IR 05000293/1986029

Insp Rept 50-293/86-29 on 860805-0915.No Violations Observed.Major Areas Inspected:Plant Operations,Radiation Protection,Physical Security,Plant Events,Maint, Surveillance,Outage Activities & Repts to NRC

ML20215H072
Person / Time
Site:	Pilgrim
Issue date:	10/08/1986
From:	Strosnider J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20215H067	List: IR 05000293/1986029 ML20215H065
References
50-293-86-29, NUDOCS 8610210425
Download: ML20215H072 (19)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket / Report No. 50-293/86-29 Licensee: Boston Edison Company

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800 Boylston Street Boston, Massachusetts 02199 Facility: Pilgrim Nuclear Power Station i.ocation: Plymouth, Massachusetts l Dates: August 5, 1986 - September 15, 1986 Inspectors: M. McBride, Senior Resident Inspector J. Lyash, Resident Inspector R. Str ckm yer, Radiation Specialist M*e t /d[/ 8 86 Approvedby:[,A. Strosnider, Chief, Reactor Projects Date

" Section IB

Summary: August 5, 1936 - September 15, 1986 Inspection Report 50-293/86-29 Areas Inspected: Routine. resident inspection of plant operations, radiation

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protection, physical security, plant events, maintenance, surveillance, outage activities, and reports to the NRC. Inspection totaled 231 hours0.00267 days <br />0.0642 hours <br />3.819444e-4 weeks <br />8.78955e-5 months <br /> by two resident inspectors.

, Results: Weaknesses in the control, calibration and testing of safety related

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protective relays and breakers were identified (section 2). The absence of a P&ID for the emergency diesel turbo boost air system is discussed (section 2).

Poor valve labeling is described (section 3 b). Control of onsite contractors is discussed (section 3.d). Concerns regarding the release of unsurveyed material from site and the effectiveness.of licensee followup were identified (section 4.c). Weaknesses in the area of interface between operations and maintenance is outlined (section 4.d). Standby gas treatment system design deficiencies identified by the licensee are described (section 4.e). Failure of the B core spray pump test return line check valve is described (section 4.f). A poor health physics practice concerning treatment of dosimeters is discussed (section 6). Concerns about the adequacy of one LER and the reportability of degraded fire seals are discussed (section 7).

861021042S 861014 PDR ADOCK 05000293 G PDR

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TABLE OF CONTENTS Page S umma ry o f Fac i l i ty Ac ti v i ti e s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Followup on Previous Inspection Findings ..................... 1 Routine Periodic Inspections ................................. 5 1 Daily Inspection, System Alignment Inspection,

Biweekly Inspections, Plant Maintenance and

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Surveillance Testing

Review of Plant Events ....................................... 8

! Failure to Perform Scram Discharge Volume Instrument Testing ~as Required by Technical Specifications.......................................... 8 Failure to Perform Nitrogen Make-Up Monitoring Required by Technical Specifications .................... 8 Unsurveyed Material Released from Site................... 9 Residual Heat Removal System Instrument Line Weld Failures ................................................ 10 Susceptibility of SBGT System to Single Failures......... 11 Core Spray Loop B IST and Test Line Check Valve Failures ................................................ 12 Core Spray Valve M0-1400-4B Yoke Flow Indication. . . . . . . . . 13

< Main Steam Line Low Pressure Sensor Cable Damage .................................................. 14

. Fire Within the Protected Area .......................... 13 Observations of Physical Security ............................ 14 Radiation Protection ......................................... 14 j Review of Licensee Event Reports (LER's) .................... 15 j Management Meetings .......................................... 16 l-i

! Attachment I.- Persons Contacted

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DETAILS 1.0 Summary of Facility Activities The plant was shutdown on April 12, 1986 for unscheduled maintenance. On July 25, 1986, Boston Edison announced that the outage would be extended

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to include refueling and completion of certain modifications. During the report period disassembly and inspection cf the Residual Heat Removal (RHR) pumps continued. The scope of this effort was expanded to include disassembly of the Core Spray pumps. Installation of the Analog Trip System and Appendix R modifications are also in progres .0 Followup on Previous Inspection Findings Violations (Closed) Violation (85-17-01), failure to establish, maintain or implement surveillance tests for the station 125 and 250 VDC batterie The inspector reviewed station procedure 8.C.14, Revision 16, Weekly Pilot Cell and Overall Battery Check and Weekly Battery Charger Test.

