IR 05000293/1986006

Insp Rept 50-293/86-06 on 860218-0307.Violation Noted: Replacement Squib Charges Installed in Standby Liquid Control Sys (SLCS) from Batch Not Tested During Manual Initiation of SLCS

ML20199L178
Person / Time
Site:	Pilgrim
Issue date:	03/28/1986
From:	Wenzinger E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20199L169	List: IR 05000293/1986006 ML20199L165 ML20199L171
References
50-293-86-06, 50-293-86-6, NUDOCS 8604100309
Download: ML20199L178 (46)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket / Report No. 50-293/86-06 DPR-35 (icensee:

Licensee: Boston Edison Company 800 Boylston Street Boston, Massachusetts 02199 Facility: Pilgrim NucI'ar e Power Station Location: Plymouth, Massachusetts ^

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Dates: February 18, 1986 - March 7, 1986 Inspectors: H. Eichenholz, Senior Resident Inspector, Yankee Rowe (Shift Inspector)

R. Jacobs, Senior Resident' Inspector, Susquehana (Shift Inspector)

W. Raymond, Senior Resident Inspector, Vermont Yankee (Shift Inspector)

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N.McBride, Senior >ResidentInspector,gUgrim o J, Wechselberger, Resident Inspector,' Oyster Creek N, Blumberg, Lead Reactor Engineer

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R. Nimitz, Senior Radiation Specialist Approved by:

. Wenzinger,' f, ojects Branch No. 3, Division Date of Reactor Pr s d Team Leader Inspection Summary: Inspection _No. 50-293/86-06 on February 18 - March 7, 1986 Areas Inspected: This special inspection included reviews of: plant operations,

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maintenance aRd modifications, surveillance testing, radiological controls, quality assurance, trainirig, fire protection, enginecring support, and security. Inspec-tion hours totaled 963..$ hour .

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TABLE OF CONTENTS

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Background........................................................... 1 Inspection Process................................................... 1

) Inspection Summary................................................... 3

' Plant Operations..................................................... 3

, 4.1 Operating Activities............................................ 3

4.2 Procedure Controls.............................................. 4 4.3 Annunciators and Response to Offnormal Conditions............... 5 1 4. 4 Facility. Conditions and Housekeeping............................ 6 j 4.5 Operations itaffin

4.6' Summary...........g............................................. ..............................................

8 j Maintenance and Modifications........................................

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5.1 Maintenance Program............................................. 9

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5.2 Maintenance Requests (MRs)...................................... 9 5. 3 " A" P r i o ri ty Ma i n te nance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 5.4 Maintenance Staffing............................................ 10 1 5.5 Procurement Support Group....................................... 11 j

5. 6 Maintenance Trending............................................ 11

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5.7 Review of Specific Items Related to Plant Ma 12

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! 5.8 S umma ry . . . . . . . . . . . . . . . . . . . . . . . . . . ..................... . . . . . . . . . . i n te na nc14 e....... Surveillance Testing................................................. 14 6.1 Independent Verification........................................ 14 e

6.2 Planning and Control of Testing................................. 15 6.3 Personnel Attitude Towards Nuclear Sa fety. . . . . . . . . . . . . . . . . . . . . . . 16 6.4 Augmented Of fgas ( A0G) Prefil ter Testing. . . . . . . . . . . . . . . . . . . . . . . . 17 6. 5 Explosive Squib Valve Testing................................... 17 6.6 Summary......................................................... 20 - Radiological Controls................................................ 20 !

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7.1 O rgani zation and Stif f i ng. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 - Communications..,............................................. 21

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7. 3 Training and Retraining....................................... 21 ALARA........................................................... . 22 i

, 75 Corrective Action Program Control and Oversight of Infield Radiolo (R0Rs)................................ 22 23 ;

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7.7 Aud i ts . . . . . . . . . . . . . . . . . . . . ........................ . . . . . . . . . . . . 0ical Wo 23 rk Ac t i 7.8 Job Pl anni ng and Vork Contro1. , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 )

7.9 Inglementation of Radiological Effluent Technical  :

Specifications (RETS)....................... ................... 24 :

i 7.10 Summary..................................... ................... 24

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Page Quality Assurance.................................................... 24 8.1 Qual i ty As surance Audi tor Group. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 8.2 Quality Control Group........................................... 25 Summary......................................................... 26 Training............................................................. 26 1 Fire Protection...................................................... 27 10.1 Fire Watches.................................................... 28 10.2 Other Observations.............................................. 30 10.3 Summary......................................................... 30 1 Engineering Support.................................................. 30

1 Security............................................................. 30 1 Observations of Licensee Management.................................. 32 Attachment 1 - Persons Contacted i

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Attachment 2 - Surveillance Testing Activities

Attachment 3 - Licensee Report on Tripping of Motor Control Center B20 Attachment 4 - NRC Followup to the Tripping of Motor Control Center B20 Attachment 5 - Licensee Response Items and Inspector Follow Items I

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DETAILS 1. 0 BACKGROUND On December 18, 1985, NRC Region I completed a Systematic Assessment of Lic-ensee Performance (SALP) Board evaluation of Pilgrim Station for the period of October 1,1984 through October 31, 1985. That assessment indicated that the licensee's performance had deteriorated in the areas of plant operations, maintenance, and emergency preparedness. This inspection was conducted in order to better understand the nature of the licensee's efforts in these areas and in areas where performance has been cyclic. The team attempted to obtain a more complete understanding of the underlying reasons for the licensee's performance discussed in the SALP report and to ascertain whether they could have an adverse impact on the safety of plant operation .0 INSPECTION PROCESS The inspection consisted of review of plant activities by three shift inspec-tors, followup inspection of shift-identified items, review of plant mainten-ance, review of quality assurance (QA) activities, and a review of radiologi-cal controls activities. The Team Leader met periodically with licensee man-agement to inform them of preliminary inspection finding During the first week of the inspection, the team consisted of the team leader,

• three shift inspectors, a technical assistant (Pilgrim SRI), and a resident inspector. The shift inspectors provided 24-hour inspection coverage seven days a week until March 2, 1986. The resident inspector occasionally func-tioned as a shift inspector during this period. An engineering specialist and a radiation specialist joined the team during the last two weeks of the inspection. A project engineer also assisted during the last week. An exit interview was held at the conclusion of the inspection on March 7, 198 Management observations were not discussed at the exit interview, although many of the topics were discussed with senior licensee management during the inspectio The inspectors used the following evaluation criteria during their reviews: Are management goals and objectives developed and implemented? Are they understood by all levels of the licensee's organization? Is there adequate planning and control of routine activities? Do workers and their supervisors have a proper attitude toward nuclear safety? Do they understand the potential impact of their day-to-day activities on safety? Is senior management involved in the day-to-day operation of the plant? Is training, direction, guidance, and supervision by first line super-visors effective?

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2 Is staffing adequate in light of planned work? How do the QA and QC program monitor plant activitie How are QA re-ports used by plant management? How does the licensee work with and oversee contractor personnel? Are the safety review committees effective?

3.0 Inspection Summary The team found no evidence that the plant was being operated unsafely. The team identified strengths and weaknesses similar to the 1985 SALP report, with two exceptions, first line supervisor activities and fire protection. First

.line supervisor actions were significantly stronger during the inspection than during the SALP period. The SALP did not discuss the fire protection program in detail. The team found this program weak. The team did not determine if the limited duration of the inspection was the cause of these apparent anoma-lie The operators were knowledgeable, conscious of nuclear safety, and performed in a consistently professional manner. However, weaknesses were noted in the staffing and onsite engineering support for the Operations Department. A shortage of licensed operators was evident. Control of plant valves was ade-quate, except for instrument root valve Plant housekeeping was goo Maintenance activities observed during the inspection were also performed well. However, weaknesses were observed in the procedural description of the maintenance work process, in the scheduling of low priority maintenance, in the procurement of spare parts, and in preventive maintenance on 480 VAC molded case circuit breakers. Staffing vacancies for some maintenance super-visory positions were evident. Licensee initiatives including the development of planning and procurement groups may resolve some of these problem Surveillance activities were generally well planned and controlled during the inspection. However, a problem was identified with a previous surveillance test of the standby liquid control system (SLCS). This test was not conducted in the manner required by the technical specifications and the licensee's procedure, and might not have detected faulty explosive " squib" valves in the SLC The team also noted deficiencies in the licensee's independent verifi-cation program involving surveillance testing and plant maintenanc Staffing vacancies and the implementation of an ALARA program are continuing weaknesses in the radiological controls program. The licensee has estimated that as much as 26 person-rems of needless radiation exposure per year could be saved by one improvement. Inter-Departmental communication and cooperation between health physics and other station groups was sometimes weak and should be improve .

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The station fire protection program tended to rely on compensatory measures rather than to aggressively seek repairs for out of service fire protection equipmen This resulted in an excessive number of compensatory fire watche Fire watch personnel had minimal trainin Quality assurance, quality control, and the station training program were all acceptably implemented. Two minor security problems were identified and re-solve Upper licensee management was often defensive about inspection findings. This indicates that the licensee does not readily acknowledge problems, a weakness that could limit future improvements in station programs. Licensee management also needs to develop better internal methods of identifying program weak-nesses, including reducing the dependence on third party auditor findings as a means of obtaining program suppor The licensee is planning significant improvements in operations, radiological protection, and maintenance. While these efforts are noteworthy, the team believed that the success of these programs is not assured and will depend heavily on management attitudes and aggressive followup.

i 4.0 PLANT OPERATIONS Operating activities observed by NRC shift inspectors and daytime staff during the period from February 19 - March 2, 1986 included the following: routine power operations and surveillance testing; normal shift duties including staffing, turnover, briefings, plant tours, and responses to alarm and off normal cone ions; actions to comply with technical specifications (TS)

limiting conditions for operations (LCOs) by the licensee in response to events that took place during the inspection. The inspectors also walked down portions of the "A" low pressure coolant injection (LPCI) and reactor core cooling (RCIC) system No discrepancies were noted during the walkdown .1. Operating Activities Plant operators performed well operating the plant. Operators were knowledgeable of plant systems and conditions, shift duties and their responsibilities. They approached their duties with a good regard for safety. Operators were observed to have a good regard for plant proce-dures and to follow them. The team observed good direct supervision of shift activities, with good interaction and guidance provided by the Watch Engineers to the shift, and by licensed operators to non-licensed personnel. In particular, there was good coordination between operators during the performance of operational surveillance tests and good super-vision of non-licensed trainees on the control board during test activi-tie Operators took a generally conservative approach regarding technical specification LCOs. Conservative calls were made when equipment oper-ability questions arose, as exemplified on February 21, 1986 when out

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l of specification inservice test (IST) cycle times were noted during sur-veillance testing of the high pressure coolant injection (HPCI) stop and

, steam line drain valves. A conservative approach to compliance with the technical specifications was also exhibited on February 20, 1986 when the standby liquid control system (SLCS) was declared inoperable and the SLCS action statement per TS 3.4 was entered due to questions of whether the annual system test had been properly completed. Actions taken to comply with the LCOs for HPCI, SLCS and LPCI were complete and appropriat Actions to restore systems to an "available" status as soon as possible following testing or repair were notable and are considered a good prac-tic Shift turnover activities for all licensed positions were generally thorough. Good use was made of the operator logs, along with a walkdown of control room panels, to review pertinent changes in operating status or problems. The transfer of status information was generally complete, and operator followup of items warranting further attention was eviden Shift logs are adequately maintained. Status briefings conducted by the operations supervisors with personnel on shift is a good practic Onesignificantexceptiontcotherwisegoodperformanceregardingcom-munications and followup was noted. The manual valve for the 'A diesel generator fire suppression system was tagged closed on February 4, 198 This status information was not adequately communicated to all shifts in that the Watch Engineer on March 5, 1986 did not know the current status of the system. It was noted that the Nuclear Operations Super-visor for the same crew was cognizant of the fire system statu .2 Procedure Controls The team noted that, in general, procedures were technically adeo.uate to accomplish the intended activity. A good practice was noted regarding system operating precedures, in that a chronology of design changes was included in the narrative section of many procedure Licensee actions to change the normal operating position of the "B" LPCI injection valves on February 26, 1986 were properly reviewed and approve Other procedures affected by the change in valve position were identified l and revised. Actions to swap the valve positions were properly controlled I and there was good coordination with maintenance personnel to complete j the evolution. The safety evaluation for the revised configuration for the "B" LPCI system was thorough and appropriately addressed potential concern Two exceptions to otherwise good findings regarding procedures and pro- l cedural controls were noted: l l

