be taken to ensure that the document control center only issue legible drawings in the future. The inspector will review drawing quality during future, routine inspection .0 Seismic Qualification of General Electric HGA Relays During a design review, the Pennsylvania Power Light (PP&L) corporate engineering staff identified that GE HGA relays may not be suitable for safety-related applications. A Wyle Engineering Company test report indicate that this type of relay experiences contact chatter when subjected to seismic forces. Eased on this information, the inspectors questioned Boston Edison engineering concerning the qualification and application of GE HGA relays at Pilgrim. Preliminary review by the licensee identified in excess of 200 HGA relays, many installed in safety-related applications. Discussions between General Electric and the licensee indicate that the relay contact chatter is confined to normally closed contacts in normally deenergized relays. This information was contained in General Electric Service Advise Letter 174.1 dated A~ p ril 11, 1983. The licensee is presently reviewing information provided by General Electric, the relay test reports provided by PP&L, and the specific application of HGA relays at Pilgrim. The inspectors will continue to follow the progress of this evaluation and document the results in a future inspection report (86-37-09).

6.0 Review of LER's LER's submitted to NRC:RI were reviewed to verify that the details were clearly reported, 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

'86-024 10/7/86 11/7/86 Non-fire resistant coated structural

steel

The inspector had no further question .0 Management Meetings At periodic 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 inspectors. No written material was given to the licensee that was not previously available to the publi On November 24, 1986, a management meeting was held at Boston Edison's

! Chiltonville Training Facility. The meeting, held at NRC Region I

{ request, was scheduled to discuss plant status, licensee management

. system improvements, SALP improvement status and a number of other issues. The details of this meeting are contained in inspection repo L i 50-293/86-41.

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Attachment I to Inspection Report 50-293/86-37

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Persons Contacted i

L. Oxsen, Vice President, Nuclear Operations

• A. Pederson, Nuclear Operations Manager

*K. Roberts, Director Outage Management D. Swanson, Nuclear Engineering Department Manager D. Cronin, Manager of Nuclear Management Services Dep N. Brosee, Maintenance Section Head R. Fairbanks, Section Manager, Licensing and Analysis, Nuclear Eng. Dep T. Sowdon, Radiological Section Head

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J. Seery, Technical Section Head j S. Hudson, Operations Section Head  !

j E. Ziemianski, Management Services Section Head

P. Mastrangelo, Chief Operating Engineer 3 B. Eldridge, Acting Chief Radiological Engineer R. Sherry, Chief Maintenance Engineer i J. McEachern, Resource Protection and Control Group Leader i E. Graham, Compliance and Administrative Group Leader F. Wozniak, Fire Protection Group Leader

• Senior licensee representative present at the exit meeting ,

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