j Revisions have been made to ensure testing of the 250 VOC battery and to

) include a fahrenheit-to-centigrade conversion chart. The inspector reviewed several completed surveillance tests and verified that all required data had been recorded, acceptance criteria were met, and the correct pilot cell had been chose This item is close Unresolved Items (Update) Unresolved Item (86-25-05), calibration, testing and control of safety related protective relay Inspection report 86-25 identified that the control of protective relays, and functional testing of certain critical bus transfers, appeared to be inadequate. Based on this finding, the inspector reviewed the system in place to ensure that the settings of all protective relays and breakers are adequately controlled, calibrated and teste presently, control of settings and calibration information for safety related protective relays and breakers is maintained by the Boston Edison Engineering Planning and Research (EP&R) Grou This is a corporate test group and does not report through the nuclear organization. EP&R controls this information primarily through the use of a computer data base. The data base was originally developed for use with overcurrent protection devices. Other device types (i.e. undervoltage, underfrequency, etc.)

have been put into the same data fields, resulting in a confusing data base printout. Not all information required for relay calibration is included in the printou For example, recommended settings for the Emergency Bus Voltage Relays were ~specified at the lower limit of the technical specification allowable drop-out range, and no pickup setting had been specified. Since no field is provided for collection of "as-found" data, this information has not been collected. In addition,

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because no controlled design documents exist, settings may be changed through memos which are not reviewed by the safety review committee The Low Pressure Coolant Injection (LPCI) valves for both LPCI loops are powered through the same 480 VAC load center, B6. Bus 86 can be supplied from either diesel generator. Two undervoltage relays are installed on each of the two B6 power supplies. The undervoltage relays will, if loss of the normal supply is sensed, transfer B6 to its alternate supply. In order to complete this transfer 125 VDC control power from swing bus D6 is required. Like 480 VAC bus B6, an auto transfer from the normal to alternate battery source on loss of voltage is provided for 125 VDC bus D6. The two auto transfer functions (i.e. transfer of B6 and D6) are

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critical in supporting the licensee's assumptions regarding available CSCS in the accident analysi Procedure 3.M.3-1, contains instruction for calibration and functional

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testing of the 480 VAC bus undervoltage relays involved in the B6 transfe This procedure however, defers to the computer data base (discussed above)-

for calibration information, lacks detail, and does not record "as found" dat In response to this finding, 2 licensee revised procedure 3.M.3-1 to include more detailed test instructions and to r2 quire recording of

, "as found" data.

3 No procedure exists for calibration and functional testing of the 125 VDC bus 06 auto transfer feature. A functional test of this feature however was performed informally during the 1984 outage due to the initiative of station personnel. The 06 transfer feature had not been tested prior to 198 The, licensee has developed a set of controlled design drawings specifying calibration and test information for 480 VAC load center breakers, drawing E7-133. Such documents do not exist for 4160 VAC and lower voltage pro-tective relays. Neither the EP&R computer data base nor controlled drawings specify 480 VAC meter control center (MCC) breaker setting In light of the above concerns licensee maintenance and engineering management committed to take the following corrective actions:

1) Controlled drawings documenting safety related 4160 VAC protective relay settings and calibration requirements will be develope ) Controlled drawings documenting safety related 480 VAC MCC settings will be developed. Current settings will be forwarded by engineering to the station for inclusion in test procedures until

'he above drawings are complete ) Settings and calibration information for undervoltage relays associated with 480 VAC bus 86 auto transfer will be added to E7-133. In addition an evaluation to identify 480 VAC, and lower i voltage, relays which may require similar treatment will be performe I

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4) Any changes to safety ralated protective relay or breaker settings will be processed as temporary modifications or plant design change ) A procedure to functionally test the 125 VDC bus D6 auto transfer feature will be written and performed during this outag Program and procedure weaknesses were noted during the review. These weaknesses create the potential for improper setting changes or inaccurate calibration. However, knowledgeable maintenance and engineering personnel involved in day-to-day implementation and control of these activities have partially compensated for the program weaknesses. Many of the findings identified by the inspector had previously been identified by licensee personnel and some action was taken. Strengthening of the process how-ever, will ensure continued compliance. This item will remain open pending completion of the above items and review by the inspecto Inspector Follow Items (Update) Inspector Follow Item (84-02-01), A large maintenance backlog exists; licensee to complete all outstanding 1981 and 1982 MR's by the end of 1984 outage. A large maintenance request (MR) backlog continues to exist. Review of outstanding MR's on a sampling basis has been performed by both resident and region based inspectors. No specific incidents of impact on safety related equipment operability have been identified. The licensee has established a planning and scheduling group, increased maintenance staffing and established a station procurement support section. If these additional resources are effectively used a reduction in maintenance backlog could resul Regional specialist inspection 50-293/86-27 examined this area and reached a similar conclusion. This area will continue to receive review during routine inspection (Update) Inspector Follow Item (84-28-02), no P&ID for the emergency diesel generator air start system. The inspector verified that a con-trolled piping and instrument drawing (P&ID) had been developed for the diesel air start system. No such drawing, however, had aeen developed for the turbo boost air system for the diesel generators. The licensee's engineering department stated that a P&ID for the turbo boost air system would be issued and that other systems would be evaluated for drawing adequacy. This item remains open pending issuance of this drawing.