(1) NRC inspectors identified that the alarm response procedures (ARPs) '

for low torus water level had a different setpoint than what exists -

on the instrument The procedures specified setpoints of -4 inches

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and -2 ft 9 inches for level switches LS 5060 and LS 5037, respec-t.ively, whereas the actual setpoints established for these instru-ments was -6 inche The procedures were subsequently correcte Inspector followup of this item noted that a broader scope concern had been identified and was being tracked by the licensee in re-sponse to a 1985 QA audit finding (Deficiency Report DR 1478). The audit findings highlighted the need to update ARPs in general, and to assure all appropriate control room annunciators are periodically calibrated. The inspector noted that important annunciators (e.g.,

those associated with technical specification instruments and those included in operational surveillance procedures) are periodically calibrated. These items should be resolved expeditiousl (2) NRC inspectors noted there is no documented control of some instru-ment root and isolation valves (i.e. , they are not identified on plant flow drawings or covered in plant procedures). Informal con-trols exist in that operators are generally responsible for posi-tioning instrument root valves, and Instrument & Control personnel have control for instrument isolation valve The plant should update drawings and procedures to incorporate these valves into check-off lists, and clearly assign responsibility for control of these valves. This item was discussed during the exit meeting on

March 7, 1986 and the licensee was requested to identify a date by which actions on these items will be completed. This item will be followed by the NRC on a subsequent inspection (86-06-01).

The team noted only two minor exceptions to otherwise good performance in the area of personnel adherence to plant procedures and procedural controls. An NPO did not follow the requirements of procedure 8.9.1, step VII.C.2 during testing of the emergency diesel generators on Febru-ary 19, 1986. The operator did not use the local control switch to ver-ify proper operation of valves A0 4521 & 4522, but merely noted the valves operated automatically in response to the day tank level control circuitry. A second minor discrepancy was noted on March 1, 1986 when an NRC inspector observed an NPO using'an outdated "information only" copy of the HPCI drawing to verify the HPCI system was properly returned to a normal valve lineup following maintenance. The checks being per-formed were in addition to those already completed to verify proper res-toration to service as part of the work control proces Licensee man-agement should discuss these findings with operations personnel to assure that procedures are diligently followed and that only updated, controlled procedures and drawings are used to verify the plant operating configura-tio .3 Annunciators and Response to Offnormal Conditions

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The number and reasons for illuminated annunciators in the control room were reviewe Of the 12 annunciators that were "in" on February 21, 1986, only 4 were nuisance alarms. The resident inspector had discussed inoperable nonsafety alarm lights and nusiance annunciators with the

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licensee in early February, 1986 prior to this inspection. At that time, a number of burned out position indicator lights were replaced and the number of chronic activated control room annunciators was reduced from 18 to 12 (NRC Inspection Report 50-293/86-01).

While this number of nuisance alarms was not considered either excessive or a hindrance to safety, it appeared there were no plans in progress to address the outstanding ones. The " Air Dryer High Moisture" annunci-ator in particular has been outstanding for some time (Section 5.17 of this report). It would be appropriate for plant management to address and eliminate the outstanding nuisance alarms on a schedule commensurate with other prioritie Operator responses to annunciators and off-normal conditions was gener-ally proper and thorough. Deficiencies noted during surveillance tests witnessed during this inspection were properly followed up by issuing maintenance requests and/or failure and malfunction reports that were

assigned the appropriate priorit A notable exception to otherwise good performance occurred on February 19, 1986 following the surveillance of the security diesel per procedure 8.9.1 The diesel would not synchronize to its bus and accept load during the test. However, the operations department did not inform the Maintenance or Security Departments about the problem. This item is further discussed in Section 12 of this repor The team reviewed operator actions prior to the inspection in response to the recirculation pump hi/lo oil level alarm on January 28, 1985 and the subsequent February 10, 1985 pump motor failure on low oil leve Operator response to the alarm was in accordance with ARP 2.3.2.5-7, and a maintenance request to address the condition was submitted as require The procedure instructions to follow up the alarm appear lacking in that the instructions to merely monitor oil and bearing temperatures were not sufficient to detect impending failure of the motor bearings. There also i

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appears to have been a lack of followup and/or involvement by maintenance or engineering on January 28, 1985 to try to validate the authenticity of the alarm. The decision to continue operations without resolving the validity of the alarm constituted an acceptance of a risk to reliable

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power generation and not a risk to safe plant operatio The inspector noted that actions are in progress to split the hi/lo alarms and to identify other similar alarms that should also be change The licensee should also review the procedures and revise them as neces-sary to assure they' are sufficient to preclude a recurrence of the pump failure. The NRC will follow the results of the licensee's evaluation of hi/lo alarms (86-06-02).

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7 4.4 Facility Conditions and Housekeeping Overall plant housekeeping and cleanliness conditions were good. The general condition and maintenance of plant equipment was also found to be goo Several minor exceptions to otherwise acceptable findings were noted, which included: the general conditions of the diesel fire pump (Section 10 of this report); a damaged pressure gage noted on February 24, 1986 on the suction of the 'A' core spray pump; and degraded condition of non-essential instruments noted on February 25, 1986 on the HPCI skid, along with a significant steam leak on steam trap ST4 in the HPCI steam pot drain line. The inspectors also noted on February 25 a buildup of oil /

water in the basin of HPCI auxiliaries skid. The licensee had previously noted the leak on the HPCI steam trap and a maintenance request was is-sued in January,1986 to repair the trap during a maintenance outage on the system. The steam trap flange leak was repaired prior to the end of the inspection. The licensee took actions to issue maintenance re-quests for the other minor problems noted by the tea The team noted valve labeling discrepancies on several plant systems that should be corrected to assist the operators in the proper identification of component for example, several tags were noted to be missing on fire system post indicator valves, and similarly, small valves on the RCIC system were not labeled, and for some of the valves that were labeled, the identification tags did not match the checkoff list. The matter was not being actively pursued at the close of the inspectio The team noted that most components are adequately identifie This matter was discussed during the exit meeting on March 7, 1986 and the licensee was requested to provide a commitment date to complete ac-tions on component labeling. The licensee should incorporate a require-ment in station procedures to control and periodically review the status ,

of component labeling and to replace tags as necessary. For example, '

labeling could be reviewed on a continuing basis during the performance ]

of system valve lineup verifications. The NRC staff will review the licensee's actions on this item on a subsequent inspection (86-06-03).

4.5 Operations Staffing l l

The licensed operator staffing is adequate to man the shifts, but at the cost of regularly encroaching on overtime limits. Moreover, the oppor-tunity to work overtime is welcomed by some of the operators. No evi-dence was found during the inspection where the use of overtime had created a personnel perforinance problem. However, one instance was noted where an individual worked 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> over the period of February 18-20, 1986. This work assignment exceeded the overtime guideline of no more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period, and was not approved by the plant manager. Current BECo management actions to correct the licensed opera-tor staffing deficiency should eventually reduce the overtime burde ~. - . - - . _ - .. . - __ _- . - -- -

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l It was noted on February 26, 1986 that the second licensed NP0 on duty l was outside the protected area for over 1-1/2 hours to get a body count I and to take readings at the plant. stack. Getting a whole body count is

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considered an administrative matter not related to licensed duties. Ac- l

tivities to obtain stack readings would be considered as tending to lic- '

, ensed duties. However, it could take 10 minutes or-longer for an opera-j tor to return to the control room from the stack. This was a practice l not specifically disallowed by station policy. The concern with a prac-

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tice that allows the licensed NPO to be outside the protected area is that that operator may not be " read' f available" to assist in the con-trol room upon request by the Watch Engineer in response to a plant event.

j Inspector concerns with this bad practice were discussed with the Chief Operating Engineer on March 3,1986, who stated that instructions would

be provided to shift personnel to require the second licensed operator ,

j to remain within the protected area, or otherwise be relieved. This in-i struction should be formalized in a written policy on the conduct of station operations and was discussed during the exit meeting on March 7, 1986. The written policy will be reviewed by the NRC (86-06-04).

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1 has been vacant for several months. The team's consensus was that BECo i management should fill this position quickly to provide the necessary  :

management for the departmen This comment is not meant to reflect ad-

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versely on the performance of the Chief Operating Engineer, who is doing a good job to supervise the operators by addressing their interests and

to keep the the plant operating well. It is hard to understand how he ,

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has done all this with no support staff. The team believes very strongly I

that BECo management should provide additional daytime technical staff

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of at least two people to assist in the planning and implementation of operations projects.

i The additional support staff could be used, for example; to review the j contents of the operator training /retrairiing programs to assure the ma-i terials remain pertinent to the~ operators; to develop and review plant

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j procedures and design changes; to complete plant system reviews to assure component labeling is proper and instrument root and isolation valves

! are tagged; to assist in administrative matters for the section; and, l to respond to outside requests for' assistance, such as for INP0 visits i and the simulator project. The operations support staff positions could

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be developed as an alternate career path for operator .6 Summary-

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The team found that shift. operations were good. Operators were knowl-

edgeable, conscious of nuclear safety, and performed in a consistently professional manner. However, an insufficient number of licensed reactor

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operators, the lack of an adequate support staff for the Chief Operating l Engineer, and the lack of an Operations Department Section Head are sig--

j nificant weaknesses in the plant operations program. The control of

} plant valves was adequate, although control of instrument root valves

was weak and did not reflect an awareness of recsnt industry problem , Plant housekeeping was good.

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, 5.0 MAINTENANCE

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' . Plant maintenance programs were reviewed to assess their ability to enhance plant safety, plant performance, and to meet the regulatory requirements of the technical specifications and ANSI N18.7-1976, " Administrative and Quality Assurance Requirements for the Operational Phase Nuclear Power Plants". In i addition to the program review, NRC inspectors on shift witnessed the perform-ance of maintenance activities to determine the adequacy of actual maintenanc Shift inspectors reviewed maintenance backlogs for impact on safety related equipment operability and identified specific items which required further review.

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5.1 Maintenance Program i Many of the administrative procedures contained minimal informatio Procedures did not always reflect minor changes in actual practice Procedure 1.5.3 describes how to fill out a maintenance request (MR) but i says little else about the process of handling maintenance activities.

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This may have contributed to the problem of lost MRs which is discussed later.

Two new groups, (1) Planning and Scheduling and (2) Procurement Support ,

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have been formed to resolve long-standing problems. Although the. groups

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little recognition by maintenance section management of the need to de-velop new procedures for these groups. The inspector informed maintenance

management of the requirements of ANSI N18.7 for procedures for planning, scheduling and control of maintenance activities. During the course of this inspection, management reviewed NRC concerns and concurred in the

' need for additional procedures or the upgrading of current procedures to more clearly define the maintenance process.

j 5.2 Maintenance Requests (MR's)

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This portion of the inspection focused on the overall system for handling MR's and the safety significance of MR's not yet completed. A large

sampling of open MR's in various systems were reviewed by the inspectors.

In no instance was any open MR identified which might indicate a condi-

tion of degraded safety. Most maintenance work is completed in a rea-i sonable period of time. Priority is given to work which would impact i

on nuclear safety or on the need to keep the plant operating. Deficien-

! cie- in safety systems which did not affect operability were given a j lower priority.

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Each maintenance engineer (mechanical, electrical and I&C) has the re-

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' sponsibility for scheduling the work and each had his own system for tracking MR's. The~ older an MR became the more chance it had of becoming

' " lost" in the system. Depending on their status, MR's could be in the

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Control Room annex in a ready to work status; being worked; in the main-tenance shop; or being held by supervisors. There were no positive pro-cedural controls for handling MR's.

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A sampling of 158 open MR's from 1983 to 1985 in plant electrical sys-tems, HPCI system, standby liquid control systems, recirculation system, turbine control system, and vessel level indication system was take The open MR's included both deficiencies and projected maintenance such as motor control center inspection and cleaning. Of 158 MR's, 38 could not be found and there appeared to be difficulty locating some which were eventually found. Although some of the MR's had been closed, this had not been reflected in the MR log A Planning and Scheduling Section (P&SS) has been established and ,hould be fully staffed by May, 1986. The-Technical Section is attempting to locate and disposition old MR's. Maintenance staffing has been increased and a station procurement support section has been established. The funding and implementation of these programs indicates upper managem(nt recognition of the need to resolve this proble .3 "A" Priority Maintenence The licensee defines priority ("A") maintenance as loss or major reduc-tion of generating capscity; external safety, security, or radiation contamination hazards; or major equipment damag "A" priority is assigned by any Watch Enginee "A" priority maintenance was evaluated as +r its impact on other maintenance activities; the rapidity in which m itenance gets completed; and the overall effective-ness of "A" maintenanc There were 706 "A" priority MR's generated during 1985 and all had been completed. There were, as of February 26, 1986, 135 "A" priority MR's generated and all but five had been completed. The five MR's which re-mained open did not appear to be significant problems. Most "A" priority

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MR's were closed within one day. "A" priority items do not require an ALARA review. Most "A" priority maintenance is completed within one da Some of the "A" priority maintenance could probably have been given a lower priority, however, the amount of "A" maintenance did not appear ;

to significantly impact lower priority maintenance. Approximately 10%

of the workload involved "A" priority maintenance. Overall the system appeared to be effective in providing a system for the watch engineer to promptly fix important equipmen .4 Maintenance Staffing The licensee has recognized the need to increase the maintenance staf l The I&C group currently has 18 technicians and four new technicians have l been hired to increase the staff to 22. The electrical group has 10 )

electricians and 4 new electricians have been hired to increase the staff

, to 14. The mechanical group will maintain their current level of 24

mechanics. The maintenance group supervisor noted that mechanics can J

be hired temporarily through the union hall to support jobs which do not

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affect plant safety equipment. In addition, the licensee is establishing an apprentice program. This program, if implemented, would increase staff beyond its current level Mechanical supervisors have recently been increased from 3 to 4; elec-trical is planned to be increased from 2 to 3; and I&C is planned to be increased from 4 to 5 supervisors. Currently, the biggest difficulty is in I&C, where only 2 positions out of 5 are staffed. The licensee stated that this problem should be resolved in a few week In addition to the staffing increases, the formation of the Planning and Scheduling Section (P&SS) should reduce supervisory administrative work-load, enabling better oversight of jobs in the fiel .5 Procurement Support Group Under the current system, purchase orders involving spare Q, EQ and Fire Protection Quality (FPQ) parts not in stock are sent to the QA and engi-neering groups located in Braintree, Massachusetts. Once approved at Braintree, the purchase order is then sent to the corporate offices in Boston for purchas If there are difficulties with the purchase order, such as determining

"Q" requirements, delays can result. Although no specific count was made by the inspector, it appeared that many jobs were delayed awaiting part In response to this problem, the licensee has formed a procurement sup-port group at the plan This group was started in January 1986, and is not fully staffe Currently, the staff consists of an acting super-visor, a requisition analyst, and a full time clerk. Two QA engineers are at the site twice a week to review purchase orders. The full time staff will ultimately include time engineers and a QA specialist in ad-dition to the requisition analys The acting supervisor of the procurement group reco0nized the need to provide procedures for the procurement group. Such procedures were in preparation but had not yet been finalized, approved, or issued. It appears that the procurement group (and P&SS group) when fully staffed can significantly reduce the purchase order and MR backlog .6 Maintenance Trending This inspection also reviewed the licensee's program for the trending of maintenance to identify repeat maintenance which could indicate that underlying problems were not being corrected. No formal trending proce-dures or program exist to trend maintenance problems. The Maintenance Section Manager trends items such as overtime history, corrective main-tenance backlog, failure and malfunction reports, and nonconformance reports affecting maintenance. Repetitive equipment failures and main-

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tenance trends are tracked by the I&C, electrical and mechanical mainten-ance shop engineer Each engineer indicated that plant component fail-ure trending was informa During this inspection, steam leaks were observed in the HPCI syste The licensee decided that these leaks were significant enough to require repairs. In order to perform these repairs, the licensee planned and performed a HPCI outage entering a seven day limiting condition for operation (LCO). This outage was the first significant maintenance work planned by the new P&S Several outstanding MR's were completed during this outag During the period of January 1983 to February 1986, most HPCI steam leaks appeared to be isolated instances and most repeat items were corrected on the second repair. However, the packing gland on valve M0-2301-5, the HPCI turbine steam supply outboard containment isolation valve, leaked twice in 1983; was repacked during the 1984 outage; and subse-quently leaked and was repaired three times in 1985 (the third leak identified in November 1985 was repaired February 6, 1986).

Discussions with maintenance did not indicate whether any further evalu-ation of this valve would be considered as the result of the continued packing leaks on this valv The HPCI system also had a lube oil bearing seal leak. A review of HPCI system maintenance from January 1983 to February 1986 did not indicate a history of oil leaks. Maintenance on other systems were also reviewed with no chronic repeat failures identifie It appears that although maintenance personnel are aware of repeat fail-ures, there is no formal trending or evaluative program to ensure repeti-tive maintenance is identified and the root cause of the problem is identified and properly corrected.

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5.7. Review of Specific Items Related to Plant Maintenance The SBGT system was modified in 1981 to install automatic actuation valves. These valves leaked in February 1983 wetting SBGT charcoal fil-ters in one train. The system was then valved out and a fire watch i established. During the 1984 outage, the automatic deluge valves were  ;

extensively modified to eliminate the leakage problem. Because the '

modification testing was extensive, the testing was not performed in 1984, and the system has remained out of service to date. The fire pro-tection engineer stated the testing may not be conducted during the 1986 outage because the system may be changed from automatic to manual actu-ation. The current status of this job is unclear. No individual had been assigned responsibility to resolve the system problems at the time  ;

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The control air dryer high moisture alarm annunciated during May 1983 and an MR was submitted for this problem May 26, 1983. I&C trouble shooting indicated the annunciator activated due to a faulty moisture detector and not due to high moisture. Because this sensor cannot be isolated from the instrument air system, repairs will require depressur-izing the air system. During the 1984 outage, no action was taken to repair the alarm. Although an engineering evaluation may be needed to resolve this problem, no engineering service request (ESR) has been sub-mitted. The inspector determined that piping in the air system is copper and would be unaffected by moisture. In addition, Procedure No. 8.C.12,

" Instrument Air Header Moisture Check" is performed at least weekly to ensure no moisture is collecting in the instrument air line During electrical maintenance of the "D" salt service water pump in November, 1985, the pump heaters were found to be inoperative. Because of the age of the pump motor, replacement heaters were no longer avail-able. At that time the pump was caution tagged to constantly operate (in order to preclude moisture buildup in the pumps). No MR was ever submitted concerning this condition as required by procedure 1.4.2 After the inspector questioned this, MR 86-29-9 was written on February 26, 1986 to document the heater problem. There is a new motor in the warehouse; however, there is no Q documentation for this motor. It is not clear who has the overall responsibility to resolve this proble It was noted during the inspection, that MR's 86-20-17, 86-20-22 and 86-A-143 were submitted for repeated repairs of the clean radwaste pum Discussions with mechanical maintenance indicated that diatomaceous earth (DE) used in the clean radwaste is very abrasive. A leaking pump bearing seal was causing DE to destroy pump casing seals. Until the pump bearing seals could be replaced, the pump casing seals had to be replaced fre-quently. MR 86-A-143 was written to replace the pump bearing seal. The more significant problem associated with this work is that a replacement bearing seal had been ordered in early 1985 and had been in shop stores since June, 1985. Apparently the mechanism for notifying the shop that this part was in or the mechanis'm that shop uses to follow up on parts ordering did not work properly. The ALARA implications of the repeated pump repairs are discussed in Section 7.4 of this repor On February 11, 1986, the plant was at full power when feeder breaker B604 for MCC B-20 tripped open. The event was caused by corrective maintenance in progress to repair previously faulted cables. The de-graded cabling was energized at the time of the cable maintenance, un-known to the personnel conducting the repairs. This condition occurred due to: (1) a loss of configuration control that resulted from a 1976 temporary modification, (2) an over reliance by personnel on tagging controls used to de-energize an electrical circuit, (3) failure of the workers to implement proper personnel protection practices while working on high voltage electrical circuits, and (4) the lack of an adequate preventive maintenance (PM) program for 480 VAC molded case circuit breakers. See Attachments 3 and 4 for a description of the event and the NRC followu .

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5.8 Summary Maintenance workers and first line supervisors performed their duties well in work observed during the inspection. Licensee procedures did not describe the maintenance work process in detail. While high priority maintenance jobs were scheduled and conducted in an adequate manner, low priority maintenance was poorly tracked. A number of low priority main-tenance requests were lost. The licensee sometimes relied on compensa-tory measures for loag periods of time rather than fix out of service equipment Vacancies in first line supervisor positions were evident, particularly in the I&C Group. A preventive maintenance program is needed for 480 VAC breakers in motor control centers. Slow procurement of spare parts has delayed station maintenance. Licensee initiatives in developing a Planning and Scheduling Section and a Procurement Support Group are important and should help resolve some of the scheduling and procurement problem .0 SURVEILLANCE TESTING Surveillance testing activities were reviewed by the shift and supporting inspectors. Observations of tests, or parts of tests, were conducted to assess performance in accordance with approved procedures and LC0's, test re-sults (if completed), removal and restoration or equipment, and deficiency review and resolution. In addition, a review of the licensee's response to potential Standby Liquid Control (SBLC) system inoperability due to a manu-facturing error in the system's explosive squib valves was conducte A list of reviewed items is included in Attachment 2 to this repor .1 Planning and Control of Testing Overall, the planning and control of routine surveillance activities was good. A high level of interaction between testing personnel was observed at both the inter- and intra-departmental levels. When I&C surveillances were being performed and equipment problems occurred that required dis-positioning, the Senior I&C engineer provided excellent oversight of the surveillance activities. His performance was noteworthy in that, 1) he provided appropriate directions and guidance to the first line supervi-sory personnel as they implemented the corrective actions, and 2) he demonstrated sensitivity and responsiveness to operational safety con-cern Minor improvements should be made in procedures that do not reflect ac-tual station practices. Examples include 1) procedure 8.B.1, Fire Pump Test, does not reflect the valving in and out of the gage glass on the diesel's day tank, 2) procedure 6.5.160, Calibration of the Area Radi-ation Monitoring System does not specify that the technicians will verify that the common control room annunciator functions for each monitor, and 3) procedure 8.5.1.1, Core Spray Pump Operability and Flow Rate Test does not specify the status of the isolation valve to the pump suction pres-