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(Closed) Inspector Follow Item (84-39-05), Review revision of procedure 8.C.13 and its implementation. Discrepancies between actual valve ccnfiguration and operating procedures were identified. The inspector reviewed procedure 8.C.13, Revision 17, Lock Open, Lock Close Valve Lineup Surveillance, and procedure 2.2.20, Revision 28, Core Spra Adequate core spray vent valve positions had been specified in procedure 2.2.20. Procedure 8.C.13 incorrectly identified the locked closed core spray loop B vent valves as 204B and 2058. The licensee later revised the procedure to correctly identify the valves as 202B and 203 The

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inspector verified proper valve position and labeling in the field. This item is close (Closed) Inspector Follow Item (85-17-05), review control room Yarway indi-cator agreement and evaluate any additional discrepancies. The licensee has experienced several incidents of disagreement between level indications in the control room derived from the Yarway instruments. In these incidents it was confirmed that the disagreement was confined to the indicators; the level sensing instruments were not affected. The licensee believes the problems to originate from unreliable signal conditioners in the indication loop. The licensee is replacing the Yarway instruments with an analog trip system during the current outage. This replacement should eliminate the instrument discrepancy problem. This item is close (Closed) Inspector Follow Item (85-31-03), review corrections to procedure 8.5.2.2. Incorrect valves and valve numbers had been specified in a sur-veillance procedure. The inspector reviewed station procedure 8.5.2.2, Revision 20, LPCI Pump Flow Rate Test and MOV Timing. Applicable procedure steps and acceptance criteria have been revised to include accurate check valve numbers. This item is close (Closed) Inspector Follow Item (86-01 02), review MSIV surveillance con-ducted in September 198 During inspection report period 86-01, the licensee could not provide results from the required quarterly main steam isolation valve closure timing test performed in September 1985. The inspector reviewed the results provided by the licensee during the present report period for the test performed on September 27, 1985. No signifi-cant trend in valve closirg times was noted by the inspecto This item is close (Closed) Inspector Follow Item (86-06-04), establish a policy on allowing licensed personnel outside the plant protected area. Procedure 1.3.34, Conduct of Operations, Revision 10, now identifies that the licensed reactor operators required by technical specifications must remain on-site; within the confines of the security fenc The inspector noted that the above restriction had not been indicated as applicable to the second licensed senior reactor operator. The licensee stated that the procedure would be revised to make this clarification and a procedure change notice was initiated. This item is close (Closed) Inspector Followup Item (86-09-01). Improve interlaboratory quality control program. For the large majority of sample analyses, the Yankee Atomic Environmental Laboratory (YAEL) meets the criteria set forth by the EPA in its Laboratory Intercomparison Program. Although in several instances the YAEL criteria for accuracy were not met, this is due to the generally more restrictive nature of the YAEL criteria versus the EPA criteria. The recommendation for improvements to the interlaboratory quality control program is therefore withdraw ___

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(Closed) Inspector Follow Item (86-25-03), review acceptability of licensee actions regarding reportability of cracked welds in the feedwater check v41ves. Cracked wrist pin tack welds had'been identified at Mill-stone unit 3 and reported under part 21 by the vendor, Anchor / Darling, on June 11, 1985. Boston Edison was.not notified of the potential proble On July 21, 1986 Anchor / Darling field representatives identified that similar valve designs had been installed at Pilgrim. Part 21 notifica-tions were then transmitted to Boston Edison and NRC:IE by Anchor / Darling identifying the omission. On July 23, 1986, during inspection of the four main feedwater check valves it was discovered that 17 of 32 wrist pin bushing tack welds were cracked. Since prior part 21 notification had been made, no additional notification was required. Consultation with NRC: Region I indicates that no licensee event report is required in cases where information has previously been accurately reported in a vendor part 21 report. A design change eliminating the need for the tack welds has been recommended by the vendor and approved for implementation by Boston Edison. This item is close IE Bulletins (Closed) IE Bulletin (79-8U-1B), Environmental Qualification of Class IE Electrical Equipment. A special team -inspection was conducted at Boston Edison engineering offices and Pilgrim Station during December 9 to December 13, 1985. The purpose of the inspection was to determine licensee compliance with 10 CFR 50.49. The team concluded that Boston Edison had implemented a program for establishing and maintaining the qualification of electrical equipment. The results of the inspection are documented in inspection report 50-293/85-35. This item is administrative 1y close .0 Routine Periodic Inspections Daily Inspection During routine facility tours, the following were checked: manning, access control, adherence to procedures and limiting conditions for operations (LCO's), instrumentation and recorder traces, control room annunciators, safety equipment operability, control room logs and other licensee documantatio During a tour of the safety relatea 4160 VAC switchgear room, the inspector noted that the voltage pickup tap setting for undervoltage relay 127A-A6-2 was not consistent with settings on similar relay The licensee removed tne relay, corrected the tap setting and recali-brated the relay. While the tap setting was incorrect, bench testing verified that adequata internal adjustment had been made to achieve the required trip setpoints. Review of previous calibration data sheets and discussions with test personnel, indicates that the incor-rect tap setting had existed for some tim It had not been identi-fied because the recommended setting, not the "as left" setting, had been recorded on the data sheet. The control of protective relay calibration is further discussed in section 2.0 of this repor . . , -_- - --- _ - - - ---

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During a tour on September 8,1986, the inspector noted that a dumpster filled with wood and trash had been placed within one foot of the licensee's compressed gas bottle storage facility. Signs posted on the facility stated that storage of flammable material within fifty feet of the building was prohibited. The inspector also noted that a wooden storage building was located within 50 feet of the gas bottle facility and that a fitting on the fire water spray system for the building was leaking. These items were discussed with the licensee. The spray system leak had been caused by freezing of the small diameter pipe and had been known to exist for some time, however, no effort to repair the leak had been mad On September 9 the flammable material had not been removed and in fact additional flammable trash had been placed next to the building. The inspector discussed the apparent lack of sensitivity to fire system maintenance and flammable material storage with

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licensee management. Subsequently, the licensee took action to

remove the flammable trash, repair the spray system leak, and 4 clarify the fire code requirements. The inspector had no further questions.

., b. System Alignment Inspection Confirmation of the operability of selected systems was made. Valve positions were verified during routine checks of the control roo Breaker alignment and instrument indications were also checke The inspector walked down accessible portions of the Emergency Diesel Generator system piping, instrumentation and electrical equipment. Major manual and automatic valve, instrumentation valve, I and electrical component positions were verified to be correct and consistent with applicable operations procedures. The inspector observed the general condition of equipment and area Review of system operation procedures indicates that many instrument root and isolation valves are not included in system lineups. These valves are also not shown on applicable P& ids, and are not labeled in the field. This condition was previously identified in inspection re'p ort 86-06 (IFI 86-06-01). The need for more positive controls over instrument isolation valves was also noted in inspection report 85-30 (IFI 85-30-08).

Major flow path valves were labeled, however, numerous labels con-tained only component noun names. No numerical designators had been included on the labels or in the operating procedures. Operations personnel stated that final walkdown and labeling of the diesel generators had not yet been performed. The licensee stated that as walkdowns are performed, new tags containing both component numbers and noun names will be applied. The need for followup to ensure that an accurate and complete valve labeling program is implemented was previously identified as IFI (86-06-03).

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- Biweekly Inspections During plant tours, the inspector observed shift turnovers, plant conditions, valve and instrumentation lineup, radiological controls, security, safety, and general adherence to regulatory requirement Plant housekeeping and cleanliness also were evaluate Plant Maintenance The inspector observed and reviewed maintenance and problem investigation activities to verify ce pliance with regulations and procedures, codes and standards, QA/QC involvement, safety tag use, personnel qualifications, radioiogical controls, fire protection, retest requirements, and reportabilit During the period the inspector witnessed activities associated with ongoing plant modifications. Cable pulling and termination, conduit installation, and core drilling were observed. Activities appeared to be controlled and performed in accordance with proper authorizing documents and specifications. Quality control measures appeared to be effectively implemente Activities associated with inspection and overhaul of the residual heat removal (RHR) system pumps continued throughout the perio The B and D RHR pumps were disassembled and inspected with no signs of pump impeller wear ring cracking identified. Samples of wear ring material were removed and sent for analysis. Analysis results have not yet been received by the licensee. The pump impeller wear rings were replaced, the pumps and motors reassembled, and initial preoperational testing begun. During the inspection period the inspector witnessed portions of disassembly, inspection, reassembly and testing activitie On August-18, 1986 during disassembly of D RHR pump it was discovered that a seal cartridge mounting stud was frozen in plac Craft personnel under the direction of General Electric (GE)

attempted to loosen the stud by striking it with a hammer and chisel, resulting in damage to the mounting surface. The stud was broken off daring further attempts to remove it. Craft personnel drilled and tapped a hole in the stud to allow use of a broken stud removal tool. This tool also snapped off. These activities were beyond the preplanned craft work scope. No GE supervisory personnel were present at the jobsit The incident was promptly brought to the attention of the responsible Boston Edison project manager by GE supervi sir >n .