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sure gage. In the last case, the gage was found isolated on the Core Spray Pumps prior to running the surveillance. Personnel on shift were not aware of this conditio One particular observation that reflected both poor prior planning and control involved recently instituted Inservice Testing (IST) of the HPCI system in procedure 8.5.4.1, HPCI Pump Operability and Flow Rate at 1000 psig. Revision 26 of this procedure dated January 30, 1996 incorporated a five second opening time requirement for the turbine stop valve and a minimum flow check valve operability test. The first performance of the test on February 21, 1986 resulted in declaring the system inoperable because the valve took more than 5 seconds to open. It was subsequently determined that the 5 second stop valve timing requirement should have been approximately 30 seconds. The minimum flow check valve test was not able to be performed because an upstream motor operated minimum flow valve could not open during the test. The motor-operated valve lacked an appropaiate initiation signal. Because the valve did not open, the HPCI turbine tried to compensate for decreasing system flow by increasing speed demand. This sequence unnecessarily challenged the HPCI syste The test procedure was not promptly changed after the February 21 tes Therefore, the HPCI test could not be performed as required by procedure on March 1, 1986. A new test sequence will be developed to allow proper verification of the minimum flow valve while operating the syste The deficient procedure in question was reviewed and approved by the ORC without their recognition that 1) the success of the minimum flow check valve test depended on the presence of the auto-initiation signal, and 2) that the 5 second timing valve was incompatible with system design and safety analysis assumption .2 Independent Verification During the reviews of I&C surveillance procedures, it was noted that the ,

licensee did not fully provide for independent verification requirements '

for lifted leads or installed jumper ANSI Standard 18.7-1976, Section ;

5.2.6, Equipment Control, specifies that temporary modifications, such l as electrical ju.mpers and lifted electrical leads require independent '

verification. The ANSI Standard also requires that independent verifi-cation of tagging of equipment be performed. During the return to ser-vice of the HPCI system on March 1, 1986, it was observed by an inspector that there were tags removed from the system, with valves realigned, without a double verification of the position of the valves. After being notified, a Nuclear Watch Engineer (NWE) had the valve positions verifie l This was done prior to declaring the system operabl l A licensee letter to NRR dated July _ 27, 1984 to NRC:NRR, states that in-formation concerning double verification would be added to procedure 1.4.5, PNPS Tagging Procedure. A review of Revision 16, dated August 1 10, 1984, which is the procedure currently in use, does not contain the subject information and raises a question about the level of performance of their commitment tracking effort l

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A Quality Assurance Surveillance, 85-1.2-1, dated January 25, 1985, re-sulted in issuance of Deficiency Report (DR) No. 1384. This DR was is-sued to resolve questions about independent verification practices used by I&C personnel during surveillance testing. The Nuclear Operations Manager (NOM) subsequently issued a July 12, 1985 memorandum M85-137, Control and Verification of Operating Actions, which discussed the method to be used to perform the verifications. The inspector determined that the management objectives of this document were not translated into the maintenance request and tagging procedure (1.5.3 and 1.4.5). The N0M stated that licensed operators in the control room currently confirm that the removed tags match all the tags hung. He further stated that plans are being made to use a separate form for tagging, which includes veri-fication of equipment position in the field during tag removal. The ob-servations made by the inspectors in the field matched the stated current practice. There is an apparent need for the licensee to implement their plans so that they are in conformance with their written policy and com-mitment to the NRC. The full implementation of independent verification practices will be reviewed during a future inspection (86-06-05).

6.3 Personnel Attitude Towards Nuclear Safety Testing personnel were careful and deliberate. Potentially inoperable equipment was consistently treated as inoperable. Inoperable equipment was not needlessly valved out of service, demonstrating a good appreci-ation of nuclear safety. This was evident during the HPCI system testing on February 21, 1986 and in the declaration of the Standby Liquid Control (SBLC) system inoperable on February 20, 198 The inspector expressed concern over an intermittent condition that leaves a residual flow indication of approximately 50 GPM following the reactor core isolation cooling (RCIC) pump operability test, procedure 8.5.5.1. During this test on February 28 and March 1, 1986, the anomalous condition was observed by the inspectors. It was not observed during the test performed on March 2, 1986. Based upon discussion with licensee personnel, it appears that this has been a long standing condition. Cor-rective action included isolating the flow transmitter, FT 1360-4, and equalizing the pressure between the low and high sides of the transmitte Following the return to service of the flow transmitter the indication of system flow returns to zer The corrective action performed on February 28, 1986, in response to the inspector's questions resulted in the senior I&C engineer coming into l

the plant on a backshift. At this time, procedure 3.M.3-8, Inspection /

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Troubleshooting Electrical Circuits was implemented. Double verification was utilized by licensee personnel when placing the flow transnitter back in service, as required by the procedure. However, on March 1, 1986,

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it was noted that procedure 3.M.3.8 was neither implemented'as required by station policy, nor was a second verification of the valving actions performed when returning the transmitter to service. The inspector brought this condition to the attention of the senior I&C engineer and

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confirmed that appropriate corrective actions would be taken with his personne Based upon the large number of observations of the I&C per-sonnel performing their tasks during this inspection, the failure to follow procedural requirements appears to be an isolated case. In re-gard to the residual flow observation, the licensee was requested to perform an investigation into the cause of these observations and im-plement appropriate correction actions. The senior I&C engineer com-mitted to have the problem resolved by approximately June 1, 1986. The licensee's actions to resolve this issue will be followed on future in-spections of the facility (86-06-06).

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6.4 Augmented Offgas (A0G) Prefilter Testing Testing requirements for the A0G prefilters are contained in procedure 2.2.106, Drawing M254, and FSAR Section 9.4.4. The testing involves D0P and millipore filter sample analysis. The licensee was not aware l of the testing requirements until brought to their attention by the team.

. They subsequently indicated that the testing would not be. beneficial due i to the low efficiency. characteristics of the filte An Engineering Service Request was initiated by the Maintenance Chief Engineer to have

the issue reviewed, and if appropriate, delete the FSAR testing require-ments. The NRC had no further questions on this item.

6.5 Explosive Squib Valve Testing The NRC reviewed the licensee's evaluation of a potentially generic problem (subsequently detailed in IE information Notice No. 86-13 dated February 21,1986) involving explosive squib valves used in the Standby l Liquid Control System (SLCS). Another BWR found during a once per cycle surveillance test, that the squib valve primers (charges) used in both

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pathways of the SLCS failed to fire. This was due, in part, to incorrect manufacturing of the wiring inside the squib valve connector for the primer. It is possible for a valve wired in this manner to fail to ac-tivate on an SLCS initiation. If this occurred, the SLCS neutron poison would not be injected into the reactor. Another concern is that the continuity monitoring circuit that monitors the readiness of the explo-sive squib valves to fire, might not detect an inoperable valv TS Surveillance requirements 4.4.A.2.c. requires a manual initiation of one of the SLCS loops (i.e. a test firing of a squib charge in place)

at least once during each operating cycle. This test checks, in part, the explosion of the charge associated with the tested loop. In addition, it requires that the replacement charges to be installed will be selected from the same manufactured batch as the tested charg Procedure 8.4.6, " Manual Initiation Test of the SLC System", was used to test fire explosive squib valves during the most recent surveillance

(1984 outage). The procedure required that a test charge be fired in

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Bench test firing of a squib valve's explosive charge is an unacceptable test. However, the licensee determined that the squib charges were fired i using a bench test, rather than the SLCS firing circuit in 1984. The '

licensee's failure to perform an in-circuit firing of an explosive charge that came from the same manufactured batch as those installed on April 10, 1984 is contrary to the requirement specified in Technical Specifi-cation 4.4.A.2.c and is considered a violation (86-06-07).

During the evening of February 20, 1986, the licensee convened Meeting No. 86-17 of the Onsite Review Committee (0RC) to review test procedures TP 86-15, Squib Valve Circuit Test, and TP 86-16, Standby Liquid Explo-sive Valve. The former procedure provided instructions for I&C personnel to perform required tests to show operability of the explosive charges of the Squib Valves in the SLCS and show continuity of firing resistor The latter procedure was developed to provide instructions for mainten-ance personnel to change the explosive charges of the Squib Valves in the SLCS. The inspector attended this meeting. The ORC also reviewed the associated Safety Evaluation No. 1919. Extensive involvement by NED personnel in presenting details of the potential problem and proposed testing to determine operability was noted by the NRC representativ At the meeting, the Chief Maintenance Engineer indicated that he would conduct a bench test for one of the charges that are in stock, should NED determine that an installed charge was defective. The NRC represen-tative stated that bench testing would not be an acceptable activity due to the stipulations for in-circuit testing specified by both the techni-cal specifications and procedure 8.4.6. The ORC then agreed that a bench test was not appropriate and it would be necessary to consider the SLCS inoperable at this tim The licensee declared both subsystems of the SLCS inaperable at 11:15 p.m. on February 20, 1985, initiated the start of a plant shutdown per their procedure 0per 5, Section F, Controlled Shutdown without Manual Scram, and informed the NRC via the ENS line that they had entered a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Limiting Condition for Operations per TS 3.4.B.2. Subsequently, the ORC reconvened, reviewed a new procedure TP 86-17, Manual Firing of l SLC System Squib Charges, which provides for in-circuit firing of SlCS squib charges. All three TP procedures were approved by the ORC for im-plementation on February 21, 198 The inspector concluded that the ORC had adequately reviewed the issue and procedures, carefully and deliberately ensured its actions and plans would determine SLCS operabilit Another strength involved the ORC's

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Following testing of the SLCS, the licensee identified no unacceptable conditions with either the existing installed charges or the as-built circuit wiring. New charges were installed following in-circuit testing, with plant shutdown terminated at 8:30 a.m. on February 21, 198 The NRC was notified via the ENS of this actio Due to a blown fuse in the "A" Squib Valve's firing circuit, the plant remained in a 7 day LC0 per TS 3.4.B.1. This delay was caused by treat-ing the replacement fuse as a quality component. The certification of its quality was not available-at the time of installation. Again, the licensee treated the situation conservatively by declaring the subsystem officially inoperable but, maintaining the system in a ready to fire state. No other unacceptable conditions were noted by NRC inspectors during the licensee's implementations of SLCS test procedure QC involvement was noted in two areas: 1) as stipulated on the MR for installation of the new squib explosive charges, the torque values and 0 ring installations were verified to be correct, and 2) QC initiated a hold point on the installation of the replacement fuse in the firing circuit ("A" Subsystem). This latter action was viewed by the NRC as a positive element that ensures material procurement and receiving in-structions are reviewed and used to establish traceability and ensure quality of replacement items. The hold tag was removed from the sub-system, and the SLCS declared operational once quality certification was demonstrate The only item requiring future NRC review involves the issuance by General Electric of a Service Information Letter (SIL) No. 186 on July 30, 1976, Modification For Standby Liquid Control System's Continuity Monitoring. This SIL identified a problem with SLCS circuitry where the potential loss of a firing current limit resistor could occur with the occurrence not being detected by the system's continuity monitoring cir-

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cuit. The licensee records show the SIL as an open item in the Operating Experience Review Program. In light of the recent events, the NED_is reviewing the SIL for disposition. Procedure TP 86-17 verified that the current limiting resistors are functional. The NRC will review the lic-ensee's plans for complying with the SIL's recommended improvements to the continuity monitoring circuitry of the SLCS (86-06-08).