The inspector reviewed the corrective actions taken to ensure that future, possibly safety significant, incidents are avoided. The requirement that GE supervision be present during all work activities has been implemented. Meetings to review the work to be perform 3d during each shift have been instituted. The individuals responsible for the incident have been remove .

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The inspector discussed with licensee management the need to aggressively monitor ongoing contractor work to ensure proper performanc In response to the inspector's con'cern periodic monitoring by the licensee's quality control group of ongoing contractor work was initiate Control and quality of contract activity will be routinely verified by the inspectors during the outag Surveillance Testing The inspector observed tests to verify performance in accordance with approved procedures and LCO's, collection of valid test results, removal and restoration of equipment, and deficiency review

and resolutio .0 Review of Plant Events Failure to Perform Scram Discharge Volume Level Instrument Testing in Accordance with Technical Specifications

/ An Emergency Notification System <all was made on August 7, 198 The licensee identified that monthly surveillance testing of the

- scram discharge volume (SDV) level instruments did not fulfill NRC technical specification requirements. The technical specification definition states that instrument functional test means the s injection of a simulated signal into the instrument primary sensor s'sto verify proper instrument channel response Current licensee .

practice is to initiate this testing at the sensor output device, not the primary senso The present instruments were installed as an equipment upgrad Analog transmitter / trip unit and resistive thermal device / output relay circuits are in us Investigations are in progress to J

determine if the tests are inadequate, or if the testing required by technical specifications is not applicable to the current SDV level instrumentation. Similar problems were identified with the

Anticipated Transient Without Scram system instrumentation and were

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discussed in the Inspection report 50-293/86-2 Failure to Perform Nitrogen Make-Up Monitoring Required by Technical

Specifications An Emergsncy Notification System call was made on August 15, 198 Technical specifications require that the amount of nitrogen added to primary containment during operation be monitored to provide indication of any large increase in containment leakage. This problem was identified by the licensee's QA group. Instrumentation used to perform this monitoring had been out of service since January, 1985, and as a result the technical specification require-ments were not met.

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The 1983 NRC Systematic Assessment of Licensee Performance (SALP)

report noted that the method used to implement this requirement was ineffective. The method did not provide meaningful data because of frequent containment venting. To resolve this issue, in November 1985, the licensee submitted a request to NRR to delete the surveil-lance requirement from the technical specifications. Subsequently, the submittal was withdrawn. The licensee has now decided to keep the surveillance requirement in the technical specifications and plans to establish a primary and a backup method of deternining containment makeup prior to start-up from the current outag . Although the licensee did identify the latest problem, previous action in response to NRC criticism was ineffective. The implementation of this surveillance testing requirement will be reviewed prior to startup (86-29-01). Unsurveyed Material Released from Site On August 20, 1986, a truck containing dirt and asphalt was released from the site without a radiological survey / analysis. The truck left Boston Edison property. It returned a short time later to an area of the property previously used for disposal of similar materials. It was realized at this time that na survey had been performed and the truck was recalled. The contents were analyzed and found to contain very small amounts of contamination. The material was unloaded and remains onsite pending licensee evaluation of disposal alternative NRC inspection revealed that no procedures exist to address the pro-cess by which material may be released. Responsibilities for survey of material, documentation of results and final authority to allow

any release are not clearly defined. This lack of a formal process strongly contributed to the incident. A previous case of unsurveyed material being allowed to leave the site occurred on June 13, 198 Corrective actions in response,to that incident were narrow in scope and ineffectiv A radiologictl occurrence report (ROR) was initiated on August 21, 1986 to document the incident. Based on the radiation protection organization's incorrect assumption that the truck had not left site, this ROR was cancelled. On August 22, 1986 a contractor employee involved in the incident noted that the original ROR had been cancelled, and initiated a second ROR. This second ROR however, was not adequately investigated until September 2, 198 As a result, the potential for an unmonitored release, and the lack of a process for release of material, were not identified by the licensee's radiation protection organization until almost two weeks after the occurrence. In addition, this investigation appears to have been conducted only after repeated questioning by contractor personne . _ _ . _ . _ _ _ _ _ _ _ _ _ . _ _ _ _ . _ _ . _ _ _ _ . _ _ _ _ _ _ . _ _ _