The inspector noted during a review of QA Surveillance Report 85-1.4-8 issued on June 4, 1985, that the licensee's past practices in 1981 had utilized in-circuit testing. However, QC involvement during the 1984 outage did not include independent verification of actual in-circuit firin i

6.6 Summary  !

l Surveillance activities were generally well planned and controlled during the inspection. An exception was a HPCI surveillance, where the test was not well controlled due to a poor procedure. Personnel conducting

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surveillance were careful and deliberate. However, acceptance of a residual flow indication on the RCIC system following a surveillance test was an example of a poor attitude. Also, the licensee failed to follow an established procedure during previous SLCS testing which could have had significant safety consequences. An independent verification program needs to be fully implemente . 0 RADIOLOGICAL CONTROLS Radiological controls activities in the station were observed during the in-spection by the shift inspectors and a specialist inspector. The review in-cluded review of program documents, discussions with health physics and other station personnel, attendance at licensee planning meetings, and observation of radiological control practices during ongoing work. The training and pro-gram for contractor and permanent radiological controls personnel were also reviewe .1 Organization and Staffing The organization and staffing of the Radiological Controls Organization was reviewe The findings in this area were based on discussions with personnel, review of the organization, and review of documentatio The licensee established and implemented an upgraded radiological con-trols organization consistent with Radiological Improvement Plan (RIP)

commitments. However, several key supervisory positions remain to be filled. Also a significant number of permanent technician positions remain to be fille In the area of supervisory personnel, the chief radiological engineer position has been open for some time. In addition, the individual acting in the position of Environmental and Radiological Health and Safety Group .

leader has indicated her intent not to permanently fill the positio Consequently, individuals in this position are filling them in an acting capacity. The licensee should fill these positions on a priority basis to provide continuity of direction to the inplant radiological operation group and the technical support grou Regarding the radiation protection technician staff, the licensee per-formed a Task Analysis in early 1985 that determined in part, the number of permanent technicians needed. The analyses indicated the need for about 30 permanent technicians. However, to date, there are only about 17 permanent technicians positions authorized. The need for additional permanent staff was brought to the attention of senior management in May, 198 The licensee should staff his organization consistent with his Task Analyse The use of contractor technicians should be minimize ; .

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7.2 Communications-Communications within the organization were generally adequate However, the need for some improvements with communications within the group was !

apparent. Communications at the morning meeting did not appear.to be !

effective. No apparer,t: feed back mechanism relative to action to be taken on information transmitted at the morning meetings was evideil Regarding shift turnovers, shift radiation protection personnel attended :

turnovers with operation personnel during shift changes. Onshift turn-overs by the shift HP were generally goo j

The communications between radiological, controls personnel and other station groups.(e.g. maintenance, operation, and instrumentation and -

control) at the worker level were generally goo ,

Communication between the Watch Engineers and technicians, a previous problem has improve ,

However,someproblemscontinuetoexistbetweencertal[1WatchEngineers '

and radiological controls technicians. The communications problems have resulted in some violation of radiological controls procedures, friction between the groups, and morale problems. Recent examples include poor

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communications during a recent Gai-Tronics problem, and poor communica-tion during an entry into the A0G. building-to drain filters.. These .

problems appear to continue in part due to the failure to bring identi-fied deficiencies in this area to the attention of appropriate management i for resolutio . 3 Training and Retraining The licensee has established and implemented an initial radiological ,

controls technician training program. The program has been reviewed by i INP0. No major concerns were identified by INPO in their. review of the program. The Technical -Training Supervisor'in this area appeared con- '

scientious and interested in establishing and implementing an effective training program. The. individual is responsive to NRC comment .

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The licensee has not established and implemented an effective'radiologis cal controls technician retraining program. This-is indicative of in'

adequate planning considering the number of new procedures which are being established and implemented to meet Radiological Improvement Pro- ';

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gram (RIP) commitments. Also, the program does not ensure appropriate retraining of personnel being rotated through various job )

A retraining program to train and qualify personnel on new procedures and procedure changes, and for personnel rotating through various posi- t tions should be established on a priority basi l

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7.4 ALARA The licensee has taken action to upgrade the ALARA Program. This is being done through improvements in program procedures and improvements in training of personnel. Final program procedures remain to be estab-lished, howeve The licensee's ALARA group was effectively integrated into the work planning process. ALARA grcup personnel,do not receive outage planning sc5edules, are unaware of the work p?anning process, and in most in-stances are unaware of work to be performed mere than & day in advance of the wor The lack of adequate review time could cc:rpromise the adequacy and ef-fectiveness of ALARA controls. The licensee should integrate the ALARA group into the work planning proces Regarding in-field ALARA controls, observations of radiation protection technicians covering jobs found non uniform implementation of ALARA con-trols during work. This is of concern because in some cases, the tech-nicians provide the only ALARA oversight for the job (e.g. "A" priority RWPs). The licensee should ensure uniformity of implementation of ALARA .

controls by technician An example of poor ALARA planning was the repeated repairs to the clean radwaste pump (Section 5.7). Flere, unnecessar made in areas with radiation levels of 140 mr/yhr.repeated repairs were The licensee is requested to provided a commitment for upgrading the ALARA program including: implementation of ALARA procedures, earlier '

incorporation of ALARA planning into the work planning process, and com-pletion of an evaluation of ALARA for "A" priority RWPs. This item will rerain open pending a review of this commitment (86-06-09).

7.5 Corrective Action _Prngram (RORs)

The licensee has established a Radiological Occurrence Reports (R0R)

progra The program is currently being revise The program provides for identification of problems and initiation of corrective action. However, the program was found to be less than ade-quate in that specific problems associated with radiological incidents were not clearly stated and identified problems were not brought to the attention of the appropriato level of station management for their review and resolution (e.g. January 1986 contaminated Watch Engineer ROR).

The licensee should upgrade his ROR program to ensure that problems as-sociated with occurrences are clearly identified and that identified problems are brought to the appropriate level of station management for review and resolution. Once brought to the level of appropriate manage-ment, lasting corrective actions should be implemente .

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7.6 Control and Oversight of Infield _ Radiological Work Activities Review of preparation and performance of radiolngical work by plant per-sonnel (e.g. maintenance and J&C) fcurid that personnel had preplanned their work, entries into radiological work areas were performed in con-formance with radiological protective procedures; and supervisory over-sight and involvement with the workers was apparent during the incpection period. Examples included repair of the "A" clean waste transfer pump by maintenance personnel and work on a level transmitter in the condenser bay by I&C perscanel. Radiological controls personnel oversight of in field work was found to be generally adequat To improve the oversight and control of in field work, radiological con-trols supervisors are touring the plant frequently. However, discussions with radiological controls management found that no clear guidance has been provided to their supervisors as to: the frequency of their tours or matters to be reviewed. Also no clear feedback mechanism was apparent to properly address tour finding Some problems were identified relating to licensee evaluation of person" nel dositetry (TLDs) for use in noble gas atmospheres and N-16 radiation fields. Documentation was not available to clearly show adequacy of the TLD The TLDs were worn by personnel working in the condenser ba The licensee subsequently documented an evaluation of the adequacy of the dosimetry. The licensee should improve documentation of evaluations of the adequacy of radiation monitoring devices and instrumentation where needed for unusual conditions and situation . 7 Audits The licensee is implementing the technical specification required audits of the radiolcgical controls program. No apparent deficiencies were identifie .8 Job Planning and Work Control The licensee has identified sign'ificant problems in the area of use of HP personnel resources to support RWP requests for RWPs which are not used, Actions taken by the licensee have considerably reduced the num-bers of RWPs requested and their subsequent non-use. However, the lic-ensee has nct clearly identified the cause of this problem and initiated timely, lasting corrective action to address it. At one point up to 75%

of daily RWP's were not being used. On a yearly basis, the licensee estimated that unused RWP's could cause up to 26 person-rems of needless radiation exposure to personnel performing radiation surveys. An addi-tional apparert prot)1em involves the use of "A" priority RWPs to perform wor The licensee has reviewed the pr0blem and reduced the use of "A" priority RWPs (50 in a week to about 5 in a week). Continued vigilance in the area is appropriat The licensee should . determine the cause of personnel requesting RWPs which are not ~used and implemented lasting corrective action .

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7. 9 Implementation of Radio 10gical Effluent Technical Specifications (RETS)

Some operations supervisory personnel found that they were unaware of their responsibilities related to the implementation of the RETS ( surveillhnce requirenients and 1.COs). Although subsequent NRC review ideittified some new surveillance requirements required, these were ade-quately addressed in che.mistry procedures. The failure to inform the operations personnel as to tile impact of the multi page document indicates problems relative to keeping the watch appraised of technical specifica-tion change A review of the implementation of the Radiological Effluent Technical Specifications (RETS) found that licensee had established and implemented procedures for RETS .and had trainea chemistry personnel on the use of the procedure A lack of procedure guidance for calculation of liquid discharge flow rate was also idGntifieri. The normal flow instrumentation was inoperabl The licenFa9 corrected this situatio .10 Summary Two key mid-level management positions are va: ant in the radiological controls group. Additional guidance for plant tours is needed for radiological controls managers, including the frequency of tours the areas requiring review, and the proper disposition of findings. ,The licenses should ensure that communication between the radiological con-trols and operations groups are frequent and thorough. A spirit of a:-

tive cooperation does not always exist betwee1 these two groups. Impor-tant radiolcgical findings need to be broaght to the attention of upper station managemen ALARA improvements are needed, including the up-grading of AlARA procedures, incorporting ALARA planning into the work planning process earlier, improving the ALARA review of "A" priority RWP's, and minimizing the number of unnecessary RWP' The latter item '

could potentially save up to 26 person-rems per year in needless radi-ation exposure. The training of Operations Department supervisors in the recently implemented RET's was wea .

8.0 Quality Assurance __ and Quality !'ontrol Program Effectiveness The scope of this inspection included an overview of QA audit and QC activi-ties, a review of QA audit ar.d surveillance findings, and observaticns of specific QA and QC activities within the plant. Tne QA engineering group was only reviewed to the extent of their interfcco with the procurement process which discussed in paragraph ~ .1 QualQyAssuranceAuditorGroup The QA auditor group consists of five auditors located at the Braintree Corporate Office and two auditors located at the plant. The audit Group is occasionally supported by Nuclear Engineering Department personnel

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and outside contractor Audit' findings or surveillanca findings which are contrary to specific written requirements are written as deficieh y reports (DR's) which must be responded to. All audit reports and their associated deficiency reports (if any) are sent to senier licensee man-agemen Froblem DR's are defined as those for which the initial response or cor-rective action is late or was unacceptable. A weekly status of problem DR's are sent to the Senior Vice President Nuclear and the Vice Presi-dent, Nuclear Operations. The inspector reviewed inforri:al documentation ,

that indicated the Senior Vice President Nuclear reads and takes an ac-tive interest in the resolutinn to problerr, DR's. As of February 21, 1986 tiiere were 9 outstanding problem DR's and 29 outotanding DR's tota Most audit findings appeared to ce technically sound. Audits. were re- )

viewed in the areas of operations, maintenance, training and surveillance

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testing. There appeared'to be a pr6blem by the Nuclear Operations De-partri:ent (N00) in giving acequate responses to key audits; respondi in a timely fasnion: and takin0 croitpt corrective action, Based upon our review of the QA audits, the following audit itetns were conhidered significant fir. dings and will be tracked in subsequent routine inspections by the NRC:

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Audit Repc'rts 84-34 and 05-25 ident1fied inadequa:ies involving the incorporation of T6chnical Specification testing requirements in station procedures. NRC Inspectiori 50 293/85-03 identified similar testing problems. Cofrective action resulted in the dentrscting of an engineering firm to Feview surveillance, operations ch'emis tt y.,

ISI and IST procedures for ccmpleteness ar.d assure effective im-piementation of Technical Specification requirement Audit Report 85-25 also indicated that HPCI system logic surveil-lance teste did not fully test ali HPCI circuit DR 1466 was is-sued on tfris ite The NRC will review the resolution of these itcms during a future in-specticn(86-06-10).

8. 2 gjj_ality Control Group QC only reviews plant maintenance activities, Surveillance testing, plant operations, health physics and other plant activities are not'the subject of QC inspections. In addition to the review of maintenance activities QC oversees all non-destructive examination (NDE) and inser-vice inspecti6n (ISI).

All MR's which cover naintenance on Q EQ, and fire protection quality (,FPQ) listed components must be reviewed by a QC inspector to ensure that there is an appropriate level of QC coverage for that jo Foranyjob ,

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requiring QC coverage, QC inspectors will review the KR; verif,y the in-stallation of proper material; observe all QC hold points; review the completed job; and verify by signir.g tht Mg that all QC requirements have been ee Disci.ssiens with the QC group indicates that dnspectors try th stop problems before they happen rather than issue DR's and non-confarmance reports after the fact. Maintenance'perconnel felt that QC coverage was thorough, professional anti aided in es'suring that the jobs weie properly don NRC inspectors noted that there was QC coverage on the backshif ts and at all Q jobs which were witnessed by the tea Contractor maintenance and modifications are performed on site by Bechtel Corporation. During normal plent operations, Bechtel has its cwn QC staff of 8 QC inspectors and operates to the Bechtel QA program which has been approved by the BECo QA grog .3 Summary QA audit findings were generally sound, but piant response to the find;

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ings were sometimes not timely. The scope of the QA audits was limited by the number of onsite auditors. . Quality Gontroi reviews of maintenance and modification activities was evident and acceptable. However, the licensee may find it beneficial to use QC to review ongoing activities in other areas, e.g., ongoing surveilla.nce t6sts.'

9.0 TRAINING R

During the course of inspection activities, observations were made of the knowledge and capabilities of operators and plant personnel. In addition.

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observations of the performance of two training classes and discussions with plant and training personnel were include .

Generally, the team thought the plant operators were knowledgeable and capable of performing their assigned shift tasks. The operators demonstrated an understanding of the plant. Operators demonstrated system knowledge while conducting surveillances. New plant operators in training, performing sur-veillances under licensed supervision also performed well. Observations made during maintenance activities, indicated the personnel involved were knowl-edgeable of the requirements to complete'their particular assigned tas Plant operations personnel were interviewed to determine if the training they received was considered an aid in performing their particular job. The un-licensed operators generally felt they were receiving adequate training and '

were looking forward to starting the licen.;ed operator training program. The licensed operators generally expressed displeasure with their training progra Some did not like required theory courses <which they felt did not enhance their capabilities to operate the plant. Some operators expressed a desire

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to better unde'r stand tiistmal hydraulics but did not feel the material they were receivir.g in the requalification program fvelped them. The operators were able to demonstrate adequate knowledge and use of the steam table ,

Durin0 the inspection period the Radiological Environmectal Technical Speci-fication (REIS) became effective on 1 March. No specific training was given '

tb the operators on RETS other than to read and understand the new tecnnical specifications. In reviewing this change, there was no information which represented a rhange to the operations procedures. Changes did occur in chemistry and radwaste procedure The licensee should have conducted scme operator training prior to the RETS irr.plementation to enspra the Operators were aware of the change and its significance with regard to plant operatio The licensee is actively engaged in attaining Institute of Nuclear Powe'r Operations (INPO) accreditation for their training programs. The self evalu-ation reports (SER) for maintenance, cheibistry, and shift technical advisor programs were submitted in December 1905 and have been acc6pted by INP The licensee believes tnese prograids will be accredited by the end of 198 Presently there are two licensed Bnston Edison SR0's in the training depart-ment and a third rccently transferred from plant shift duty to assist in -

training operators. Host of th'e remaining training staff positions are filled by contractor The licenseo has openings for three licensed instructors on their trajning staff, with four instructors presently participating in a lic-ensed np9tator candidate course. Of the people enrolled in the current lic-ense candidate course, four ar6 scheduled to assume operator duties upon suc-cessful comple' tion of an NRC examination. The licensee has hired 10 addi-ticnal operators to participate in the next licensed operator cours The licensec has apparently made a corrmitment to Stevelop an adequate training staff and tg provide adequate licensed coerator trainjng instruction. The transfer of a former licensed operator instructor to manage the licensed operator program indicates the licensee's awareness of perceived deficiencias in the licensed operator training progra In summary, recent personnel changes in the operator licensing training pro-gram should help the licensee to further the impr6vement of relations between the operations staff and the t' raining department und result in a better training ' rogra p Generally, the operators were fbund to be knowledgcable and capable of effettively operating the plant. Tt.c new licensed operator candidates will not have the benefit of years of experiecce and therefore must be subjected to a high quality training program to ensure continued effective plant operation. The need to develop a quality training staff that can ef-fectively relate to the operations staff has been recognized ,by the license .0 FIRE ' PROTECTION The inspectors reviewed the causes of the nus.erous station fire watches that were in plcce at the time of the inspection and actions taken to reduce the number,- as well as other observed fire protection equipment conditloa _ - ,

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10.1 Fire Watches i

The licensee obtains fire watches from National Fire and Medical Service This contractor is supervised by'the senior fire protection enginee As of February 14, 1986, there were 72 plant locations requiring fire 4- watches (either continuous or hourly) resulting from 90 separate reason The reasons for these watches vary from inoperable fire protection sup-pression equipment and unsealed penetrations between fire area boundaries to one missing screw on a fire. doo t There is a significant backlog of fire protection MRs (over 250) which  ;

were open from 1984 to the present. This backlog has contributed to the '

number of fire watches needed. The FPE indicated that Bechtel was re-

! cently tasked to reduce this backlog.

I A total of five plant areas have five suppression systiem deficiencie These areas are the cable spreading room, emergency diesel generators, recirculation pump motor generator set room, the H2~ seal oil system and the standby gas treatment syste The halon system for the cable spreading room has not been weight tested s

as required by Technical Specifications. The halon system is connected j ' and considered functional. It is difficult to weight test because of the large size of the halon bottles, lack of sufficient clearance beneath

cable trays, and the fact that they are restrained by racks for seismic i purposes. This condition has existed for about two years without cor-

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rection. Engineering has been involved with attempting to determine j halon quantity in place'by a level detection system. An unofficial level l was obtained which indicated-that there had been no change in quantity in the bottles.

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It is not clear why this system was not taken out of

service temporarily, disassembled, and tested. . There appears to have ,

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been a lack of management attention to fix this problem and eliminate  !

l fire watch in this are Preaction sprinkler system for the emergency diesel generators (EDG) is  ;

j inoperable due to a design problem. -The existing _ circuit supervisory  :

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panels in the EDG room are not functional and the licensee is replacing  !

the panels under a 1983 design change (PDC). The 'A' panel is installed j

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but not yet tested, and the0' panel is'onsite but not yet installe )

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On March 5, the inspectors determined that the ' A' EDG preaction sprinkler '

system was tagged out due to installation and testing of the new fire

, control panel. This also'affected the D/G day tank room sprinkler system.

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Technical Specification (TS)'3.12.C requires that with an inoperable EDG

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day tank sprinkler system, a continuous fire patrol with backup suppres-l sion equipment be provided. -A. hose reel, which uses the 'B' EDG fire i- - main as a water source, was available'for use in the 'A' EDG and day tank

rooms. ~However, neither the.FPEs~nor the Nuclear Watch Engineer (NWE)

was aware of the current status of the:'A' EDG suopression system. The-j Nuclear Operating Supervisor (NOS) indicated that he was aware of this

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condition. Based on a discussion with two fire watches who had been assigned duty in the EDG rooms, neither had received any formal training in the use of fire extinguisher In addition, the fire door connecting ,

the 'A' and 'B' EDG rooms is blocked open to allow one fire watch instead of tw However, two individuals who manned this position stated that they had received no instruction to shut this door to prevent fire sprea This is another example of lack of management initiative to correct a long standing proble .

The deluge system for both trains of the standby gas treatment system is inoperable due to the manual block valves being tagged shut. This condition stems from an incident in 1983 in which a leaking valve caused wetting of a charcoal filter bed, and the system has been inoperable since that time. This appears to be another case where a fire watch has been used in lieu of achieving problem resolutio The majority of the remaining fire watches are for open penetrations, inoperable detector strings, and fire door problems. Some of the fire watches are not required by Technical Specifications (TS) because they are in balance of plant areas. Others are the result of the implementing Appendix R modifications and due to requested Appendix R exemptions which have not yet been approve Inspector review of the list of and reasons for fire watches indicated that the licensee is interpreting the fire watch requirements conserva-tively. Senior licensee management is kept aware of the number of fire watches by weekly reports, although no specific actions to reduce the number were observe The inspectors were also concerned with the level of training provided to the contractor fire watches. Several fire watches were interviewed to determine their responsibilities and level of training. With the ex-ception of fire watches for hot work, most of the contractor fire watches have little training in fire fighting including use of fire extinguisher Licensees procedure for fire watches specifies that the fire watches primary duties are to inform the control room in the event of a fire, although they are permitted to attempt to extinguish the fire, using extinguishers. The licensee's contractor issued a policy statement, after being notified of this concern, which stated that the fire watch would not use fire extinguishers unless directed to do so by the control room, and it was the fire watches responsibility to inform the control room if he was not trained. The licensee ~ stated that the fire watch procedure would be clarified. The FPE also indicated that he was sched-uling fire extinguisher training for the fire watches. The training of fire watches and the procedura modification will be reviewed during a future inspection (86-06-11).

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10.2 Other Observations On February 22, the inspector witnessed weekly surveillance test 8.B.1-10 for fire pump operability. The inspector noted the following good prac-tices. The procedure was thorough and able to be followed verbati Valve stems were well greased and the valves easy to operate. All three fire pumps (the electric, diesel, and jockey pumps) passed the acceptance criteri The room heating system for the diesel generator (D/G) fire pump was found to be out of service due to a frozen motor. As a consequence, the cell temperatures for the fire pump battery were below specificatio This condition had existed since December 1985. Electrical maintenance indicated that this was a procurement problem since the motor was Q-listed. They stated that an Engineering Service Request (ESR) had been prepared to address the procurement aspect .

Gland leakoff for the D/G fire pump was excessive and not contained by the drip tray. The relief valve relieved excessively while the pump was running, spilling water around the room. MRs had been written on these conditions. On February 26, the gland seal leakage was adjusted to an acceptable amoun The above discrepancies were discussed with the FPE on February 24. On February 28, the inspector again examined the D/G fire pump condition A portable electric heater using an ungrounded plug was directed at the battery in an attempt to keep battery cell temperatures within normal range. The heater was connected to an extension cord and the connection was laying on the room floor. If the D/G fire pump had started, this

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area was likely to get very wet from the leaking relief valve. The in-spector considered this to be a safety hazard, and brought it to the attention of the NWE. The condition was immediately correcte The inspector also observed housekeeping conditions and amount of com-bustibles during plant tours. In general, housekeeping was good and very little uncontrolled combustible material was observed in the plan .3 Summary A lack of management initiative to reduce the number of station fire watches was evident. Fire watch personnel had minimal training. Several examples of degraded fire protection equipment were observed. Licensee's actions to reduce the heavy reliance on fire watches and to improve oversight will be reviewed in a subsequent inspection (86-06-12).

11.0 ENGINEERING SUPPORT One inspector visited the Nuclear Engineering Department (NED) offices in l Braintree and discussed engineering support with NED managers and engineers.