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The lack of aggressive and thorough followup to this incident and the ineffective corrective action taken in response to a previous incident, demonstrates weakness in the area of radiation protectio The inspectors discussed these concerns with both station ar\J radiation protection management. The need_to ensure that future problems are aggressively investigatr:d was stressed. Corrective action taken by the licensee included clarification of the ROR procedure, implenentation of a material release procedure, and personnel disciplinary action. The inspectors will continue to closely evaluate licensee response to health physics related events to determine effectivenes Residual Heat Removal System Instrument Line Weld Failures On August 21, 1986 the licensee discovered a leaking weld on the one inch instrument line supplying residual heat removal (RHR), loop A, pressure switch PS-1001-74A. The cracked weld was located just downstream of the instrument line root valve and was immediately 1,olated. On August 22, 1986 a second cracked weld was identifie This second weld was on a similar one inch line supplying RHR loop A shutdown cooling flow instrumentation. On August 24, 1986 the root valve supplying the flow instrumentation was shut and tagged close Isolation of tne second failed weld resulted in loss of flow indication for the A loop. Subsequently three additional cracked i

welds were discovered, all on RHR loop A one inch instrument line One of these additional failures was not isolable from the process syste The inspector will review the licensee's final evaluation of the failures during a future inspection (86-29-02).

Repairs necessary to return' shutdown cooling flow indication were not completed until September 15, 1986. This resulted in over three weeks of operation with no direct indication of system flo During this time, the other loop of RHR was out of service for pump inspec-tions and system repairs. Licensee personnel indicated that with proper planning, the instrumentation could have been returned to service in less than a wee The inspector reviewed the licensee s actions to restore the RHR

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Operations personnel issued "B" priority maintenance requests (MR) for most of the weld failures. Although indirect indica-tions of shutdown cooling flow (i.e., moderator-temperature and RHR pump motor current) were available in the control room, the loss of direct flow neasuring ability should have been considered significant and "A" priority MR's should have been issue _

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Conflicting signals about the priority of the repairs were given to the maintenance group from the operations group, after the initial MR's were written. Also, Operations personnel were not kept informed of the progress and expected completion date of the repair There was little evidence of advance maintenance planning for the repairs. At one point, maintenance (with operation's concurrence) shifted resources from the instrument line repairs to less pressing repairs on the out of service RHR loop. At other times, the instrument repairs were given the highest priorit Following the incident, the maintenance group started issuing weekly status reports of equipment out of service. Operations personnel indicated that the reports were a useful source of information and should help communications between the two groups. In addition

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senior station management has expressed concern regarding operations and maintenance communications, and has taken steps to improve the situation. The inspectors will continue to evaluate this area during future inspection Susceptibility of SBGT System to Single Failures During review of the Standby Gas Treatment System (SBGT) system technical specifications licensee engineering personnel identified a single failure which could affect the ability of the system to per-form as designed. The two. redundant SBGT system trains are crosstied by an air operated fail-open damper. Under accident conditions, with a loss of offsite power, motive air to the crosstie damper would be unavailable. The failure of a single SBGT train charcoal bed tem-perature sensor would cause activation of the charcoal bed deluge spray system in one train, rendering it unable to remove radioactive iodine as designed. The affected train could not be isolated from the remaining train because of the failed-open crosstie dampe Approximately twenty-five percent of the system flow would be drawn through the ineffective charcoal bed and passed to the main stac This would result in elevated release levels. The charcoal bed deluge systems for bcth trains have been isolated since installation due to other design problems. However the presence of the fail-open crosstie may allow other single failures to affect both train Previously SBGT system design limitations related to the cro3stie damper were discussed in QA Deficiency Report 14G3, issued November 8, 1985. Although the deficiency report did not specifically identify single failure problems, the DR response indicated that flow through both trains was needed to meet the 4,000 cfm SBGT design flow rat In addition, the response noted that it had been routine practice to declare both SBGT system trains inoperable when maintenance on one train forced the closure of the crosstie dampe , . _ _ _ - . _ . _ . . - - . .-. . .