! NED's primary mechanisms for site communications are morning phone calls with l

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the station management, the coordinating role of the NED Assistant Deputy Manager (ADM) onsite, and interpersonnel relations between individuals in the station and NED. NED managers make frequent site visit The inspector discussed current plant problems involving the HPCI system and fire protection with NED Mechanical Group leader. The individual was current on the status of these problems and his group was involved. The priority on addressing long standing fire protection problems (particularly those involv-ing suppression system deficiencies), however, has only recently been empha-sized (within the last three months). NEDs backlog of Engineering Service Requests (ESRs) was not increasing and approximately 400 ESRs were addressed in 1985. No attempt was made to determine the technical adequacy of the ESR resolutions. There is a good tracking mechanism for ESRs. The station man-agement receives periodic status reports of ESRs and can revise ESR priorities and schedules based on their needs and NED resource The inspector discussed engineering support with the onsite technical grou There appears to be a strong reliance on a small group of engineers and Shift Technical Advisors (STAS), all of whom have significant other responsibilitie The onsite technical group has a staff of ten professionals (5 of whom are reactor engineers) to provide support. All of the remaining engineers have significant project responsibilit The_ Performance group has nine STAS, two performance analysts with two vacancie The station intends to implement a system engineer concept with the technical staff, but no additional staffing is presently authorized. In the view of the team, the current onsite engi-neering staff is inadequate to support a system engineer concept, and its recommended that additional staffing be provided for this purpose. It is believed that proper implementation of this concept can provide a substantial increase in the quality of station operations. Much more flexibility would be available to investigate plant problem .0 SECURITY

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This section is based on observation in the security area during the course of the inspection period and on a previously occurring event reviewed during this period. The events reviewed during the inspection included propar security badge verification, security diesel surveillances, and followup of events surrounding a previously reported sleeping security guar An NRC inspector entered the main gate area of the Pilgrim station to obtain his security badge prior to reporting for inspection duties on February 22, 1986. The inspector upon requesting his security badge was given another NRC inspectors security badge. He immediately reported this to the security per-sonnel present and was given his correct security badge. The security badge presents a photograph of the individual as well as other pertinent information as signature, name, social security number, organization, et The inspector later discussed this event with a security superviso The

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security supervisor reported that a '! board check" had been conducted immedi-ately after the event to verify the badges were located in the correct slot In addition, the particular security guard and remaining security personnel

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were counseled on the even Boston Edison and contractor security management were notified. The contractor security supervisor stated that he believed the incident was isolated. During later plant entrances, NRC inspection per-sonnel noted an increased awareness of the security personnel to positively identify individuals with the correct security badg Licensee personnel conducted surveillance on the security diesel generator on February 19, 198 A problem developed during the surveillance with the inability of the operator to successfully load the diesel and as a result the diesel was shutdow The operators did not initiate a maintenance request (MR) because MR 85-46-158 (August 22, 1985; priority B) previously reported diesel synchronization problems. Maintenance personnel believed the synchroni-zation problem only involved a malfunctioning indicating light. The inspector discussed the security diesel surveillance and outstanding MRs with the cogni-zant electrical maintenance and security personnel. Both supervisors stated that they were unaware of the failure of the diesel to load during the Febru-ary 19, 1986 surveillanc The surveillance was conducted again on March 4, 1986 with acceptable result The security supervisor stated that he is going to request operations to change the procedure to notify security if security equipment should fail a surveillanc Prior to the start of the inspection, a contractor guard was found asleep by his supervisor while assigned to protect a deficient vital area barrier. It was determined that a vital area could be accessed via a pipe chase opening from a non-vital area. The licensee took compensatory measures to prevent unauthorized access by stationing a guard to secure the non vital area pro-viding access to the vital area. The licensee has completed a design change (PDC-86-08) review to seal the open area in the pipe chase and expects it to be accomplished before the next outag The guard's employment was terminate In summary, a few problems in the attentiveness of guards to routine duties were identified. One example of weak communication between the Operations, Maintenance, and Security Groups was identified. Planned increases in the number of licensee security supervisors should help to resolve these problems.

13.0 Observations of 1.icensee Management

) Licensee first line supervisors were strongly involved in station activities

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and were generally effective during the inspectio The team noted that management has improved some long standing problem areas, such as station contamination and housekeeping. However, other problems have been tolerated, such as.out of service fire suppression equipment, the large number of com-pensatory fire watches in the station, and long standing inoperable annunci-ators and nuisance alarm Upper level-corporate and plant management were often defensive about the inspection findings. For example, inspectors observed several morning con-ference calls between the station and corporate management and judged them

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ineffective because of a lack of aggressive participation. In response, the licensee blamed the NRC observers' presence at the meetings for the lack of activit In another example, the licensee blamed the stress from the in-spection for friction between the health physics and operations personne In the case of a late night safety review committee meeting, NRC presence was blamed for the length of the meeting and the extensive discussions that led to the conclusion that Standby Liquid Control System " squib" valve testing should be revised from bench testing to in-situ testing. (In-situ testing is required by Technical Specifications.) These responses indicate that lic-ensee managers do not always acknowledge problems, a weakness that could severely limit future improvements in station programs. An unwillingness to acknowledge previous problems was partially responsible for the current lack of Operations Department staffing and support. This defensive attitude was not noted in discussions with workers and first line supervisors.

Licensee management has recently initiated improvements in operations, main-tenance, and radiological controls which are important. However, most of these initiatives appear to be responses to third party findings, rather than a reflection of initiative from within the licensee's organization. One senior licensee manager indicated to the team that outside auditors were often useful in relaying station needs to the licensee's Board of Directors. The licensee should develop better internal methods of obtaining program support, reducing the dependence on third party auditors. The success of the planned program improvements will depend heavily on management attittdes strong direction and continuing suppor .--

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ATTACHMENT 1 INSPECTION REPORT 50-293/86-06 PERSONS CONTACTED The following is a partial listing of the licensee personnel that were contacted during the inspectin W. Harrington, Senior Vice President, Nuclear (Senior Licensee Manager Present at

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the Exit Interview)

L. Oxsen, Vice President, Nuclear Operations E. Howard, Vice President, Nuclear Engineering and Quality Assurance C. Mathis, Nuclear Operations Manager P. Mastrangelo, Chief Operating Engineer D. Swanson, Nuclear Engineering Department Manager H. Brannan, Quality Assurance Manager K. Roberts, Director Outage Management N. Brosee, Maintenance Section Head T. Sowdon, Radiological Section Head J. Seery, Technical Section Head

E. Ziemianski, Management Services Section Head S. Wollman, On-Site Safety and Performance Group Leader B. Eldridge, Acting Chief Radiological Engineer R. Sherry, Chief Maintenance Engineer D. Mills, Construction Management Group Leader J. McEachern, Resource Protection and Control Group Leader E. Graham, Compliance and Administrative Group

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ATTACHMENT 2 INSPECTION REPORT 50-293/86-06 SURVEILLANCE TESTING ACTIVITIES Portions of the following surveillance testing activities were reviewed:

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Monthly test of the "A" Emergency Diesel Generator for February 1985, proce-dure 8. Weekly surveillance of the auxiliary transformer, February 20, 1986, procedure 8.C.17

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Weekly surveillance of the 4.16kv/480v switchgear, February 20, 1986, proce-dure 8.C.18 l --

Weekly surveillance of the shutdown transformer, procedure 8.C.23

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Weekly surveillance of the vital MG set, procedure 8.C.20

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Manual initiation test of one SLC system (once cycle) procedure 8. HPCI pump operability flow rate and valve test at 1000 psig (monthly) proce-

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dure 8.5.4.1

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Special test surveillance of SLC firing circuits

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Calibration of the area radiation monitoring system procedure 6.5.160 Fire water supply system shutoff valve inspection (monthly) procedure 8. Daily surveillance log (tech specs and regulatory agencies) daily log test

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Fire pump test (weekly) procedure (8.B-1)

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Control rod exercise (weekly) procedure (8.3.2)

Routine running of standby gas treatment system (weekly) procedure (8.C.4)

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Core spray pump operability and flow rate test (monthly) procedure 8.5. Core spray system integrity surveillance (quarterly) procedure 8. A.18

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Core spray pump operability and flow rate test (monthly) procedure 8.5. Main steam line high radiation procedure 8.M.1-12

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HPCI steam line low pressure procedure 8.M.2.54

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Primary containment isolation valves (twice week) procedure 8.7.4.5 i

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Attachment 2 2

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LPCI motor operated valve operability test (monthly) procedure 8.5. LPCI motor operated valve operability test from alternate shutdown panels procedure 8.5. HPCI system IST quarterly test procedure 8.5.4.1B

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HPCI valve operability test (monthly) procedure 8.5. RCIC pump operability flow rate and valve test at 1000 psig (monthly) proce-dure 8.5. RCIC valve operability (monthly) procedure 8.5. RCIC pump operability flow rate and valve test at 1000 psig (monthly) proce-dure 8.5. RCIC valve operability (monthly) procedure 8.5.5.4

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HPCI pump operability flow rate and valve test at 1000 psig (monthly) proce-dure 8.5. Automatic depressurization system subsystem logic with reactor in other than shutdown procedure 8.M.2.2

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ATTACHffENT 3 .

INSPECTION REPOP.T 50-?93/86-06

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0FFICE MEMORANDUM 4[6302900 Boston Edison Company RMG Control Number Subject: Report on Tripping of. Motor Control Center 820 DESCRIPTION:

On February 11, 1986, at approximately 1039 hours0.012 days <br />0.289 hours <br />0.00172 weeks <br />3.953395e-4 months <br />, electricians, while breaker 52-604 and deenergizing 480 volt safety-related The bus B20.sp electricians, notified sensingpersonne Operations' the trip of B20 and suspecting it's cause, immediately Operations' personnel had already initiated ;

the clearing and reenergizing approximately 1047 hour0.0121 days <br />0.291 hours <br />0.00173 weeks <br />3.983835e-4 months <br /> of bus B20 and returned it to service at ,

EVENT BACKGROUND:

On October 19, 1984, Maintenance Request Number 84-46-512 was written which identified a cable that was visually faulted and needed repair. The cable was later identified as cable number B2013J, which station electrical drawings indicate is powered from breaker 70 ampere, Westinghouse Model 'HFA' breaker.52-2013B, a three-phase, 480 volt, located in the 'B' valve room of the Reactor Building.The cable feeds a welding outlet On February 11, 1986, at approximately 0800 hours0.00926 days <br />0.222 hours <br />0.00132 weeks <br />3.044e-4 months <br />, after breaker 52-2013B had been tagged in the open position, Maintenance maintenance personnel were authorized to start work on Request 84-46-512. This maintenance request is added to this report as Attachment breaker 52-604 and deenergizing safety-related bus B20.During this cabl An immediate investigation into the cause of the event revealed that the cables had been removed from the load side of breaker side of breaker 52-2016B, a previously5?-20138 and reconnected to the load designated " spare" breaker located approximately 3 feet below breaker MCCB2 B, in the same motor control center, ticcun m

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/%R EC ETT/75 \

Dept. Doc. TCH 86-75 (H1220) Page 2

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To: C. J. Mathis Date: February 27, 1986

. Sub' ject: Report on Tripping of Motor Control Center B20

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The breaker 52-2016B is a Westinghouse Model 'HFA', 480 volt, 100 ampere ,

breake CAUSE:

The analysis of this event determined that faulty breaker 52-2016B coupled with the grounding of non-safety related cable B2013J and the existence of an g unrestored temporary modification performed in 1976, resulted in the trip of -

safety-related bus B2 An immediate investigation revealed that breaker 52-2016B remained O energized throughout this event and had to be manually tripped after the discovery of the wiring change. Since breaker 52-2016B did not trip when cable B2013J was inadvertently grounded, it was removed from service and .

tested via station procedure number 3.M.3-3, entitled "480 MCC Breaker Trip Device." The breaker failed its instantaneous current trip test. The results of this test are added to this report as Attachment An investigation of the wiring change revealed that during Refuel Outage

1. 2, on approximately March 5,1976, a temporary modification to MCCB20 was performed. The modification was documented on Maintenance Work Order N H. A copy of this Maintenance Work Order is added to this report as Attachment C. The modification consisted of transferring the load side cables .

This temporary of breaker 52-2013B to the load side of breaker 52-2016 modification was not restored to normal after the outag .

The grounding of cable B2013] did not trip the faulty 52-20168 breaker; therefore, the next breaker in the coordination scheme, breaker 52-604,

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tripped fulfilling its intended safety function and cleared the faul Breaker 52-604 is the supply breaker to safety-related bus B20 and the tripping of breaker 52-604 deenergized bus B20. A single line diagram depicting these breakers with their intended loads is added to this report as Attachment ROOT CAUSE DETERMINATION:

The root cause of this event was the failure to control the temporary modification to MCCB20. Designated spare breaker 52-2016B was not intended for service and cable B2013J should have been verified by monitoring as l deenergized before work began, but other checks, which were performed, should J have sufficed to ensure its deenergizatio CORRECTIVE ACTION:

On February 12, 1986, repairs to cable B2013J were completed and the cables were returned to the load side of breaker 52-2013B, which was left tagged open. To ensure that similar modifications to spare breakers had not been performed, the remaining safety-related, 480 volt, motor control center station breakers designated " Spare" were inspected to verify their statu .

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Dept. Doc. TCH 86-75 (W1220)

To: C. J. Mathis Date: February 27, 1986 Page 3

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Subject: Report on Tripping of Motor Control Center B20

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'The in'spection confirmed that these breakers were correctly designated

" Spare." A similar inspection was performed on the non-safety related spare 480 volt motor control center breakers. This inspection revealed that one breaker, 52-2124 marked " Spare", is feeding a load; however, station electrical prints do indicate a connected load and this marker will.be changed. The results of these inspections are added to this report as Attachments El and E2. On February 12, 1986, to reemphasize safety practices in the repair of electrical cables, a meeting was held with Maintenance personnel. During these instructions special attention was given to the techniques to be used to verify that cables are deenergized before initiating repairs on the (Refer to Safety Meeting Notes, Document No. M86-48 Attachment G.)

CONSEQUENCE: "

. MCCB20 is a safety-related bu Loss of this bus affects Primary Containment Isolation and other safety-related systems. As a precaution, an orderly shutdown was initiated following the loss of this bus. This was terminated when B20 was returned to service. Loss of B20 reduced redundancy in automatic isolation capability in Reactor Water Cleanup and RHR system and defeated the automatic operation of the LPCI subsystem of the RHR system. The Stack Gas monitoring panel C2247 and emergency lighting panel 17L were also made inoperable by the loss of B20. The actions required by the Limiting Conditions of Operation for these systems

- was not taken because the MCCB20 was returned to service immediatel No

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condition not specifically considered in the PNPS Safety Analysis Report resulted from the loss of MCCB2 . Breaker 52-20138 was analyzed as part of the equipment requiring equipment qualification per 10 CFR 50.49.b2. It was identified as requiring testing l

to verify its proper operation as a breaker on a safety-related bus which feeds a non-safety load. It was tagged open on November 30, 1985, via NWE Tag #46-147 pending satisfactory completion of required testing. The unrestored Temporary Modification to 52-2013B defeated this protective actio . The implication upon finding an unrestored temporary modification is that other similar modifications might exist in the plant. To prevent occurrences of this type, administrative controls for plant modifications i and temporary jumpers have been in effect at PNPS since before this I l

unrestored temporary modification occurred. Additionally, to address a perceived potential for an occurrence of this type, a temporary modification procedure, Station Procedure Number 1.5.9 was implemented in ]

February, 1982. To detect changes which may have been performed without sufficient control prior to 1982, a review of previously documented changes was made and walkdowns of many of the plant's electrical and mechanical components have been performed. Because of improvements !

resulting from these efforts, we believe this occurrence to be an isolated l event. For convenience, a copy of the Failure and Malfunction Report l generated by this event and a copy of the WE Logbook-for February 11, 1 1986, are added to this report as Attachments F1 and F !

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To: C. J: Mathis Date: February 27, 1986 Page 4

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Subject:.. Report on Tripping of Motor Control Center B20

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CONCLUSION

f The' protective trip of_MCCB20, via breaker 52-604, for reasons already

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stated, is an isolated even This trip did not create a condition not

specifically cont.idered in the Safety Analysis Report for Pilgrim Statio This event focuses our attention on the importance of controlling modifications to the plant's equipment, components and structures to prevent

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incidents of this type in the future.

RECOMMENDATIONS:

Although the inspection of other 480 volt spare breakers did not reveal any other unrestored temporary modifications, it did disclose other minor discrepancies which should be corrected and common practices which should be abandoned. Proposed changes to correct these minor discrepancies and reduce the potential for confusion are contained in the following recommendations: Temporary paper markers attached to the 480 volt breaker panels should be replaced with permanent Bakelit tags. Temporary paper markers should not

• be utilized in the future except for very short duration (1 week). When modifications change single line diagrams similar to E9, these l changes should be added to the Control Room and station controlled print

sets before a system is declared operable in a manner similar to print

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controls established for P&ID' . Station Drawing Number S-E-155, entitled " Station Electrical Single Line Composite Diagram 4.16KV & 480V - AC Systems," should be compared to other

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Motor Control Center Single Line Diagrams and absolute agreement achieved and maintaine . For spare breakers with unterminated cables connected to them, either the cables should be disconnected, coiled and taped, or the markers should indicate their disconnect location and not simply indicate " Spare." Spare breakers should be secured in the open position and strictly controlle . Station Procedure 2.4.143, Page E9, should be revised to reflect the desired condition of breakers 52-2036, 71, 93 and 52-17116.

I Consideration should be given as to whether additional procedural controls or surveillances are appropriate for spare breaker REFERENCES: PNPS Procedures 2.4.143 and TP85-Il7 ' FCN No. 7530 Jumper Log Entries . NED Memo 85-1153 Report Attachment Drawing Number E9, E5010 E5012, S-E-155 E217 Sh 61, E532 Sh 34 PNPS Technical Specifications Attachments: A through G l

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O ATTACHMENT 4 INSPECTION REPORT 50-293/86-06 NRC FOLLOWUP TO THE TRIPPING 0F MOTOR CONTROL CENTER B20 The team attended a licensee presentation of the event details February 28, 198 A review was conducted of the licensee's report, dated February 27, 1986, which described the event, corrective actions, and provided an analysis of the even In addition, the team conducted an independent assessment of the circumstances surrounding this event, which included personnel interviews and reviews of all applicable maintenance and engineering documentation. Relevant portions of the licensee's internal event report are contained in Attachment 3 to this inspection repor Based upon the NRC's review, the following comments and conclusions are warranted: The 20138 480VAC breaker on MCC B20 was designated in plant procedures and drawings as a supply for welding receptacles and the nitrogen fill pump re-ceptacle. The breaker was analyzed as part of the plant's equipment requiring Environmental Qualification (EQ) per 10 CFR 50.49.b.2. It required testing to verify its proper operation as a breaker on a safety related bus which feeds a non-safety load. Instead of conducting the test, the breaker was tagged open on November 30, 1985. A temporary modification in 1976 resulted in the circuit being powered from another breaker and defeated the mitigating action of tagging open the 2013B breake As documented in NED Memo 85-1153 dated November 7, 1985 and procedure TP 85-117, EQ MCC Breaker Tests, the licensee intended to test the 20138 breaker to validate a breaker coordination study which assures EQ requirements are met. However, there was reluctance on the part of plant operators to release this breaker for testing because this action would have entailed de energizing an adjacent breaker (2013A) which would have resulted in de-energizing Emer-gency Lighting Panel 17L. The team concluded that the operators exercised appropriate judgement in tagging open breaker 20138 as a compensatory actio The plant operator's could not have reasonably known of the loss of configura-tion control that occurred in 197 Since this event potentially involves the licensee's failure to be in compli-ance with the EQ rule subsequent to November 30, 1985, additional review and potential enforcement action may result subsequent to the completion of this inspection. This item is being tracked by existing Unresolved Item 50-293/

86-01-0 . MR 84-46-512 was issued by the licensee on October 19, 1984 to repair or re-place cabling that was visually faulted. The degraded cabling was not re-paired until February 11, 1986. This represents a 16 month period from the time of identification of the condition until the time of repair. The ele::-

trical maintenance worker who eventually performed the cabling repair conducted the initial investigation on or about November 12, 1984, and completed proce-

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c Attachment 4 2 dure 3.M.3.8, Inspector / Trouble Shooting-Electrical Circuits. The licensee has been unable to locate the completed copy of this procedure. The worker stated that he considered it to be incredible that~ cabling with the extent of damage observed could be energized for the 16 month period, The licensee's lack of implementation of important corrective maintenance in this case is one indication of an inappropriate prioritization of maintenanc Additionally, it appears that an appropriate level of first line supervision was not provided for this maintenance activity at both the initial time of discovery and investigation in October / November 1984, or during the initial repair efforts on February 11, 198 . Procedure 3.M.1-1, Preventive Maintenance, specifies that breaker over current devices are calibrated on 480VAC MCC with the Preventive Maintenance (PM)

Program being maintained and scheduled as directed by procedure 1.8.2, PM Tracking Program. This latter procedure specifies the use of a group list which provides the testing to be performed, when it is to be done, and the applicable procedure to be utilized. The Master Surveillance Tracking Program Group list designates the 480 VAC MCC breaker trip device calibration tests as being performed by the licensee once per cycle during the refueling outage, and in accordance with procedure 3.M.3-3. The purpose of this procedure is to verify, in part, the calibration of the molded case MCC breaker The licensee planned to calibrate anti overhaul breaker 2013B during the 1984 refueling outage. However, this work was not done. Had the PM program for the 2013B breaker been implemented as envisioned, they would have detected the unrestored temporary modification and prevented the subsequent loss of safety related MCC B2 . A meaningful PM program for 480 VAC molded case breakers has not been devel-ope The licensee has indicated that they have initiated actions to develope a PM program consisting of: 1) procure an appropriate testing device, 2) de-velop testing procedures, 3) develop appropriate acceptance criteria that have their bases in a fault coordination study, and 4) issue an Engineering Service Request that will enable them to procure replacement breakers for the PM Pro-gram. At the exit interview, the licensee was requested to provide the NRC their plans and schedules for initiating a baseline FM program for safety re-lated 480 VAC molded case breakers during their next refueling outag This item will be reviewed during a future inspection (50-293/86-06-13).

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l ATTACHMENT 5 INSPECTION REPORT 50-293/86-06 LICENSEE RESPONSE ITEMS AND INSPECTOR FOLLOW ITEMS Licensee Response Items The licensee is requested to respond to each item, describing the planned

. action and the estimated completion dat . Evaluate the need to include instrument root valve positions in station procedures and drawings (86-06-01). Complete labeling of station valves and components (86-06-03). Establish a policy on allowing licensed personnel outside the plant protected area boundary while onshift (66-06-04). Investigate the cause and required corrective actions for the residual RCIC flow indication occassionally noted after RCIC surveillance tests by June 1, 1986 (86-06-06). Upgrade the ALARA program, including implementation of ALARA procedures, earlier incorporation of ALARA planning into work planning process, and completion of an evaluation of ALARA for "A" priority RWPs (86-06-09). ' Implement a baseline preventative maintenance program for 480 VAC molded case circuit breakers in motor control centers during the next refueling outage (86-06-13, Attachment 4).

II. Inspector Follow Items These items will be reviewed during subsequent NRC inspection .

The licensee's evaluation of hi/lo annunciator alarms (86-06-02). The implementation of an independent verification program (86-06-05). The implementation of GE SIL 186, concerning standby liquid control system squib valves (86-06-08). The resolution of QA audits 84-34 and 85-25 (86-06-10). The training of fire watches and modification of their procedural in-structions (86-06-11). The reduction of the number of station fire watches (86-06-12).