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On' June 2, 1986, the inspector questioned QA personnel about the susceptibility of the SBGT system to single. failures in light of DR 1463 and QA passed the question to the licensee's engineering department. However, the engineering department did not identify

, the single failure problem in response to the inspectors question or did the response to DR 1463 identify the single failure concer The identification of the single failure problem was made independently by an engineering group performing a review of the SBGT system fire protection deluge syste In response to these observations, the licensee indicated they will document answers from the engineering department to NRC inspector questions, as a management tool. The apparent design deficiency was reported via ENS on August 21, 1986. The licensee made Part 21 noti-fications on August 29, 1986. The inspector will review licensee actions during a future inspection (86-29-03). Core Spray Loop B IST and Test Line Check Valve Failures On August 26, 1986 core spray pump B failed the monthly inservice test. Rated flow could not be obtained through.the full flow test return line. The pump, motor, and pump discharge check valve were disassembled, inspected and reassembled with no significant problems identifie On September 4, 1986, during examination of the test return line check valve,. it was identified that the disc had become disassociated from the hanger arm. The valve is a forged bolted bonnet swing check valve manufactured by Velan Engineering Companies. The valve disc contains an integral disc stud which is inserted through the hanger arm. The disc is fastened to the arm by a disc nut and cotter pin arrangement. The disc stud had broken off resulting in the valve failur The disc was found in the valve body. The remaining portion of the disc stud, nut and cotter pin were not foun The licensee is evaluating possible failure mechanisms. During the recert work on the B RHR loop, the RHR pump discharge and test line check valves were inspected with no problems identified. Boston Edison has stated that core spray pump A, its associated check valves, and the A RHR loop check valves will be inspected. This will be performed in conjunction with the rebuild of A and C RHR pumps. The inspector will continue to monitor the licensee's analysis of the failure root cause and any additional corrective actions taken. (86-29-04).

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' Core Spray Valve M0-1400-4B Yoke Flaw Indication Core Spray Valves MD-1400-4B and MD-1400-4A are motor operated gate valves installed in the core spray loop B and loop A test return lines respectively. During the past several years inspections of the 4A valve have repeatedly identified looselor broken operator mounting capscrews. In response to a capscrew failure on April 26, 1986, the licensee performed a detailed design analysis. Results of this analysis, and the design changes implemented to prevent recurrence, are described in inspection report 50-293/86-14, section 4.c. One contributor to the failures was found to be excessively i high motor operator torque switch settings. Settings were reduced to values consistent with the valve applicatio Subsequent correspondence with the valve manufacturer identified that possible damage or failure of the valve yoke could result from valve cycling with excessive thrus In response to vendor recommendations the 4B valve yoke was removed and a magnetic particle examination of all accessible surfaces was performed on September 12, 1986. This examination identified one indication approximately 7/16 inch in length. The defect area was ground and blended for welding, and a weld repair implemented. Magnetic particle examination of the excavation and final weld area was performed with acceptable result The inspector will review licensee final engineering analysis and 4A valve examination ~results during a future inspection (86-29-05). Main Steam Line Low Pressure Sensor Cable Damage On September 12, 1984 the licensee discovered severe insulation damage on the cable for main steam line low pressure sensor PS-261-30 The pressure sensor provides an isolation signal to the Primary Containment Isolation System (PCIS). The damage was discovered when the cable was removed from its conduit to allow installation of new shielded cable for the ongoing Analog Trip System modifications. Several feet of outer cable insulation was brittle and cracked, with six to twelve inches completely remove Cracking of internal conductor insulation was also foun Licensee investigation revealed that-the conduit involved passed within one foot of a process steam line. The steam line insulation in this area had fallen away or been removed, subjecting this section of conduit and cable to excessive temperature The licensee review of this situation revealed no failure modes which could have contributed to the spurious PCIS group 1 isolations ex-perienced earlier in 198 The inspectors will review licensee cor-rective actions to ensure that no similar situations exist (86-29-06).

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14 Fire Within the Protected Area On September 15, 1986 at approximately 1535 hours0.0178 days <br />0.426 hours <br />0.00254 weeks <br />5.840675e-4 months <br /> a small fire within the protected area near the Bechtel warehouse was reported. The fire brigade was summoned. The source of the fire was an accumulation of cardboard and trash adjacent to the warehouse outside wal It was extinguished by security personnel in the area using hand held fire extinguishers. The cause of the fire has not been identified. No equipment was damaged, no personnel were injure .0 Observations of Physical Security Checks were made to determine whether security conditions met regulatory requirements, the physical security plan, and approved procedures. Those checks included security staffing, protected and vital area barriers, personnel identification, access control, badging, and compensatory measures when require On August 24, 1986, the licensee was informed that bombs would explode at the Pilgrim Nuclear Power Station within the next 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />. A bomb search procedure was immediately started inside the plant, and enhanced security measures were implemented. The search was completed with negative result On August 26, 1986, an anonymous allegation that bombs had been planted at Pilgrim was received. A bomb search procedure was started inside the plant, and enhanced security measures were implemented. The search was completed with negative result The FBI, the NRC Information Assessment Team, and the Commonwealth of Massachusetts were notifie .0 Radiation Protection Radiological Controls were observed on a routine basis during the report-ing period. Standard. industry radiological work practices, conformance to radiological control procedures and 10 CFR Part 20 requirements were observed. Independent surveys of radiological boundaries and random surveys of nonradiological points throughout the facility were taken by the inspecto On August 12, 1986, the inspector observed an individual preparing to

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enter a high radiation area with a drifting pocket dosimete The individual brought this to the attention of a health physics technician who directed him to enter the area with the drifting instrument. At a later time the inspector questioned the individual and learned tttt he had exchanged dosimeters with a supervisor who'was not planning to enter the area. The health physics technician present stated that this practice ,

was acceptable. The inspector considers these to be poor health physics '

practices. The above incident was discussed with health physics department management who stated that the actions taken were not in accordance with i

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department practices. The individuals involved were counseled and a station wide memorandum was issued to highlight the correct procedur .0 Review of LERs LERs submitted to NRC:RI were reviewed to verify that the details were clearly reported, including accuracy of the description of cause and adequacy of corrective action. The inspector determined whether further

, information was required from the licensee, whether generic implications were indicated, and whether the event warranted onsite followup. The following LER's were reviewed:

LER N Event Date Report Date Subject 86-17 7/1/86 7/28/86 Appendix J Related Valves 86-18 6/29/86 8/8/86- General Electric AKF Field Breaker Failed to Trip Automatically 86-19 7/15/86 8/14/86 Insufficient Monthly ATWS Surveillance Procedure LER Updates LER N Event Date Report Date Subject 86-002-01 1/16/86 8/15/86 Reactor Scram Due to Pressure Switch Sensitivity 86-016-01 6/21/86 8/25/86 Bus AS, Bus A6, and Startup Transformer Degraded Voltage Relay Calibrations Overdue 86-013-01 5/30/86 Use of Non-Seismic

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General Electric Type CFD Relays 86-015-01 6/13/86 Primary Containment Local Leak Rate Test Frequency e The following problems were identified:

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LER 86-15-01 (an update) was issued in response to the inspector's concerns about the completeness of the initial LER. The initial LER did not justify choosing the less restrictive of two surveillance interval definitions in the technical specifications for " operating cycle". A second deficiency in the LER involved the lack of description for the term " programmatic basis". This description is critical to the LER. These cor.cerns were discussed with the licensee at the conclusion of the previous resident inspection, 50-293/86-2 The update LER adequately addressed the first concern, but not the second. Specifically, the LER still does not adequately describe the licensee's previous surveillance scheduling program for local leak rate testin This description is critical to the LER's central theme, that the regulatory requirements of 10 CFR 50 Appendix J are inconsistent with the technical specification requirements and that the licensee's scheduling method is consistent with the technical specifications. The licensee agreed to review the LER and appropriately update i On September 2,1986, the inspector questioned the reportability of ninteen degraded fire penetration seals listed in Failure and Malfunction Report No.164. The Failure and Malfunction report had been initiated two months earlier, on July 8,1986. At the end of the inspection period, the licensee had not determined whether the barriers were reportable. This item is unresolved, pending the completion of the licensee's evaluation (86-29-07).

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The inspector noted that LER's 86-16-01, 86-17-00, and 86-20-00 did not have report dates entered on the LER forms. Also, LER 86-17-00 did not have a licensee contact listed in the LER. This information is required to be submitted to the NRC. The licensee indicated that the LER's will be reviewed and appropriately update .0 Management Meetings On September 9, 1986, a meeting between Region I and Boston Edison senior management was conducted at Boston Edison's Chiltonville Training Facilit The purpose of the meeting was to discuss licensee management program im-provements. The meeting is summarized in NRC Inspection Report 50-293/86-3 At periodic intervals during the course of the inspection period, meetings were held with senior facility management to discuss the inspection scope and preliminary findings of the resident inspector. No written material was given to the licensee that was not previously available to the publi ._ .. -. _

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i Attachment I to Inspection Report- 50-293/86-29 Persons Contacted i

L. Oxsen, Vice President, Nuclear Operations e *A. Pederson, Nuclear Operations Manager

• K. Roberts, Director Outage Management D. Swanson, Nuclear Engineering Department Manager N. Brosee, Maintenance Section Head T. Sowdon, Radiological Section Head J. Seery, Technical Section Head E. Ziemianski, Management Services Section Head

, P. Mastrangelo, Chief Operating Engineer B. Eldridge, Acting Chief Radiological Engineer R. Sherry, Chief Mair.tenance Engineer J. McEachern, Resource Protection and Control Group Leader E. Graham, Compliarce and Administrative Group Leader

• Senior Licensee representative present at the exit meetin _

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